Table of Contents
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. #1)
x
Annual
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
For the fiscal year ended
December 31,
2009
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)
Registrants
telephone number, including area code:
(303) 999- 4400
Securities registered
pursuant to Section 12(b) of the Act:
Title
of each class
|
|
Name
of each exchange on which registered
|
Class A Common Stock, $0.01 par value
|
|
New York Stock Exchange
|
(including associated stock purchase rights)
|
|
|
Securities
registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if
the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. YES
x
NO
o
Indicate by check mark if
the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of
the Act. YES
o
NO
x
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 if
disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
o
Indicate by check mark
whether the registrant is a large accelerated filer, an accelerated filer, or a
non-accelerated filer, or a smaller reporting company. See definition of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2
of the Exchange Act. (Check one):
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 June 30, 2009,
the aggregate market value of the voting and non-voting common stock held by
non-affiliates was $684,959,425. As of February 1, 2010, the registrant
had 50,952,786 shares of Class A Common Stock outstanding. The registrant
also had 1,797,784 shares of Class B Stock outstanding on February 1,
2010 all of which are held by an affiliate of the registrant.
Table of Contents
EXPLANATORY NOTE
Berry
Petroleum Company (the Registrant) is filing this Amendment No. 1 (this Amendment)
to its Annual Report on Form 10-K for the fiscal year ended December 31,
2009 (the Form 10-K). The sole
purpose of this Amendment No. 1 is to amend Item 8 of the Form 10-K
to correct the presentation error in the Statement of Comprehensive Income (Loss)
for the year ended December 31, 2009 and the related disclosures in Note 3
to the audited financial statements.
Comprehensive income (loss) in the Form 10-K reflected a net gain
from the change in fair value of derivatives of $174.1 million, which should
have been reflected as a net loss. The unrealized gains (losses) on
derivatives, net of income tax, has been revised from a gain of $205.3 million
to a loss of $129.3 million. The
reclassification of realized (gains) losses on derivatives included in net
income, net of taxes, has been revised from a gain of $31.2 million to a gain
of $44.8 million. Accordingly, this Amendment reflects comprehensive loss of
approximately $120.0 million, rather than comprehensive income of $228.1
million reflected in the Form 10-K. These corrections were also included
in the Companys Form 10-Q for the period ended June 30, 2010 filed August 9,
2010. Except to correct Item 8 of the Form 10-K
as described above, no other items or disclosures in the Form 10-K have
been amended, and all other information included in the Form 10-K remains
unchanged. This Amendment does not
reflect events occurring after the filing of the Form 10-K or modify,
amend or update any items or disclosures therein in any way other than as
required to reflect the changes identified above.
3
Table of Contents
Item 8. Financial Statements and Supplementary Data
Financial statement
schedules have been omitted since they are either not required, are not
applicable, or the required information is shown in the financial statements
and related notes.
4
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To the Board of Directors
and Shareholders of Berry Petroleum Company:
In our opinion, the
financial statements listed in the accompanying index present fairly, in all
material respects, the financial position of Berry Petroleum Company at
December 31, 2009 and 2008, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2009 in
conformity with accounting principles generally accepted in the United States
of America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2009, based on criteria established in
Internal
Control - Integrated Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Companys management is
responsible for these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in Managements Report on
Internal Control over Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial statements and on the
Companys internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about
whether the financial statements are free of material misstatement and whether
effective internal control over financial reporting was maintained in all
material respects. Our audits of the financial statements included examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a
reasonable basis for our opinions.
As discussed in Note 2 to
the financial statements, the Company changed the manner in which it accounts
for recurring fair value measurements of financial instruments in 2008. As
discussed in Note 9 to the financial statements, the Company changed the manner
in which it accounts for earnings per share in 2009.
A companys internal control
over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally
accepted accounting principles. A companys internal control over financial
reporting includes those policies and procedures that (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the companys assets that could have a material effect on the financial
statements.
Because of its inherent
limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
Denver, Colorado
February 25, 2010,
except for the effects of the matter discussed in Note
17, as to which the date is August 11, 2010
5
Table of
Contents
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2009 and 2008
(In Thousands, Except Share Information)
|
|
2009
|
|
2008
|
|
ASSETS
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
5,311
|
|
$
|
240
|
|
Short-term
investments
|
|
66
|
|
66
|
|
Accounts
receivable, net of allowance for doubtful accounts of $38,508 and $38,511,
respectively
|
|
74,337
|
|
65,873
|
|
Deferred
income taxes
|
|
5,623
|
|
|
|
Fair
value of derivatives
|
|
11,527
|
|
111,886
|
|
Prepaid
expenses and other
|
|
6,612
|
|
11,015
|
|
Total
current assets
|
|
103,476
|
|
189,080
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment, net
|
|
2,106,385
|
|
2,254,425
|
|
Fair
value of derivatives
|
|
735
|
|
79,696
|
|
Other
assets
|
|
29,539
|
|
19,182
|
|
|
|
$
|
2,240,135
|
|
$
|
2,542,383
|
|
LIABILITIES
AND SHAREHOLDERS EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts
payable
|
|
$
|
63,096
|
|
$
|
119,221
|
|
Revenue
and royalties payable
|
|
25,878
|
|
34,416
|
|
Accrued
liabilities
|
|
29,320
|
|
34,566
|
|
Line
of credit
|
|
|
|
25,300
|
|
Income
taxes payable
|
|
|
|
187
|
|
Fair
value of derivatives
|
|
33,843
|
|
1,445
|
|
Deferred
income taxes
|
|
|
|
45,490
|
|
Total
current liabilities
|
|
152,137
|
|
260,625
|
|
Long-term
liabilities:
|
|
|
|
|
|
Deferred
income taxes
|
|
237,161
|
|
270,323
|
|
Senior
secured revolving credit facility
|
|
372,000
|
|
931,800
|
|
8¼%
Senior subordinated notes due 2016
|
|
200,000
|
|
200,000
|
|
10¼%
Senior notes due 2014, net of unamortized discount of $13,456 and $0,
respectively
|
|
436,544
|
|
|
|
Asset
retirement obligation
|
|
43,487
|
|
41,967
|
|
Other
long-term liabilities
|
|
19,711
|
|
5,921
|
|
Fair
value of derivatives
|
|
75,836
|
|
4,203
|
|
|
|
1,384,739
|
|
1,454,214
|
|
Commitments
and contingencies (Note 13)
|
|
|
|
|
|
Shareholders
equity:
|
|
|
|
|
|
Preferred
stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding
|
|
|
|
|
|
Capital
stock, $0.01 par value:
|
|
|
|
|
|
Class A
Common Stock, 100,000,000 shares authorized; 42,952,499 shares issued and
outstanding (42,782,365 in 2008)
|
|
430
|
|
427
|
|
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
|
|
89,068
|
|
79,653
|
|
Accumulated
other comprehensive (loss) income
|
|
(60,372
|
)
|
113,697
|
|
Retained
earnings
|
|
674,115
|
|
633,749
|
|
Total
shareholders equity
|
|
703,259
|
|
827,544
|
|
|
|
$
|
2,240,135
|
|
$
|
2,542,383
|
|
The
accompanying notes are an integral part of these financial statements.
6
Table of Contents
BERRY PETROLEUM COMPANY
Statements of Income
Years ended December 31, 2009, 2008 and 2007
(In Thousands, Except Per Share Data)
|
|
2009
|
|
2008
|
|
2007
|
|
REVENUES
|
|
|
|
|
|
|
|
Sales
of oil and gas
|
|
$
|
506,691
|
|
$
|
649,248
|
|
$
|
433,208
|
|
Sales
of electricity
|
|
36,065
|
|
63,525
|
|
55,619
|
|
Gas
marketing
|
|
22,806
|
|
35,750
|
|
|
|
Gain
(loss) on derivatives
|
|
6,514
|
|
(213
|
)
|
13
|
|
Gain
(loss) on sale of assets
|
|
826
|
|
(1,297
|
)
|
54,173
|
|
Interest
and other income, net
|
|
1,810
|
|
3,504
|
|
4,414
|
|
|
|
574,712
|
|
750,517
|
|
547,427
|
|
EXPENSES
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
156,612
|
|
188,758
|
|
130,940
|
|
Operating
costs - electricity generation
|
|
31,400
|
|
54,891
|
|
45,980
|
|
Production
taxes
|
|
18,144
|
|
26,876
|
|
14,651
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
139,919
|
|
125,595
|
|
82,861
|
|
Depreciation,
depletion & amortization electricity generation
|
|
3,681
|
|
2,812
|
|
3,568
|
|
Gas
marketing
|
|
21,231
|
|
32,072
|
|
|
|
General
and administrative
|
|
49,237
|
|
54,279
|
|
39,663
|
|
Interest
|
|
49,923
|
|
23,942
|
|
15,069
|
|
Extinguishment
of debt
|
|
10,823
|
|
|
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
5,425
|
|
10,543
|
|
8,351
|
|
Bad
debt expense
|
|
|
|
38,665
|
|
|
|
|
|
486,395
|
|
558,433
|
|
341,083
|
|
Income
before income taxes
|
|
88,317
|
|
192,084
|
|
206,344
|
|
Provision
for income taxes
|
|
28,349
|
|
70,308
|
|
79,060
|
|
Income
from continuing operations
|
|
59,968
|
|
121,776
|
|
127,284
|
|
(Loss)
income from discontinued operations, net of tax
|
|
(5,938
|
)
|
11,753
|
|
2,644
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
54,030
|
|
$
|
133,529
|
|
$
|
129,928
|
|
|
|
|
|
|
|
|
|
Basic
net income from continuing operations per share
|
|
1.31
|
|
2.70
|
|
2.85
|
|
Basic
net (loss) income from discontinued operations per share
|
|
(0.13
|
)
|
0.26
|
|
0.06
|
|
Basic
net income per share
|
|
$
|
1.18
|
|
$
|
2.96
|
|
$
|
2.91
|
|
|
|
|
|
|
|
|
|
Diluted
net income from continuing operations per share
|
|
1.30
|
|
2.66
|
|
2.81
|
|
Diluted
net (loss) income from discontinued operations per share
|
|
(0.13
|
)
|
0.26
|
|
0.06
|
|
Diluted
net income per share
|
|
$
|
1.17
|
|
$
|
2.92
|
|
$
|
2.87
|
|
Statements of Comprehensive Income (Loss)
Years Ended December 31, 2009, 2008 and 2007
(In Thousands)
Net
income
|
|
$
|
54,030
|
|
$
|
133,529
|
|
$
|
129,928
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($79,240), $96,546, and
($66,627), respectively
|
|
(129,287
|
)
|
157,522
|
|
(99,941
|
)
|
Reclassification
of realized (gains) losses on derivatives included in net income, net of
income taxes of ($27,447), $47,119 and ($524), respectively
|
|
(44,782
|
)
|
76,879
|
|
(786
|
)
|
Comprehensive
income (loss)
|
|
$
|
(120,039
|
)
|
$
|
367,930
|
|
$
|
29,201
|
|
The
accompanying notes are an integral part of these financial statements.
7
Table of Contents
BERRY PETROLEUM COMPANY
Statements of Shareholders Equity
Years Ended December 31, 2009, 2008 and 2007
(In Thousands, Except Per Share Data)
|
|
Class
A
|
|
Class
B
|
|
Capital
in
Excess of Par
Value
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Shareholders
Equity
|
|
Balances
at January 1, 2007
|
|
$
|
421
|
|
$
|
18
|
|
$
|
50,166
|
|
$
|
397,072
|
|
$
|
(19,977
|
)
|
$
|
427,700
|
|
Stock-based
compensation (484,451 shares)
|
|
4
|
|
|
|
12,930
|
|
|
|
|
|
12,934
|
|
Tax
impact of stock option exercises
|
|
|
|
|
|
3,049
|
|
|
|
|
|
3,049
|
|
Deferred
director fees - stock compensation
|
|
|
|
|
|
445
|
|
|
|
|
|
445
|
|
Cash
dividends declared - $0.30 per share, including RSU dividend equivalents
|
|
|
|
|
|
|
|
(13,292
|
)
|
|
|
(13,292
|
)
|
Adoption
of authoritative accounting guidance regarding uncertainty in income taxes
|
|
|
|
|
|
|
|
(63
|
)
|
|
|
(63
|
)
|
Change
in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
(100,727
|
)
|
(100,727
|
)
|
Net
income
|
|
|
|
|
|
|
|
129,928
|
|
|
|
129,928
|
|
Balances
at December 31, 2007
|
|
425
|
|
18
|
|
66,590
|
|
513,645
|
|
(120,704
|
)
|
459,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation (199,363 shares)
|
|
2
|
|
|
|
11,684
|
|
|
|
|
|
11,686
|
|
Tax
impact of stock option exercise
|
|
|
|
|
|
938
|
|
|
|
|
|
938
|
|
Deferred
director fees stock compensation
|
|
|
|
|
|
441
|
|
|
|
|
|
441
|
|
Cash
dividends declared - $0.30 per share, including RSU dividend equivalents
|
|
|
|
|
|
|
|
(13,425
|
)
|
|
|
(13,425
|
)
|
Change
in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
234,401
|
|
234,401
|
|
Net
income
|
|
|
|
|
|
|
|
133,529
|
|
|
|
133,529
|
|
Balances
at December 31, 2008
|
|
427
|
|
18
|
|
79,653
|
|
633,749
|
|
113,697
|
|
827,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation (170,134 shares)
|
|
3
|
|
|
|
6,750
|
|
|
|
|
|
6,753
|
|
Tax
impact of stock option exercises
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
(98
|
)
|
Deferred
director fees - stock compensation
|
|
|
|
|
|
2,763
|
|
|
|
|
|
2,763
|
|
Cash
dividends declared - $0.30 per share, including RSU dividend equivalents
|
|
|
|
|
|
|
|
(13,664
|
)
|
|
|
(13,664
|
)
|
Change
in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
(174,069
|
)
|
(174,069
|
)
|
Net
income
|
|
|
|
|
|
|
|
54,030
|
|
|
|
54,030
|
|
Balances
at December 31, 2009
|
|
$
|
430
|
|
$
|
18
|
|
$
|
89,068
|
|
$
|
674,115
|
|
$
|
(60,372
|
)
|
$
|
703,259
|
|
The
accompanying notes are an integral part of these financial statements.
8
Table of Contents
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2009, 2008 and 2007
(In Thousands)
|
|
2009
|
|
2008
|
|
2007
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
54,030
|
|
$
|
133,529
|
|
$
|
129,928
|
|
Depreciation,
depletion and amortization
|
|
145,788
|
|
141,049
|
|
97,259
|
|
Extinguishment
of debt
|
|
10,823
|
|
|
|
|
|
Amortization
of debt issuance costs and net discount
|
|
6,827
|
|
1,774
|
|
774
|
|
Dry
hole and impairment
|
|
14,859
|
|
9,932
|
|
12,951
|
|
Commodity
derivatives
|
|
247
|
|
(108
|
)
|
574
|
|
Stock-based
compensation expense
|
|
8,626
|
|
9,313
|
|
8,200
|
|
Deferred
income taxes
|
|
19,998
|
|
67,982
|
|
62,465
|
|
Loss
(gain) on sale of asset
|
|
79
|
|
1,297
|
|
(54,173
|
)
|
Other,
net
|
|
(4,016
|
)
|
(2,530
|
)
|
2,787
|
|
Cash
paid for abandonment
|
|
(1,030
|
)
|
(4,607
|
)
|
(1,188
|
)
|
Allowance
for bad debt
|
|
|
|
38,511
|
|
|
|
Change
in book overdraft
|
|
(16,018
|
)
|
23,984
|
|
(9,400
|
)
|
(Increase)
decrease in current assets other than cash, cash equivalents
and short-term investments
|
|
(10,055
|
)
|
10,281
|
|
(47,876
|
)
|
(Decrease)
increase in current liabilities other than line of credit
|
|
(17,582
|
)
|
(20,838
|
)
|
36,578
|
|
Net
cash provided by operating activities
|
|
212,576
|
|
409,569
|
|
238,879
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
(134,946
|
)
|
(397,601
|
)
|
(285,267
|
)
|
Property
acquisitions
|
|
(13,497
|
)
|
(667,996
|
)
|
(56,247
|
)
|
Capitalized
interest
|
|
(30,107
|
)
|
(23,209
|
)
|
(18,104
|
)
|
Proceeds
from sale of assets
|
|
139,796
|
|
2,037
|
|
72,405
|
|
Net
cash used in investing activities
|
|
(38,754
|
)
|
(1,086,769
|
)
|
(287,213
|
)
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
Proceeds
from issuances on line of credit
|
|
387,700
|
|
404,000
|
|
395,150
|
|
Payments
on line of credit
|
|
(413,000
|
)
|
(393,000
|
)
|
(396,850
|
)
|
Proceeds
from issuance of long-term debt
|
|
1,090,262
|
|
1,708,700
|
|
229,300
|
|
Payments
on long-term debt
|
|
(1,215,100
|
)
|
(1,021,900
|
)
|
(174,300
|
)
|
Debt
issuance costs
|
|
(23,955
|
)
|
(11,002
|
)
|
(1
|
)
|
Financing
obligation
|
|
18,214
|
|
|
|
|
|
Dividends
paid
|
|
(13,664
|
)
|
(13,425
|
)
|
(13,292
|
)
|
Proceeds
from stock option exercises
|
|
890
|
|
2,813
|
|
5,178
|
|
Excess
tax (expense) benefit
|
|
(98
|
)
|
938
|
|
3,049
|
|
Net
cash (used in) provided by financing activities
|
|
(168,751
|
)
|
677,124
|
|
48,234
|
|
Net
increase (decrease) in cash and cash equivalents
|
|
5,071
|
|
(76
|
)
|
(100
|
)
|
Cash
and cash equivalents at beginning of year
|
|
240
|
|
316
|
|
416
|
|
Cash
and cash equivalents at end of year
|
|
$
|
5,311
|
|
$
|
240
|
|
$
|
316
|
|
Supplemental
disclosures of cash flow information:
|
|
|
|
|
|
|
|
Interest
paid, net of capitalized interest
|
|
$
|
36,854
|
|
$
|
15,708
|
|
$
|
15,841
|
|
Income
taxes paid
|
|
$
|
8,769
|
|
$
|
13,290
|
|
$
|
6,715
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
(Decrease)
increase in fair value of derivatives:
|
|
|
|
|
|
|
|
Current
(net of income taxes of ($49,914), $75,772, and ($36,562), respectively)
|
|
$
|
(81,439
|
)
|
$
|
123,628
|
|
$
|
(54,844
|
)
|
Non-current
(net of income taxes of ($56,773), $67,893, and ($30,589), respectively)
|
|
(92,630
|
)
|
110,773
|
|
(45,883
|
)
|
Net
(decrease) increase to accumulated other comprehensive (loss) income
|
|
$
|
(174,069
|
)
|
$
|
234,401
|
|
$
|
(100,727
|
)
|
The
accompanying notes are an integral part of these financial statements.
9
Table of
Contents
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
1.
Summary of Significant Accounting Policies
Description of the business
Berry Petroleum Company (the
Company) is an independent energy company engaged in the production,
development, acquisition, exploitation and exploration of crude oil and natural
gas. The Company has invested in cogeneration facilities which provide steam
required for the extraction of heavy oil and which generates electricity for
sale.
Basis of presentation
The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States of America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of the date of the financial statements
and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Reclassifications
and error corrections
Included
in the fourth quarter of 2009 are adjustments to correct the prior accounting
for the Companys royalties in the amount of $3.3 million, which resulted in
decreasing its sales of oil and gas and increasing its royalties payable. The year- to-date impact of the adjustment
was $1.9 million. Management concluded
the impact was immaterial to the current and prior periods.
In
March 2008, the Company determined there was an error in computing
royalties payable in prior years, accumulating to $10.5 million as of December 31,
2007. The Company 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 sales of oil and gas by $10.5 million and reducing royalties
payable.
Cash and cash equivalents
The Company considers all
highly liquid investments purchased with a remaining maturity of three months
or less to be cash equivalents. The Companys cash management process provides
for the daily funding of checks as they are presented to the bank. Included in
accounts payable at December 31, 2009 and 2008 is $15.7 million and $31.8
million, respectively, representing outstanding checks in excess of the bank
balance (book overdraft).
Accounts receivable
Trade accounts receivable consist mainly of
receivables from oil and gas purchases and joint interest owners on properties
the Company operates. For receivables
from joint interest owners, the Company typically has the ability to withhold
future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and gas receivables are
collected within two months.
Allowance for doubtful accounts
The Company routinely assesses the recoverability of
all material trade and other receivables to determine collectability. As of both December 31, 2009 and 2008,
the Company has an allowance for doubtful accounts of $38.5 million. The 2008 amount represents the Companys November and
December 2008 sales to BWOC. The
Company had a long-term contract to sell all of its heavy crude oil in
California for approximately $8.10 below WTI with BWOC. On December 22, 2008, Flying J, Inc.
and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary
BWOC each 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 Companys
production. On March 17, 2009, the
Company entered into a stipulation with BWOC, terminating the contract
effective as of March 16, 2009. The
Company recorded $38.5 million of bad debt expense in 2008 for the bankruptcy
of BWOC. Of that $38.5 million due from
BWOC, $11.8 million represents 20 days of December 2008 crude oil sales
and an administrative claim under the bankruptcy proceedings and $26.7 million
represents November and the balance of December 2008 crude oil sales
which would have the same priority as other general unsecured claims. BWOC will also be liable to the Company for
damages under this contract. While the
Company also has guarantees from Big West Oil and from Flying J, Inc. in
the amount of $75 million each, the information received from the bankruptcy
proceedings to date has not provided the Company with adequate data from which
to make a conclusion that any amounts will be collected. The Company has entered into various
agreements with other companies to sell its California oil production.
10
Table of Contents
Discontinued operations
In 2009, the Company sold
its DJ Basin assets, the results of operations of which, are reported as
discontinued operations in the Statement of Income.
Income taxes and uncertain
tax positions
Income taxes are provided
based on earnings reported for tax return purposes in addition to a provision
for deferred income taxes. Deferred
income taxes are accounted for using the asset and liability method, which
results in the recognition of deferred income taxes on the difference between
the tax basis of an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively. A valuation allowance is recognized if it is determined that
deferred tax assets may not be fully utilized in future periods. Income tax positions must meet a
more-likely-than-not recognition threshold to be recognized, and any potential
accrued interest and penalties related to the unrecognized tax benefits are
recognized within income tax expense.
Uncertain tax positions are recognized in the Balance Sheet as a current
or noncurrent liability, based upon the expected timing of the payment to a
taxing authority.
Derivatives
The Company periodically enters into commodity
derivative contracts to manage its exposure to oil and natural gas price
volatility. The Company also enters into
derivative contracts to mitigate the risk of interest rate fluctuations. The accounting treatment for the changes in
fair value of a derivative instrument is dependent upon whether or not a
derivative instrument is a cash flow hedge or a fair value hedge, and upon
whether or not the derivative is designated as a hedge. Changes in fair value of a derivative
designated as a cash flow hedge are recognized, to the extent the hedge is
effective, in other comprehensive income until the hedged item is recognized in
earnings. Changes in the fair value of a
derivative instrument designated as a fair value hedge, to the extent the hedge
is effective, has no effect on the statement of income because changes in fair
value of the derivative offsets changes in the fair value of the hedged
item. Where hedge accounting is not
elected or if a derivative instrument does not qualify as either a fair value
hedge or a cash flow hedge, changes in fair value are recognized in
earnings. Hedge effectiveness is
assessed at least quarterly based on total changes in the derivatives fair
value. Any ineffective portion of the derivative instruments change in fair
value is recognized immediately in earnings.
The estimated fair value of derivative instruments requires substantial
judgment. These values are based upon,
among other things,
whether or not the forecasted hedged transaction
will occur, option pricing models,
futures prices, volatility, time to maturity and credit risk. The values the Company reports in its
financial statements changes as these estimates are revised to reflect actual
results, changes in market conditions or other factors, many of which are
beyond its control.
Prior
to January 1, 2010, the Company designated most of its commodity and
interest rate derivative contracts as cash flow hedges, whose unrealized fair
value gains and losses were recorded to Accumulated other comprehensive loss
(AOCL). Effective January 1, 2010,
the Company has elected to de-designate all of its commodity and interest rate
contracts that had previously been designated as cash flow hedges as of December 31,
2009 and have elected to discontinue hedge accounting prospectively.
As
a result, subsequent to December 31, 2009, the Company will recognize all
gains and losses from prospective changes in commodity and interest rate
derivative fair values immediately in earnings rather than deferring any such
amounts in AOCL. At December 31,
2009, AOCL consisted of $97 million ($60 million after tax) of unrealized
losses, representing the mark-to-market value of the Companys cash flow hedges
as of the balance sheet date, less any ineffectiveness
recognized. As a result of discontinuing hedge accounting on January 1,
2010, such mark-to-market values at December 31, 2009 are frozen in AOCL
as of the de-designation date and will be reclassified into earnings in future
periods as the original hedged transactions affect earnings. The
Company expects to reclassify into earnings from AOCL the frozen value related
to de-designated commodity hedges during the next three years.
Oil and gas properties, buildings and equipment
The Company accounts for its
oil and gas exploration and development costs using the successful efforts
method. Geological and geophysical costs and the costs of carrying and
retaining undeveloped properties are expensed as incurred. Exploratory well
costs are capitalized pending further evaluation of whether economically
recoverable reserves have been found. If economically recoverable reserves are
not found, exploratory well costs are expensed as dry holes. All exploratory
wells are evaluated for economic viability within one year of well completion and
the related capitalized costs are reviewed quarterly. Exploratory wells that
discover potentially economic reserves in areas where a major capital
expenditure would be required before production could begin, and where the
economic viability of that major capital expenditure depends upon the
successful completion of further exploratory work in the area, remain
capitalized if the well found a sufficient quantity of reserves to justify its
completion as a producing well and the Company is making sufficient progress
assessing the reserves and the economic and operating viability of the project.
The costs of development wells are capitalized whether productive or
nonproductive.
11
Table of Contents
Depletion of oil and gas
producing properties is computed using the units-of-production method.
Depreciation of lease and well equipment, including cogeneration facilities and
other steam generation equipment and facilities, is computed using the
units-of-production method or on a straight-line basis over estimated useful
lives ranging from 10 to 20 years. Buildings and equipment are recorded at
cost. Depreciation is provided on a straight-line basis over estimated useful
lives ranging from 5 to 30 years for buildings and improvements and 3 to 10
years for machinery and equipment. Estimated residual salvage value is
considered when determining depreciation, depletion and amortization (DD&A)
rates. Changes in reserves are applied
on a prospective basis.
Interest incurred on funds
borrowed to finance exploration and certain acquisition and development
activities is capitalized. To qualify for interest capitalization, the costs
incurred must relate to the acquisition of unproved reserves, drilling of wells
to prove up the reserves and the installation of the necessary pipelines and
facilities to make the property ready for production. Such capitalized interest
is included in oil and gas properties, buildings and equipment. Capitalized
interest is added into the depreciable base of the assets and is expensed on a
units-of-production basis over the life of the respective project.
In accordance with
authoritative guidance, the Company groups assets at the field level and
periodically reviews the carrying value of its property and equipment to test
whether current events or circumstances indicate such carrying value may not be
recoverable. If the tests indicate that the carrying value of the asset is greater
than the estimated future undiscounted cash flows to be generated by such
asset, then an impairment adjustment needs to be recognized. Such adjustment
consists of the amount by which the carrying value of such asset exceeds its
fair value. The Company generally measures fair value by considering sale
prices for similar assets or by discounting estimated future cash flows from
such asset using an appropriate discount rate. Considerable management judgment
is necessary to estimate the fair value of assets, and accordingly, actual
results could vary significantly from such estimates. When assets are sold, the
applicable costs and accumulated depreciation and depletion are removed from
the accounts and any gain or loss is included in income. Expenditures for
maintenance and repairs are expensed as incurred.
Asset retirement
obligations
Asset retirement obligations
(ARO) relate to future costs associated with plugging and abandonment of oil
and gas wells, removal of equipments and facilities from leased acreage and
returning such land to its original condition.
The fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred (typically when the asset is
installed at the production location), and the cost of such liability increases
the carrying amount of the related long-lived asset by the same
amount. The liability is accreted each period through charges to
depreciation, depletion and amortization expense, and the capitalized cost is
depleted on a units-of-production basis over the proved developed reserves of
the related asset. Revisions to estimated retirement obligations
result in adjustments to the related capitalized asset and corresponding
liability.
Accrued liabilities
Accrued liabilities consist
primarily of accrued property taxes, accrued interest and accrued payroll
costs. Accrued property taxes were $8.3
million and $13.5 million as of December 31, 2009 and 2008,
respectively. Accrued interest was $6.9
million and $8.4 million as of December 31, 2009 and 2008,
respectively. Accrued payroll costs were
$8.2 million and $8.4 million as of December 31, 2009 and 2008,
respectively.
Revenue recognition
Revenues
associated with sales of crude oil, natural gas, electricity and natural gas
marketing are recognized when delivery has occurred and title has transferred,
and if the collectability of the revenue is probable. The electricity and
natural gas the Company produces and uses in its operations are not included in
revenues. Revenues from crude oil and natural gas production from properties in
which the Company has an interest with other producers are recognized on the
basis of its net working interest (entitlement method). Revenues are
derived from gas marketing sales which represent excess capacity on the Rockies
Express pipeline which the Company uses to market natural gas for its working
interest partners.
Electricity cost
allocation
The Company
owns three
cogeneration facilities. Its investment in cogeneration facilities has
been for the express purpose of lowering steam costs in its heavy oil
operations and securing operating control of the respective steam
generation. Cogeneration, also called combined heat and power (CHP),
extracts energy from the exhaust of a turbine that would otherwise be wasted,
to produce steam. Such cogeneration operations produce electricity and steam.
The Company allocates steam costs to its oil and gas operating costs based on
the conversion efficiency of the cogeneration facilities plus certain direct
costs in producing steam. Electricity revenue represents sales to the
utilities. Electricity used in oil and gas operations is allocated at cost. A
portion of the capital costs of the cogeneration facilities is allocated to
DD&A-oil and gas production.
12
Table of Contents
Electricity
consumption included in oil and gas operating costs for the years ended December 31,
2009, 2008 and 2007 was $2.8 million, $5.8 million and $5.0 million,
respectively.
Transportation costs
Transportation costs,
consisting primarily of natural gas transportation costs, are included in
either Operating costs - oil and gas production or Operating costs -
electricity generation, as applicable. Natural gas transportation costs
included in Operating costs - oil and gas production were $15.2 million, $9.5
million and $1.2 million for 2009, 2008 and 2007, respectively. Natural gas transportation costs included in
Operating costs - electricity generation were $2.8 million, $7.2 million and
$6.7 million for 2009, 2008 and 2007, respectively. Additionally, the
transportation costs in Uinta were $0.2 million, $0.2 million and $1.4 million
in 2009, 2008 and 2007, respectively.
Stock-based compensation
The Company recognizes the
grant date fair value of stock options and other stock based compensation
issued in the statement of income.
Expense is recognized on a straight-line basis over the employees
requisite service period (generally the vesting period of the award).
Earnings (loss) per share
Basic earnings (loss) per
share is computed by dividing net earnings (loss) attributable to common stock
by the weighted average number of common shares outstanding during each period. Under the treasury stock method, diluted
earnings (loss) per share is computed by dividing net earnings (loss) adjusted
for the effects of potential common shares.
Related party transactions
In December 2007, the
Company accepted a tender issued by Bakersfield Fuel & Oil Company
(BFO) to purchase all of its shares in BFO for $2.9 million. These proceeds are
reflected in the Proceeds from sale of assets line on the Statements of Cash
Flows and in the Gain on sale of assets line on the Statements of Income. Mr. Thomas
Jamieson is a Director of Berry Petroleum Company and a director and the
controlling stockholder of BFO. The tender was made to all shareholders of BFO
other than Mr. Jamieson and his affiliates. The Corporate Governance and
Nominating Committee, with input from the Audit Committee, approved this
transaction.
Equity method investments
The Company owns interests
in two entities which serve to gather and transport natural gas in the Companys
Lake Canyon and Brundage Canyon fields. The Company owns less than
50% interest in both entities and these interests are accounted for using the
equity method. The Companys net
investment in these entities is included under the caption Other assets on
its Balance Sheet.
Impact of recently issued
accounting standard updates
In January 2010, the
FASB issued Accounting Standards Update (ASU) No. 2010-06
Improving Disclosures about Fair Value Measurements.
The ASU amends previously issued
authoritative guidance and requires new disclosures and clarifies existing
disclosures and is effective for interim and annual reporting periods beginning
after December 15, 2009, except for the disclosures about purchases,
sales, issuances, and settlements in the rollforward activity in Level 3 fair
value measurements. Those disclosures
are effective for fiscal years beginning after December 15, 2010 and for
interim periods within those fiscal years.
As this requires only additional disclosures, the guidance will have no
impact on the Companys financial position or results of operations.
2.
Fair Value Measurement
In
September 2006, authoritative guidance
was
issued that defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements. The Company adopted
this guidance as of January 1, 2008 for all financial and nonfinancial
assets and liabilities recognized or disclosed at fair value on a recurring
basis. The Company has also adopted the
authoritative guidance as it relates to all nonfinancial assets and liabilities
that are not recognized or disclosed on a recurring basis as of January 1,
2009 pursuant to the authoritative guidance issued by the FASB in February 2008. The adoption of the authoritative guidance
did not have a material impact on the financial statements for the years ended December 31,
2009 or 2008.
13
Table of Contents
The
authoritative guidance establishes a three-tier fair value hierarchy, which
prioritizes the inputs used to measure fair value. These tiers include:
Level 1, defined as unadjusted quoted prices in active markets for
identical assets or liabilities; Level 2, defined as inputs other than
quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs for use when
little or no market data exists, therefore requiring an entity to develop its
own assumptions.
A
financial instruments categorization within the fair value hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Companys assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect
the classification of assets and liabilities within the fair value
hierarchy. Oil swaps, natural gas swaps and interest rate swaps are
valued using internal models which are based on active market data and are
classified within Level 2 of the valuation hierarchy. 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. The Company determines the value of option
contracts utilizing industry-standard option pricing models based on inputs
that are either readily available in public markets, can be derived from
information available in publicly quoted markets, or are quoted by financial
institutions that trade these contracts. In situations where the Company
obtains inputs via quotes from financial institutions, it verifies the
reasonableness of these quotes via similar quotes from another financial
institution as of each date for which financial statements are prepared. The
Company also considers counterparty credit risk and its own credit risk in its
determination of all estimated fair values. The Company has consistently
applied these valuation techniques in all periods presented and believes it has
obtained the most accurate information available for the types of derivative
contracts it holds. Level 3 derivatives
include oil collars, natural gas collars and natural gas basis swaps.
The
following tables set forth by level within the fair value hierarchy the Companys
assets and liabilities that were measured at fair value on a recurring basis as
of December 31, 2009 and 2008.
Assets and liabilities measured at fair
value on a recurring basis
December 31,
2009 (in
millions)
|
|
Total carrying value on the
Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivative
liability
|
|
$
|
(88.5
|
)
|
$
|
(62.5
|
)
|
$
|
(26.0
|
)
|
Interest rate swaps liability
|
|
(8.9
|
)
|
(8.9
|
)
|
|
|
Total liabilities at
fair value
|
|
$
|
(97.4
|
)
|
$
|
(71.4
|
)
|
$
|
(26.0
|
)
|
December 31,
2008 (in
millions)
|
|
Total carrying value on the
Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivative
asset
|
|
198.4
|
|
25.9
|
|
172.5
|
|
Interest rate swaps liability
|
|
(12.5
|
)
|
(12.5
|
)
|
|
|
Total assets at fair
value
|
|
185.9
|
|
13.4
|
|
172.5
|
|
14
Table of Contents
Changes in Level 3 fair value
measurements
The table below includes a rollforward of the Balance Sheet amounts
(including the change in fair value) for financial instruments classified by us
within Level 3 of the valuation hierarchy. When a determination is made to
classify a financial instrument within Level 3 of the valuation hierarchy, the
determination is based upon the significance of the unobservable factors to the
overall fair value measurement. Level 3 financial instruments typically
include, in addition to the unobservable or Level 3 components, observable
components (that is, components that are actively quoted and can be validated to
external sources).
(in
millions)
|
|
Twelve months ended
December 31, 2009
|
|
Twelve months ended
December 31, 2008
|
|
|
|
|
|
|
|
Fair value asset (liability), beginning of period
|
|
$
|
172.5
|
|
$
|
(194.3
|
)
|
Total realized and unrealized (losses) gains
included in Gain (loss) on derivatives
|
|
(1.0
|
)
|
0.4
|
|
Purchases, sales and settlements, net
|
|
(200.9
|
)
|
366.4
|
|
Transfers in and/or out of Level 3
|
|
3.4
|
|
|
|
Fair value (liability) asset, end of period
|
|
(26.0
|
)
|
172.5
|
|
|
|
|
|
|
|
Total unrealized (losses) gains included in
income related to financial assets and liabilities still on the balance sheet
at December 31, 2009 and 2008
|
|
$
|
(0.1
|
)
|
$
|
|
|
The $3.4 million of
transfers out of Level 3 for the year ended December 31, 2009 represent
crude oil collars that were converted to crude oil swaps during the first
quarter of 2009.
For further discussion
related to the Companys derivatives see Note 3 to the financial statements.
Fair Market Value of Financial Instruments
The Company used various assumptions and methods in
estimating the fair values of its financial instruments. The carrying amounts
of cash and cash equivalents and accounts receivable approximated their fair
value due to the short-term maturity of these instruments. The carrying amount
of the Companys credit facilities approximated fair value, because the
interest rates on the credit facilities are variable. The fair values of the
8.25 % senior subordinated notes due 2016 and the 10.25 % senior notes due 2014
were estimated based on quoted market prices. The fair values of the Companys
derivative instruments and other investments are discussed above.
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
(in millions)
|
|
As of
December 31, 2009
|
|
|
|
|
|
|
|
Line of credit
|
|
$
|
|
|
$
|
|
|
Senior secured revolving
credit facility
|
|
372
|
|
372
|
|
8.25 % Senior subordinated
notes due 2016
|
|
200
|
|
196
|
|
10.25% Senior notes due
2014
|
|
437
|
|
487
|
|
|
|
$
|
1,009
|
|
$
|
1,055
|
|
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
(in millions)
|
|
As of
December 31, 2008
|
|
|
|
|
|
|
|
Line of credit
|
|
$
|
25
|
|
$
|
25
|
|
Senior secured revolving
credit facility
|
|
932
|
|
932
|
|
8.25 % Senior subordinated
notes due 2016
|
|
200
|
|
116
|
|
|
|
$
|
1,157
|
|
$
|
1,073
|
|
15
Table of
Contents
Assets and Liabilities Measured at Fair
Value on a Nonrecurring Basis
In
December 2009, subsequent to the approval of the Companys capital budget,
the Company recorded a $4.2 million impairment charge related to the write down
of a drilling rig to its fair value. Fair value may be estimated using
comparable market data, a discounted cash flow method, or a combination of the
two. In the discounted cash flow method, estimated future cash flows are based
on managements expectations for the future and include estimates of future oil
and gas production, commodity prices based on published forward commodity price
curves as of the date of the estimate, operational costs, and a risk-adjusted
discount rate. The fair value measurement was based on Level 3 inputs.
The fair value of the drilling rig on December 31, 2009 was $3.3
million.
3.
Hedging
To
minimize the effect of a downturn in oil and gas prices and protect the Companys
profitability and the economics of its development plans, the Company enters
into crude oil and natural gas hedge contracts from time to time. The terms of
contracts depend on various factors, including managements view of future
crude oil and natural gas prices, acquisition economics on purchased assets and
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. The Company
benefits from lower natural gas pricing as it is a consumer of natural gas in
its California operations. In the Rocky
Mountains and E. Texas the Company benefits from higher natural gas pricing.
The Company has 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 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 its Board of Directors.
Currently, the hedges are in the form of swaps and collars. However, the Company may use a variety of
hedge instruments in the future to hedge WTI or the index gas price. The Company also utilizes interest rate
derivatives to protect against changes in interest rates on its floating rate
debt.
At
December 31, 2009, the net fair value derivative liability was $97.4
million as compared to a net fair value asset of $185.9 million at December 31,
2008 which reflects changes in commodity prices and interest rates. Based on
NYMEX strip pricing as of December 31, 2009, the Company expects to make
hedge payments under the existing derivatives of $21.7 million during the next
twelve months.
At
December 31, 2009, AOCL consisted of $(60.4) million, net of tax, of
unrealized losses from crude oil and natural gas swaps and collars that
qualified for hedge accounting treatment at December 31, 2009, less any
ineffectiveness recognized. As a result
of discontinuing hedge accounting on January 1, 2010, such mark-to-market
values at December 31, 2009 are frozen in AOCL as of the de-designation
date and will be reclassified into earnings in the same period that the
forecasted transactions impact earnings.
The
related cash flow impact of all of the Companys hedges is reflected in cash
flows from operating activities.
The
Company presents its derivative assets and liabilities on its Balance Sheets on
a net basis. The Company nets derivative assets and liabilities whenever
it has a legally enforceable master netting agreement with a counterparty to a
derivative contract. The Company uses these agreements to manage and
reduce its potential counterparty credit risk.
16
Table of
Contents
The
following table disaggregates the Companys net derivative assets and
liabilities into gross components on a contract-by-contract basis before giving
effect to master netting arrangements. Finally, the Company identifies
the line items on its 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. The Company uses the end of period accounting designation
to determine the classification for each derivative position.
|
|
As of December 31, 2009
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
(in millions)
|
|
Balance Sheet
Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Commodity Oil
|
|
Current assets
|
|
$
|
14.2
|
|
Current liability
|
|
$
|
30.8
|
|
Commodity Natural Gas
|
|
Current assets
|
|
1.3
|
|
|
|
|
|
Commodity Oil
|
|
|
|
|
|
Long term liabilities
|
|
74.1
|
|
Commodity Natural Gas
|
|
Long term assets
|
|
0.4
|
|
|
|
|
|
Commodity Natural Gas
|
|
Current liability
|
|
0.2
|
|
|
|
|
|
Commodity Natural Gas
|
|
Long term liabilities
|
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
Long term assets
|
|
0.3
|
|
Current assets
|
|
3.5
|
|
Interest rate contracts
|
|
|
|
|
|
Current liabilities
|
|
2.7
|
|
Interest rate contracts
|
|
|
|
|
|
Long term liabilities
|
|
3.0
|
|
Total derivatives
designated as hedging instruments under authoritative guidance
|
|
|
|
17.6
|
|
|
|
114.1
|
|
Commodity Natural Gas
|
|
|
|
|
|
Current assets
|
|
0.4
|
|
Commodity Natural Gas
|
|
|
|
|
|
Current liabilities
|
|
0.5
|
|
Total derivatives not
designated as hedging instruments under authoritative guidance
|
|
|
|
|
|
|
|
0.9
|
|
Total Derivatives
|
|
|
|
$
|
17.6
|
|
|
|
$
|
115.0
|
|
The tables below summarize the Statement of Income
impacts of the Companys derivative instruments before tax for the twelve
months ending December 31, 2009 (in millions):
Derivatives
cash
flow hedging
relationships
|
|
Amount
of Gain
(Loss) Recognized
in AOCL on
Derivative
(Effective portion)
|
|
Location
of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)
|
|
Amount
of Gain
(Loss)
Reclassified from
AOCL into
Income (Effective
Portion)
|
|
Location
of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Amount
of Gain (Loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Commodity - Oil
|
|
$
|
(219.3
|
)
|
Sales of oil and gas
|
|
$
|
53.9
|
|
Sales of oil and gas
|
|
$
|
|
|
Commodity - Natural Gas
|
|
12.9
|
|
Sales of oil and gas
|
|
25.4
|
|
Gain (loss) on derivatives
|
|
(0.6
|
)
|
Interest rate
|
|
(2.7
|
)
|
Interest expense
|
|
(7.0
|
)
|
Gain (loss) on derivatives
|
|
|
|
Total
|
|
$
|
(209.1
|
)
|
|
|
$
|
72.3
|
|
|
|
$
|
(0.6
|
)
|
17
Table of
Contents
Amount of Gain or (Loss) Recognized in Income on
Derivatives not designated as Hedging Instruments under authoritative guidance
as of twelve months ending December 31, 2009:
Derivatives not designated as
Hedging Instruments under
authoritative guidance
|
|
Location of Gain (Loss) Recognized
in Income on Derivative
|
|
Amount of Gain (Loss)
Recognized in Income on
Derivatives not designated as
Hedging Instruments under
authoritative guidance
|
|
|
|
|
|
|
|
Commodity Oil
|
|
Gain
(loss) on derivatives
|
|
$
|
(6.7
|
)
|
Commodity - Natural Gas
|
|
Gain
(loss) on derivatives
|
|
(0.5
|
)
|
Commodity - Natural Gas
|
|
(Loss) income from discontinued operations, net of
taxes
|
|
(0.5
|
)
|
Total Derivatives
|
|
|
|
$
|
(7.7
|
)
|
During
the first quarter of 2009, the Company converted oil collars for 6,000 Bbl/D
for the full year 2010 into swaps for the same volumes with swap prices ranging
from $61.00 to $64.80.
The Company generally utilizes NYMEX WTI based
derivatives to hedge cash flows from its California oil sales. The Companys oil sales contracts with
multiple refiners are primarily based on the field posting prices. There is a high correlation between WTI and
the field posting prices which allowed us to utilize hedge accounting. As there is a ready market for the Companys
crude oil in California, the Company does not believe the loss of any
particular contract impacts the probability that its hedged forecasted
transactions will occur. The Company
generally hedges its natural gas at the basis location that corresponds to the
forecasted sale.
While the Company designates the majority of its
hedges as cash flow hedges, it has not elected hedge accounting on certain of
its crude oil and natural gas hedges.
During the twelve months ended December 31, 2009, the Company
recorded $6.5 million under the caption Gain (loss) on derivatives related to
hedges for which it either did not elect hedge accounting or which no longer
qualified for hedge accounting. In
conjunction with the sale of the DJ basin assets, during the first quarter of
2009, the Company concluded that the forecasted transaction in certain of its
hedging relationships was not probable of occurring. As such, the Company reclassified a gain of
$14.3 million from AOCL to the Statement of Income under the caption Gain
(loss) on derivatives. Gain (loss) on derivatives
includes a loss for cash settlements of $7.6 million and a gain for the change
in fair value of $0.3 million on hedges for which the Company has not elected
hedge accounting. Additionally,
a portion of the change in
fair value for hedges that was designated as cash flow hedges may impact the
Companys income as the sales price is not perfectly correlated with the
Companys hedges. The Company recognized
an unrealized net loss of $0.5 million on the Statement of Income under the
caption Gain (loss) on derivatives for the twelve months ended December 31,
2009, respectively, as a result of ineffectiveness. During
the first quarter of 2009, the Company entered into natural gas derivatives on
behalf of the purchaser of its DJ assets.
The Company did not elect hedge accounting for these hedges and recorded
an unrealized net loss of $0.5 million on the Statement of Income under the
caption (Loss) income from discontinued operations, net of taxes.
The
Companys hedge contracts have been executed primarily with counterparties that
are party to its senior secured revolving credit facility.
Neither
the Company nor its counterparties are required to post collateral in
connection with its derivative positions and netting agreements are in place
with each of the Companys counterparties allowing the Company to offset its
commodity derivative asset and liability positions. The credit rating of each of these
counterparties was AA-/Aa2, or better as of December 31, 2009. The Companys derivatives are held with a
small number of counterparties and as of December 31, 2009, the Companys
largest three counterparties accounted for 76% of the value of its total
derivative positions.
As
of December 31, 2009, the Company had the following commodity hedges:
|
|
2010
|
|
2011
|
|
2012
|
|
Oil Bbl/D:
|
|
14,930
|
|
9,020
|
|
3,000
|
|
Natural Gas MMBtu/D:
|
|
19,000
|
|
10,000
|
|
10,000
|
|
For further discussion
related to the fair value of the Companys derivatives see Note 2 to the
financial statements.
18
Table of Contents
4.
Asset
Retirement Obligations (AROs)
The following table
summarizes the change in abandonment obligation for the years ended December 31
(in thousands):
|
|
2009
|
|
2008
|
|
Beginning
balance at January 1
|
|
$
|
41,967
|
|
$
|
36,426
|
|
Liabilities
incurred
|
|
1,407
|
|
4,686
|
|
Liabilities
settled
|
|
(1,030
|
)
|
(4,607
|
)
|
Disposition
of assets
|
|
(2,752
|
)
|
|
|
Revisions
in estimated liabilities
|
|
|
|
2,006
|
|
Accretion
expense
|
|
3,895
|
|
3,456
|
|
Ending
balance at December 31
|
|
$
|
43,487
|
|
$
|
41,967
|
|
The
ARO reflects the estimated present value of the amount of dismantlement,
removal, site reclamation and similar activities associated with the Companys
oil and gas properties. Inherent in the fair value calculation of the 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.
5
.
Acquisitions
and Divestitures
During
the twelve months ended December 31, 2009, the Company completed
acquisitions totaling $13.5 million. In June 2009, the Company acquired
property near McKittrick, California, the deep rights to one of the leases in
its Darco property in E. Texas, and additional interests in its Piceance Garden
Gulch assets.
On July 17, 2009, the Company completed
the financing of its
E. Texas gas gathering system for $18.4 million in
cash. The Company entered into
concurrent long-term gas gathering agreements for the E. Texas production which
contained an embedded lease. The
transaction was treated as a financing obligation. Accordingly, the net book value of the
property of $16.7 million will be depreciated over the remaining useful life of
the asset and the cash received of $18.4 million was recorded as a financing
obligation. A portion of future payments
will be recorded as gathering expense, a portion as interest expense and the
balance as a reduction in the financing obligation. There is no minimum payment required under
these agreements.
On
March 3, 2009, the Company entered into an agreement to sell its DJ basin
assets and related hedges for $154 million before customary closing
adjustments. The closing date of the sale of the assets was April 1,
2009. The Company recorded a pre-tax
impairment loss of $9.6 million related to the sale, which is aggregated within
the $5.9 million (Loss) income from discontinued operations, net of taxes on
its Statement of Income for the twelve months ended December 31, 2009.
19
Table of
Contents
(Loss)
income from discontinued operations, net of tax on the accompanying statements
of income is comprised of the following (in thousands):
|
|
For the Twelve Months Ended
December 31,
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
|
$
|
5,396
|
|
48,729
|
|
$
|
34,192
|
|
Loss on sale of asset
|
|
(908
|
)
|
|
|
|
|
Other revenue
|
|
623
|
|
2,072
|
|
1,851
|
|
Total revenue
|
|
5,111
|
|
50,801
|
|
36,043
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
2,576
|
|
11,340
|
|
10,279
|
|
Production taxes
|
|
195
|
|
3,023
|
|
2,564
|
|
DD&A
|
|
2,188
|
|
12,642
|
|
10,829
|
|
General and administrative
|
|
388
|
|
1,074
|
|
547
|
|
Interest expense
|
|
815
|
|
2,267
|
|
2,218
|
|
Commodity derivatives
|
|
484
|
|
145
|
|
13
|
|
Dry hole, abandonment,
impairment and exploration
|
|
9,637
|
|
1,772
|
|
5,306
|
|
Total expenses
|
|
16,283
|
|
32,263
|
|
31,756
|
|
|
|
|
|
|
|
|
|
(Loss) income from
discontinued operations, before income taxes
|
|
(11,172
|
)
|
18,538
|
|
4,287
|
|
Income tax (benefit)
expense
|
|
(5,234
|
)
|
6,785
|
|
1,643
|
|
(Loss) income from
discontinued operations
|
|
$
|
(5,938
|
)
|
11,753
|
|
$
|
2,644
|
|
On July 15, 2008, the Company
acquired a 100%
working interest in natural gas producing properties on 4,500 net acres in
Limestone and Harrison counties in E. Texas for approximately $668 million,
including post
closing adjustments of $46 million.
The
unaudited pro forma results presented below for the years ended December 31,
2008 and 2007 have been prepared to give effect to the E. Texas Acquisition on
the Companys results of operations under the purchase method of accounting as
if it had been consummated at the beginning of each of the periods
presented. The unaudited pro forma
results do not purport to represent the results of operations that actually
would have occurred on such date or to project the Companys results of
operations for any future date or period.
The pro forma results set forth below also gives effect to (1) the
presentation as discontinued operations of the Companys DJ Basin assets, which
were sold on April 1, 2009, and (2) the Companys implementation of
authoritative guidance on determining whether instruments granted in
share-based payment transactions are participating securities, which requires
the revision of prior period basic and diluted earning per share data.
|
|
Year Ended
December 31,
2008
|
|
Year Ended
December 31,
2007
|
|
Pro forma revenue
|
|
$
|
797,261
|
|
$
|
581,138
|
|
Pro forma income from
operations
|
|
$
|
197,196
|
|
$
|
162,733
|
|
Pro forma net income
|
|
$
|
125,917
|
|
$
|
103,333
|
|
Pro forma basic earnings
per share
|
|
$
|
2.79
|
|
$
|
2.34
|
|
Pro forma diluted earnings
per share
|
|
$
|
2.75
|
|
$
|
2.30
|
|
20
Table of Contents
The following is a
calculation and allocation of purchase price to the E. Texas Acquisition assets
and liabilities based on their relative fair values, as determined by the
valuation of proved reserves and related assets as of the acquisition date:
Purchase
price (in thousands):
|
|
As of
December 31, 2008
|
|
Original
purchase price
|
|
$
|
622,356
|
|
|
|
|
|
Closing
adjustments for property costs, and operating expenses in excess of revenues
between the effective date and closing date
|
|
45,506
|
|
|
|
|
|
Total
purchase price allocation
|
|
$
|
667,862
|
|
|
|
|
|
Allocation
of purchase price (in thousands):
|
|
|
|
|
|
|
|
Oil
and natural gas properties
|
|
$
|
651,659
|
(i)
|
Pipeline
|
|
17,277
|
|
Tax
receivable
|
|
1,476
|
|
|
|
|
|
Total
assets acquired
|
|
670,412
|
|
|
|
|
|
Current
liabilities
|
|
(1,195
|
)(ii)
|
Asset
retirement obligation
|
|
(1,355
|
)
|
|
|
|
|
Net
assets acquired
|
|
$
|
667,862
|
|
(i) Determined by
reserve analysis.
(ii) Accrual for
royalties payable.
In May 2007, the
Company sold its non-core West Montalvo assets in Ventura County, California.
The sale proceeds were approximately $61 million and the Company recognized a
$52 million pretax gain on the sale, including post closing adjustments. In the
fourth quarter of 2007 the Company completed the sale of a portion of its
Tri-State acreage for $1.4 million.
6.
Oil and Gas
Properties, Buildings and Equipment
Oil and gas properties,
buildings and equipment consist of the following at December 31 (in
thousands):
|
|
2009
|
|
2008
|
|
Oil
and gas:
|
|
|
|
|
|
Proved
properties:
|
|
|
|
|
|
Producing
properties, including intangible drilling costs
|
|
$
|
1,892,340
|
|
$
|
1,820,609
|
|
Lease
and well equipment (1)
|
|
513,961
|
|
663,610
|
|
|
|
2,406,301
|
|
2,484,219
|
|
Unproved
properties
|
|
|
|
|
|
Properties,
including intangible drilling costs
|
|
267,303
|
|
255,412
|
|
|
|
2,673,604
|
|
2,739,631
|
|
Less
accumulated depreciation, depletion and amortization
|
|
583,077
|
|
509,277
|
|
|
|
2,090,527
|
|
2,230,354
|
|
Commercial
and other:
|
|
|
|
|
|
Land
|
|
66
|
|
810
|
|
Drilling
rigs and equipment
|
|
5,333
|
|
13,166
|
|
Buildings
and improvements
|
|
5,911
|
|
6,274
|
|
Machinery
and equipment
|
|
26,608
|
|
22,767
|
|
|
|
37,918
|
|
43,017
|
|
Less
accumulated depreciation
|
|
22,060
|
|
18,946
|
|
|
|
15,858
|
|
24,071
|
|
|
|
$
|
2,106,385
|
|
$
|
2,254,425
|
|
(1)
Includes cogeneration facility costs.
21
Table of Contents
Suspended Well Costs
The following table provides
an aging of capitalized exploratory well costs based on the date the drilling
was completed and the number of wells for which exploratory well costs have
been capitalized for a period of greater than one year since the completion of
drilling (in thousands, except number of projects):
|
|
2009
|
|
2008
|
|
2007
|
|
Capitalized
exploratory well costs that have been capitalized for a period of one year or
less
|
|
$
|
|
|
$
|
|
|
$
|
6,826
|
|
Capitalized
exploratory well costs that have been capitalized for a period greater than
one year
|
|
|
|
|
|
|
|
Balance
at December 31
|
|
$
|
|
|
$
|
|
|
$
|
6,826
|
|
|
|
|
|
|
|
|
|
Number
of projects that have exploratory well costs that have been capitalized for a
period of greater than one year
|
|
|
|
|
|
|
|
The following table reflects
the net changes in capitalized exploratory well costs (in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Beginning
balance at January 1
|
|
$
|
|
|
$
|
6,826
|
|
$
|
89
|
|
Additions
to capitalized exploratory well costs pending the determination of proved
reserves
|
|
|
|
|
|
6,826
|
|
Reclassifications
to wells, facilities and equipment based on the determination of proved
reserves
|
|
|
|
(6,826
|
)
|
|
|
Capitalized
exploratory well costs charged to expense
|
|
|
|
|
|
(89
|
)
|
Ending
balance at December 31
|
|
$
|
|
|
$
|
|
|
$
|
6,826
|
|
Dry hole, abandonment, impairment
and exploration
In 2009 the Company had dry
hole, abandonment and impairment charges of $5.2 million primarily due to a
$4.2 million impairment charge related to the write-down of a rig to its fair
market value (see Note 2 Fair Value Measurement). The Company incurred exploration costs in
2009 of $0.2 million compared to $0.6 million in 2008 and $0.6 million in
2007. These costs consist primarily of
geological and geophysical costs.
In 2008 the Company had dry
hole, abandonment, impairment and exploration charges of $10.5 million
consisting primarily of $7.3 million for technical difficulties that were
encountered on five wells in the Piceance basin before reaching total
depth. These holes were abandoned in
favor of drilling to the same bottom hole location by drilling new wells. Due to the release of its rigs the Company
performed an impairment test which resulted in $2.4 million of impairment costs
resulting from the impairment of one rig.
In 2007 the Company had dry
hole, abandonment, impairment and exploration charges of $8.4 million that
consisted primarily of a $3.3 million impairment of its Coyote Flats
prospect to reflect its fair value in conjunction with the preparation of its
year end reserve estimates, a $2.9 million writedown of its Bakken properties
which were sold in September 2007, geological and geophysical costs of
$0.6 million and other dry hole charges of $1.6 million.
7.
Debt
Obligations
Short-term lines of credit
In
2005, the Company 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 the
Company or the lender. In conjunction
with the amendment to the Companys senior secured credit facility, on July 15,
2008, the Line of Credit was collateralized by oil and natural gas properties
representing at least 80% of the present value of the Companys proved
reserves.
At December 31, 2009 and 2008, the outstanding
balance under this Line of Credit was zero and $25.3 million,
respectively. Interest on amounts
borrowed is charged at LIBOR plus a margin of approximately 1.4%. The weighted average interest rate on
outstanding borrowings on the Line of Credit at December 31, 2009 and 2008
was 0% and 1.4%, respectively.
22
Table of
Contents
Senior secured revolving credit
facility
The Companys senior secured revolving credit
facility (the Agreement) has a current borrowing base and lender commitments of
$938 million.
The LIBOR and prime rate margins are between 2.25%
and 3.0% based on the ratio of credit outstanding to the borrowing base and the
annual commitment fee on the unused portion of the credit facility is 0.50%.
Covenants
under the Agreement are as follows:
Total funded debt to EBITDAX (1) ratio not
greater than:
|
|
Senior
secured debt to EBITDAX ratio not greater than:
|
|
2009
|
|
2010
|
|
Thereafter
|
|
to Sep
2010
|
|
Mar 2011
|
|
Sep 2011
|
|
Thereafter
|
|
4.75
|
|
4.50
|
|
4.00
|
|
3.75
|
|
3.50
|
|
3.25
|
|
3.0
|
|
(1) Net
income before interest expense, income tax expense, depreciation and
amortization expense, exploration expense and non-cash items of income.
The
write off of $38.5 million to bad debt expense associated with the bankruptcy
of BWOC is excluded from the calculation of EBITDAX, per the Agreement.
The
Agreement contains a current ratio covenant which, as defined, must be at least
1.0. The total outstanding debt at December 31,
2009 under the Agreement, as amended, and the Line of Credit was $372 million and
zero, respectively, and $4 million in letters of credit have been issued under
the facility, leaving $562 million in borrowing capacity
available. The maximum amount available is subject to semi-annual
redeterminations of the borrowing base, based on the value of the Companys
proved oil and gas reserves, in April and October of each year in
accordance with the lenders customary procedures and
practices. Both the Company and the banks have the bilateral right
to one additional redetermination each year.
The Agreement is collateralized by oil and natural gas properties
representing at least 80% of the present value of the Companys proved
reserves.
Second Lien Term Loan
On April 27, 2009 the
Company completed a $140 million second lien term loan, with lenders from among
its current lending group, with a maturity of January 16, 2013. The Company paid off the second lien term
loan on May 29, 2009 from the proceeds of the issuance of its 10.25%
senior notes due 2014, and wrote off $7.2 million in deferred loan fees for the
year ended December 31, 2009.
10.25% senior
notes due 2014
On May 27, 2009, the Company issued in a public
offering $325 million principal amount of 10.25% senior notes due 2014 ($325
million Notes). Interest on the $325
million Notes is paid semiannually in June and December of each
year. The $325 million Notes were issued
at a discount to par value of 93.546%, and are carried on the balance sheet at
their amortized cost. The deferred costs of approximately $9.5 million
associated with the issuance of this debt are being amortized over the five
year life of the $325 million Notes.
Pursuant to the terms of the
Companys senior secured revolving credit facility, the issuance of the $325
million Notes automatically reduced its borrowing base by 25 cents per dollar
of Notes issued, or approximately $81 million.
The Company wrote off $3.3 million of deferred loan fees during the
second quarter of 2009 as a result of the decrease in its borrowing base.
On August 13, 2009,
the Company issued in a public offering an additional $125 million principal
amount of its 10.25% senior notes due
2014 ($125 million notes and, together with the $325 million notes, the
Notes).
The $125 million Notes were
issued at a premium to par value of 104.75%, and are carried on the balance
sheet at their amortized cost. The deferred costs of approximately $1.9 million
associated with the issuance of this debt are being amortized over the five
year life of the Notes.
Pursuant to the terms of the
Companys senior secured revolving credit facility, the issuance of the $125
million Notes automatically reduced its borrowing base by 25 cents per dollar
of notes issued, or approximately $31 million.
The Company wrote off $0.3 million of deferred loan fees during the
third quarter of 2009 as a result of the decrease in its borrowing base.
The $125 million Notes and the previously issued
$325 million Notes are treated as a single series of debt securities and are
carried on the balance sheet at their combined amortized cost.
8.25% senior subordinated notes due
2016
In
2006, the Company issued in a public offering $200 million of 8.25% senior
subordinated notes due 2016 (the Sub notes).
Interest on the Sub notes is paid semiannually in May and November of
each year. The deferred costs of
23
Table of Contents
approximately
$5.2 million associated with the issuance of this debt are being amortized over
the ten year life of the Sub notes.
Financial
Covenants
The
senior secured revolving credit facility contains restrictive covenants as
described above. Under the Companys
senior subordinated and senior unsecured notes as long as the interest coverage
ratio (as defined) is greater than 2.5 times, the Company may incur additional
debt. The Company was in compliance with
all of these covenants as of December 31, 2009.
|
|
As of
December 31, 2009
|
|
Current Ratio (Not less
than 1.0)
|
|
5.5
|
|
Total Funded Debt Ratio to
EBITDAX (Not greater than 4.75)
|
|
3.3
|
|
Interest Coverage Ratio
(Not less than 2.5)
|
|
4.2
|
|
Senior Secured Debt Ratio
to EBITDAX (Not greater than 3.75)
|
|
1.2
|
|
The
weighted average interest rate on the Companys total outstanding borrowings
was 7.0% and 4.9% at December 31, 2009 and 2008, respectively.
8.
Income
Taxes
The continuing operations
provision for income taxes consists of the following (in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Current:
|
|
|
|
|
|
|
|
Federal
|
|
$
|
2,388
|
|
$
|
2,991
|
|
$
|
12,676
|
|
State
|
|
(198
|
)
|
5,285
|
|
5,191
|
|
|
|
2,190
|
|
8,276
|
|
17,867
|
|
Deferred:
|
|
|
|
|
|
|
|
Federal
|
|
28,221
|
|
56,919
|
|
52,235
|
|
State
|
|
(2,062
|
)
|
5,113
|
|
8,958
|
|
|
|
26,159
|
|
62,032
|
|
61,193
|
|
Total
|
|
$
|
28,349
|
|
$
|
70,308
|
|
$
|
79,060
|
|
The following table
summarizes the components of the total deferred tax assets and liabilities. The
components of the net deferred tax liability consist of the following at December 31
(in thousands):
|
|
2009
|
|
2008
|
|
Deferred
tax asset:
|
|
|
|
|
|
Federal
benefit of state taxes
|
|
$
|
6,064
|
|
$
|
11,082
|
|
Credit
carryforwards
|
|
27,729
|
|
33,636
|
|
Stock
option costs
|
|
11,091
|
|
9,089
|
|
Derivatives
|
|
42,218
|
|
2,282
|
|
Bad
debt expense
|
|
15,605
|
|
15,936
|
|
Other,
net
|
|
1,807
|
|
4,312
|
|
|
|
104,514
|
|
76,337
|
|
Deferred
tax liability:
|
|
|
|
|
|
Depreciation
and depletion
|
|
(330,836
|
)
|
(319,349
|
)
|
Derivatives
|
|
(5,216
|
)
|
(72,801
|
)
|
|
|
(336,052
|
)
|
(392,150
|
)
|
Net
deferred tax liability
|
|
$
|
(231,538
|
)
|
$
|
(315,813
|
)
|
At December 31, 2009,
the Companys net deferred tax assets and liabilities were recorded as a
current asset of $5.6 million and a long-term liability of $237.2 million. At December 31,
2008, the Companys net deferred tax assets and liabilities were recorded as a
current liability of $45.5 million and a long-term liability of $270.3 million.
24
Table of Contents
Reconciliation of the
continuing operations statutory federal income tax rate to the effective income
tax rate follows:
|
|
2009
|
|
2008
|
|
2007
|
|
Tax
computed at statutory federal rate
|
|
35
|
%
|
35
|
%
|
35
|
%
|
State
income taxes, net of federal benefit
|
|
4
|
|
3
|
|
5
|
|
Deferred
state rate impact
|
|
(4
|
)
|
(1
|
)
|
|
|
Net
impact to uncertain tax positions
|
|
(2
|
)
|
|
|
|
|
Other
|
|
(1
|
)
|
(1
|
)
|
(2
|
)
|
Effective
tax rate
|
|
32
|
%
|
36
|
%
|
38
|
%
|
The Company has
approximately $14 million of federal and $15 million of state (California) EOR
tax credit carryforwards available to reduce future income taxes. The EOR
credits will begin to expire, if unused, in 2024 and 2016 for federal and
California purposes, respectively.
In June 2006, the FASB
issued authoritative guidance on accounting
for uncertainty in income taxe
s
.
The guidance addresses the determination of whether tax benefits claimed or
expected to be claimed on a tax return should be recorded in the financial
statements. The Company 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. There is also guidance on derecognition, classification, interest
and penalties on income taxes, accounting in interim periods and requires
additional disclosures.
As of December 31,
2009, the Company had a gross liability for uncertain tax benefits of
$6.1 million of which $5.2 million, if recognized, would affect the
effective tax rate. The Company recognizes 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. The Company had accrued approximately $0.7 million and $1.2 million of
interest related to its uncertain tax positions as of December 31, 2009
and 2008, respectively.
For the year ended December 31,
2009 the Company recognized a net benefit of approximately $4.0 million to the
Statements of Income due to audit settlements and the closure of certain
federal and state tax years and uncertain tax positions accruals, net of
interest expense, of approximately $0.8 million.
For the year ended December 31,
2008 the Company recognized a net benefit of approximately $1.6 million to the
Statements of Income due to the closure of certain federal and state tax years,
offset by additional uncertain tax position accruals net of interest expense of
approximately $1.9 million.
For the year ended December 31,
2007 the Company recognized a net benefit of approximately $0.6 million to the
Statements of Income due to the closure of certain federal and state tax years,
offset by additional uncertain tax position accruals net of interest expense of
approximately $0.2 million.
The following table
illustrates changes in the gross unrecognized tax benefits (in millions):
|
|
2009
|
|
2008
|
|
2007
|
|
Unrecognized
tax benefits at January 1
|
|
$
|
12.0
|
|
$
|
12.0
|
|
$
|
14.6
|
|
(Decreases)
increases for positions taken in current year
|
|
(0.1
|
)
|
1.2
|
|
0.5
|
|
(Decreases)
increases for positions taken in a prior year
|
|
(1.3
|
)
|
0.3
|
|
(0.3
|
)
|
Decreases
for settlements with taxing authorities
|
|
(3.6
|
)
|
|
|
|
|
Decreases
for lapses in the applicable statute of limitations
|
|
(0.9
|
)
|
(1.5
|
)
|
(2.8
|
)
|
Unrecognized
tax benefits at December 31
|
|
$
|
6.1
|
|
$
|
12.0
|
|
$
|
12.0
|
|
As of December 31,
2009, the Company remains subject to examination in the following major tax
jurisdictions for the tax years indicated below:
Jurisdiction:
|
|
Tax
Years Subject to Exam:
|
|
Federal
|
|
2005 2008
|
|
California
|
|
2005 2008
|
|
Colorado
|
|
2005 2008
|
|
Utah
|
|
2005 2008
|
|
25
Table of Contents
9. Earnings Per Share
In
June 2008, the FASB issued authoritative guidance, 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. All prior period earnings per share data
presented were adjusted retrospectively to conform with the provisions of the
guidance which is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and interim periods within those years.
The
following table shows the computation of basic and diluted net (loss) income
per share from continuing and discontinued operations for the years ended December 31,
(in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Net income from continuing
operations
|
|
$
|
59,968
|
|
$
|
121,776
|
|
$
|
127,284
|
|
Less: Income allocable to
participating securities
|
|
1,460
|
|
1,752
|
|
1,494
|
|
Income available for
shareholders
|
|
$
|
58,508
|
|
$
|
120,024
|
|
$
|
125,790
|
|
|
|
|
|
|
|
|
|
Net (loss) income from
discontinued operations
|
|
$
|
(5,938
|
)
|
$
|
11,753
|
|
$
|
2,644
|
|
Less: Income allocable to
participating securities
|
|
|
|
173
|
|
32
|
|
Loss (income) from
discontinued operations available for shareholders
|
|
$
|
(5,938
|
)
|
$
|
11,580
|
|
$
|
2,612
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
from continuing operations
|
|
$
|
1.31
|
|
$
|
2.70
|
|
$
|
2.85
|
|
Basic (loss) earnings per
share from discontinued operations
|
|
(0.13
|
)
|
.26
|
|
.06
|
|
Basic earnings per share
|
|
$
|
1.18
|
|
$
|
2.96
|
|
$
|
2.91
|
|
|
|
|
|
|
|
|
|
Dilutive earnings per
share from continuing operations
|
|
$
|
1.30
|
|
$
|
2.66
|
|
$
|
2.81
|
|
Dilutive (loss) earnings
per share from discontinued operations
|
|
(0.13
|
)
|
.26
|
|
.06
|
|
Basic) earnings per share
|
|
$
|
1.17
|
|
$
|
2.92
|
|
$
|
2.87
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic
|
|
44,625
|
|
44,485
|
|
44,075
|
|
Add: dilutive effects of
stock options
|
|
221
|
|
578
|
|
604
|
|
Weighted average shares
outstanding - dilutive
|
|
44,846
|
|
45,063
|
|
44,679
|
|
Options
to purchase $1.6 million, $0.2 million and $0.0 million shares were not
included in the diluted (loss) earnings per share calculation for the years
ended December 31, 2009, 2008 and 2007, respectively, because their effect
would have been anti-dilutive.
The adoption of the
guidance issued by the FASB decreased basic earnings per share from continuing
operations by $0.4 and $0.4 for the years ended December 31, 2008 and
2007, respectively, and dilutive earnings per share from continuing operations
by $0.2 and $0.2 for the years ended December 31, 2008 and 2007,
respectively. Basic and dilutive (loss)
earnings per share from discontinued operations remained unchanged for the year
ended December 31, 2008 and 2007.
10.
Shareholders Equity
Shares of Class A
Common Stock (Common Stock) and Class B Stock, referred to collectively as
the Capital Stock, are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $0.50 per share
preference in the event of liquidation or dissolution. Further, each share of Class B
Stock is convertible into one share of Common Stock at the option of the
holder.
Dividends
The regular annual dividend
is currently $0.30 per share, payable quarterly in March, June, September and
December.
Dividend payments are
limited by covenants in the Companys (1) credit facility to the greater
of $20 million or 75% of net income, and (2) bond indenture of up to $20
million annually irrespective of its coverage ratio or net income if the
Company has exhausted its restricted payments basket, and up to $10 million in
the event it is in a non-payment default.
Shareholder Rights Plan
In November 1999, the
Company adopted a Shareholder Rights Agreement and declared a dividend
distribution of one Right for each outstanding share of Capital Stock on December 8,
1999. The plan expired on December 8, 2009. No rights were exercised under the plan.
26
Table of Contents
11.
Equity
Incentive Compensation Plans and Other Benefit Plans
In December 1994, the
Companys Board of Directors adopted the Berry Petroleum Company 1994 Stock
Option Plan which was restated and amended in December 1997 and December 2001
(the 1994 Plan or Plan) and approved by the shareholders in May 1998 and May 2002,
respectively. The 1994 Plan provided for the granting of stock options to
purchase up to an aggregate of 3,000,000 shares of Common Stock. All options,
with the exception of the formula grants to non-employee Directors, were
granted at the discretion of the Compensation Committee and the Board of
Directors. The term of each option did not exceed ten years from the date the
options were granted. The 1994 Plan expired in December 2004, and the
shareholders approved a new equity incentive plan in May 2005.
The 2005 Equity Incentive
Plan (the 2005 Plan), approved by the shareholders in May 2005, provides
for granting of equity compensation up to an aggregate of 2,900,000 shares of
Common Stock. All equity grants are at market value on the date of grant and at
the discretion of the Compensation Committee or the Board of Directors. The
term of each grant did not exceed ten years from the grant date, and vesting
has generally been at 25% per year for 4 years or 100% after 3 years. The 2005
Plan also allows for grants to non-employee Directors although no grants were
made to non-employee directors in 2008 or 2009. The grants made to the
non-employee Directors under the 2005 plan vest immediately. The Company uses a
broker for issuing new shares upon option exercise.
Total compensation cost
recognized in the Statements of Income was $7.7 million, $8.9 million and $8.4
million in 2009, 2008 and 2007, respectively. The tax benefit related to this
compensation cost was $3.2 million, $3.8 million and $3.3 million in 2009, 2008
and 2007, respectively.
Stock Options
The fair value of each stock
option award is estimated on the date of grant using the Black-Scholes option
pricing model that uses the assumptions noted in the following table. Expected
volatilities are based on the historical volatility of the Companys stock. The
Company uses historical data to estimate option exercises and employee
terminations within the valuation model; separate groups of recipients that
have similar historical exercise behavior are considered separately for
valuation purposes. The expected term of options granted is based on historical
exercise behavior and represents the period of time that options granted are
expected to be outstanding; the range given below results from certain groups
of recipients exhibiting different exercise behavior. The risk free rate for
periods within the contractual life of the option is based on U.S. Treasury
rates in effect at the time of grant.
During 2009, no options were granted.
|
|
2009
|
|
2008
|
|
2007
|
|
Expected
volatility
|
|
|
|
36%
|
|
32%
- 33%
|
|
Weighted-average
volatility
|
|
|
|
36%
|
|
33%
|
|
Expected
dividends
|
|
|
|
1%
|
|
1%
|
|
Expected
term (in years)
|
|
|
|
5
|
|
4.9
- 5.6
|
|
Risk-free
rate
|
|
|
|
3.2%
|
|
3.4%
- 4.7%
|
|
The following table
summarizes information related to stock options outstanding and exercisable as
of December 31, 2009:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
Average
|
|
|
|
Weighted
|
|
Average
|
|
Range of
|
|
|
|
Average
|
|
Remaining
|
|
|
|
Average
|
|
Remaining
|
|
Exercise
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
Prices
|
|
Outstanding
|
|
Price
|
|
Life
|
|
Exercisable
|
|
Price
|
|
Life
|
|
$7.00
- $15.00
|
|
645,100
|
|
$
|
10.55
|
|
3.5
|
|
645,100
|
|
$
|
10.55
|
|
3.5
|
|
$15.01
- $25.00
|
|
436,250
|
|
21.61
|
|
4.9
|
|
436,250
|
|
21.61
|
|
4.9
|
|
$25.01
- $35.00
|
|
881,051
|
|
31.87
|
|
6.5
|
|
791,475
|
|
31.81
|
|
6.5
|
|
$35.01
- $45.00
|
|
313,619
|
|
42.74
|
|
8.1
|
|
135,500
|
|
43.20
|
|
8.1
|
|
Total
|
|
2,276,020
|
|
$
|
25.36
|
|
5.6
|
|
2,008,325
|
|
$
|
23.53
|
|
5.6
|
|
27
Table of Contents
Weighted average option
exercise price information for the years ended December 31:
|
|
2009
|
|
2008
|
|
2007
|
|
Outstanding
at January 1
|
|
$
|
25.16
|
|
$
|
24.33
|
|
$
|
20.97
|
|
Granted
during the year
|
|
|
|
41.18
|
|
43.40
|
|
Exercised
during the year
|
|
13.52
|
|
19.38
|
|
12.52
|
|
Cancelled/expired
during the year
|
|
28.48
|
|
29.66
|
|
22.88
|
|
Outstanding
at December 31
|
|
25.36
|
|
25.16
|
|
24.33
|
|
Exercisable
at December 31
|
|
23.53
|
|
21.70
|
|
19.88
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary
of stock option activity for the years ended December 31:
|
|
2009
|
|
2008
|
|
2007
|
|
Balance
outstanding, January 1
|
|
2,421,650
|
|
2,527,266
|
|
2,859,836
|
|
Granted
|
|
|
|
89,084
|
|
220,115
|
|
Exercised
|
|
(62,050
|
)
|
(149,950
|
)
|
(444,216
|
)
|
Canceled/expired
|
|
(83,580
|
)
|
(44,750
|
)
|
(108,469
|
)
|
Balance
outstanding, December 31
|
|
2,276,020
|
|
2,421,650
|
|
2,527,266
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at December 31
|
|
2,008,325
|
|
1,842,532
|
|
1,558,780
|
|
|
|
|
|
|
|
|
|
Available
for future grant
|
|
218,635
|
|
412,025
|
|
988,798
|
|
|
|
|
|
|
|
|
|
Weighted
average remaining contractual life (years)
|
|
5.6
|
|
6.5
|
|
7.3
|
|
Weighted
average fair value per option granted during the year based on the
Black-Scholes pricing model
|
|
$
|
|
|
$
|
14.03
|
|
$
|
13.88
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
2009, there was $2.4 million of total unrecognized compensation cost related to
stock options granted under the Plan. This cost is expected to be recognized
over a weighted-average period of 1.3 years. The tax benefit realized from
stock options exercised during the year ended December 31, 2009, 2008 and
2007 is $0.1 million, $1.4 million and $3.5 million, respectively.
|
|
Stock
Options
|
|
|
|
Years
ended
|
|
|
|
December 31,
2009
|
|
December 31,
2008
|
|
December 31,
2007
|
|
Weighted
average fair value per option granted during the year based on the Black-Scholes
pricing model
|
|
$
|
|
|
$
|
14.03
|
|
$
|
13.88
|
|
Total
intrinsic value of options exercised (in millions)
|
|
0.6
|
|
4.4
|
|
11.9
|
|
Total
intrinsic value of options outstanding (in millions)
|
|
15.3
|
|
|
|
50.8
|
|
Total
intrinsic value of options exercisable (in millions)
|
|
15.3
|
|
|
|
38.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Units
Under the 2005 Equity Plan,
the Company began a long-term incentive program whereby restricted stock units
(RSUs) are available for grant to certain employees and non-employee Directors.
Granted RSUs generally vest at either 25% per year over 4 years or 100% after 3
years. Unearned compensation under the restricted stock award plan is amortized
over the vesting period. During 2009 and 2008, the non-employee Directors did
not receive any RSUs. The RSUs granted to the non-employee Directors are 100%
vested at date of grant but are subject to a deferral election before the
corresponding shares are issued of a minimum of four years or until they leave
the Board of Directors or upon change of control. The Company pays cash
compensation on the RSUs in an equivalent amount of actual dividends paid on a
per share basis of its outstanding common stock.
28
Table of Contents
The following is a summary
of RSU activity for the year ended December 31, 2009:
|
|
RSUs
|
|
Weighted
Average
Intrinsic Value at
Grant Date
|
|
Weighted
Average
Contractual Life
Remaining
|
|
Balance
outstanding, January 1
|
|
966,198
|
|
$
|
20.83
|
|
3.0
years
|
|
Granted
|
|
294,504
|
|
26.72
|
|
|
|
Converted
|
|
(107,375
|
)
|
28.98
|
|
|
|
Canceled/expired
|
|
(46,034
|
)
|
25.08
|
|
|
|
Balance
outstanding, December 31
|
|
1,107,293
|
|
$
|
22.14
|
|
2.6
years
|
|
|
|
RSUs
Year ended December 31,
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
Weighted-average
grant date fair value of RSUs issued
|
|
26.72
|
|
$
|
11.26
|
|
$
|
42.36
|
|
Total
value of RSUs vested (in millions)
|
|
2.6
|
|
0.8
|
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
The total compensation cost
related to nonvested awards not yet recognized on December 31, 2009 is
$12.6 million and the weighted average period over which this cost is expected
to be recognized is 1.6 years.
Other Employee Benefits - 401(k) Plan
The Company sponsors a
defined contribution thrift plan under section 401(k) of the Internal
Revenue Code to assist all employees in providing for retirement or other
future financial needs. In December 2005,
the 401(k) Plan was amended whereby effective January 1, 2006, the
Companys matching contribution is $1.00 for each $1.00 contributed by the
employee up to 8% of an employees eligible compensation. The Companys
contributions to the 401(k) Plan, net of forfeitures, were $1.4 million
for each of the years ended December 31, 2009, 2008 and 2007. Employees
are eligible to participate in the 401(k) Plan on their date of hire and
approximately 97% of the Companys employees participated in the 401(k) Plan
in 2009.
Director Deferred Compensation Plan
The Company established a
non-employee director deferred stock and compensation plan to permit eligible
directors, in recognition of their contributions to the Company, to receive
compensation for service and to defer recognition of their compensation in
whole or in part to a Stock Unit Account or an Interest Account. When the
eligible director ceases to be a director, the distribution from the Stock Unit
Account shall be made in shares using an established market value date. The
distribution from the Interest Account shall be made in cash. The plan may be
amended at any time, but not more than once every six months, by the
Compensation Committee or the Board of Directors. Shares earned and
deferred in accordance with the plan as of December 31, 2009, 2008 and
2007 were 124,686, 24,204 and 12,934, respectively.
Amounts allocated to the
Stock Unit Account have the right to receive an amount equal to the dividends
per share the Company declares as applicable. The dividend payment date and
this dividend equivalent shall be treated as reinvested in an additional
number of units and credited to their account using an established market value
date. Amounts allocated to the Interest Account are credited with interest at
an established interest rate.
12.
Concentration
of Credit Risks
Significant Customers
The Company sells oil, gas
and natural gas liquids to pipelines, refineries and oil companies and electricity
to utility companies. Credit is extended based on an evaluation of the customers
financial condition and historical payment record. The Company does not believe that the loss of
any one customer would impact the marketability, but it may impact the
profitability of its crude oil, gas, natural gas liquids or electricity sold.
Due to the possibility of refinery constraints in the Utah region, it is
possible that the loss of the crude oil sales customer could impact the
marketability of a portion of the Companys Utah crude oil volumes.
In
2009, sales to three purchasers were approximately 25%, 16% and 12%of the
Companys revenue. In 2008, sales to two
purchasers were approximately 60% and 11% of the Companys revenue. In 2007, sales to one purchaser was
approximately 68% of the Companys revenue.
29
Table of Contents
As
of both December 31, 2009 and 2008 the Company has an allowance for
doubtful accounts of $38.5 million, which represents the Companys November and
December 2008 sales to BWOC. While
the Company believes that it may recover some or all of the amounts due from
BWOC, the data received from the bankruptcy proceedings to date has not
provided the Company with any data from which to make a conclusion that any
amounts will be collected.
Concentrations of Market
Risk
The
future results of the Companys oil and gas operations will be affected by the
market prices of oil and gas. The
availability of a ready market for crude oil, natural gas and liquid products
in the future will depend on numerous factors beyond the Companys control,
including weather, imports, proximity and capacity of oil and gas pipelines and
other transportation facilities, any oversupply or undersupply of oil, gas and
liquid products, the regulatory environment, the economic environment, and
other regional and political events, none of which can be predicted with
certainty.
During 2009, the Company did
not have any credit losses on the sale of oil, natural gas, natural gas liquids
or hedging contracts. During 2008, the
Company experienced two credit losses related to its oil and natural gas sales. Included in bad debt expense in 2008 is $0.2
million related to the bankruptcy of SemGroup and $38.5 million related to BWOC
as described above. During 2007 the
Company did not have any credit losses on the sale of oil, natural gas, natural
gas liquids or hedging contracts.
The Company places its temporary
cash investments with high quality financial institutions and limit the amount
of credit exposure to any one financial institution. For the three years ended December 31,
2009, the Company has not incurred losses related to these investments.
Concentrations of Credit
Risk
Derivative financial
instruments that hedge the price of oil and gas and interest rate levels are
generally executed with major financial or commodities trading institutions
which expose us to market and credit risks and may, at times, be concentrated
with certain counterparties or groups of counterparties. As of December 31, 2009, $74 million of
the approximate net value of the Companys hedging positions of approximately
$97 million can be attributed to one of three counterparties. While a significant portion of its hedges are
with a small number of counterparties, the Company monitors each counterpartys
credit rating and CDS rate. Neither the
Company nor its counterparties are required to post collateral under the
Companys hedging contracts.
13.
Commitments
and Contingencies
The Companys contractual
obligations not included in its Balance Sheet as of December 31, 2009
(except Long-term debt and Abandonment obligations) are as follows (in
millions):
|
|
Total
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Long-term
debt and interest
|
|
$
|
1,359.7
|
|
$
|
71.9
|
|
$
|
71.9
|
|
$
|
437.3
|
|
$
|
62.6
|
|
$
|
485.7
|
|
$
|
230.3
|
|
Abandonment
obligations
|
|
43.5
|
|
2.8
|
|
2.8
|
|
2.9
|
|
2.9
|
|
2.8
|
|
29.3
|
|
Operating
lease obligations
|
|
16.0
|
|
2.4
|
|
2.4
|
|
2.5
|
|
2.5
|
|
2.5
|
|
3.7
|
|
Drilling
and rig obligations
|
|
52.1
|
|
13.9
|
|
27.7
|
|
2.1
|
|
2.1
|
|
6.3
|
|
|
|
Firm
natural gas transportation contracts
|
|
136.8
|
|
19.7
|
|
19.7
|
|
17.9
|
|
15.7
|
|
14.8
|
|
49.0
|
|
Total
|
|
$
|
1,608.1
|
|
$
|
110.7
|
|
$
|
124.5
|
|
$
|
462.7
|
|
$
|
85.8
|
|
$
|
512.1
|
|
$
|
312.3
|
|
Operating leases
The Company leases corporate
and field offices in California, Colorado and Texas. Rent expense with respect
to its lease commitments for the years ended December 31, 2009, 2008 and
2007 was $2.1 million, $1.7 million and $1.5 million, respectively. In 2006,
the Company purchased an airplane for business travel which was subsequently
sold and contracted under a ten year operating lease beginning December 2006.
30
Table of Contents
Drilling obligations
The
Company amended and restated its Utah Lake Canyon project in December 2009
and has a 14 gross well drilling commitment over the amended term (December 2009
to December 2014). The Companys
minimum obligation under its exploration and development agreement is $14.7
million as of December 31, 2009.
Also included above the Company has contractual obligations on its
Piceance assets in Colorado. The Company must spud 120 wells by February 2011
to avoid penalties of $0.2 million per well. The Company expects to meet
all obligations but its ability to meet this commitment depends on the capital
resources available to the Company to fund its activities to develop these
assets on the schedule required to avoid penalties or loss of related leases.
Other Commitments
On July 17, 2009, the Company closed on the
financing of its
E. Texas gas gathering system for $18.4 million in
cash. The Company entered into
concurrent long-term gas gathering agreements for the E. Texas production which
contained an embedded lease. There is no
minimum payment required under these agreements. For the year ended 2009, the Company has
incurred $2.0 million under the agreements.
On
June 17, 2009, the Company amended its natural gas firm transportation
agreement with Enbridge Pipelines providing for transportation of its gas from
Tex-OK to Orange County, Florida (Zone 1).
The agreement provides for minimum volume of 25,000 MMBtu/d and a maximum
volume of 55,000 MMBtu/D.
The
Company has 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. The Company pays a
demand charge for this capacity and its own production did not completely fill
that capacity. To maximize the utilization of its firm transportation, the
Company bought its partners share of the gas produced in the Piceance basin at
the market rate for that area and used its excess transportation to move this
gas to the sales point. The pre-tax net of its gas marketing revenue and
its gas marketing expense in the Statements of Operations is $1.6 million, $3.7
million and $0 for the years ended December 31, 2009, 2008 and 2007,
respectively.
In addition, Berry has
signed two precedent agreements 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. A
component of these agreements is currently in dispute and may result in a
termination of the contracts for capacity on this pipeline in which case the
Company will make alternative arrangements for the transportation and marketing
of the Companys production. The Company
does not believe the termination of these contracts will result in monetary
damages. Please see Item 1A. Risk Factors If third-party pipelines interconnected to our
natural gas wells and gathering facilities become partially or fully
unavailable to transport our natural gas, our results of operations and
financial condition could be adversely affected.
The
Company is a party to a crude oil sales contract through June 30, 2013
with a refiner for the purchase of a minimum of 5,000 Bbl/D of its Uinta light
crude oil. Pricing under the contract,
which includes transportation and gravity adjustments, is at a fixed percentage
of WTI. While the contractual
differentials under this contract may be less favorable at times than the
posted differential, demand for the Companys 40 degree black wax (light) crude
oil can vary seasonally and this contract provides a stable outlet for the
Companys crude oil. Gross oil production from the Companys Uinta properties
averaged approximately 2,700 Bbl/D in 2009.
Please see Item 1A. Risk FactorsWe
may not be able to deliver minimum crude oil volumes required by our sales
contract.
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 Companys California production. Included in the allowance for doubtful
accounts is $38.5 million due from BWOC. Of the $38.5 million due from BWOC,
$11.8 million represents 20 days of the Companys December 2008 crude oil
sales, an administrative claim under the bankruptcy proceedings, and $26.7 million
represents November 2008 and the balance of December 2008 crude oil
sales which would have the same priority as other general unsecured
claims. BWOC will also be liable to us
for damages under this contract. The
Company has guarantees from Big West Oil and from Flying J, Inc. in the
amount of $75 million each, in the event that the claim is not fully
collectible from BWOC. While the Company believes that it may recover some or
all of the amounts due from BWOC, the data received from the bankruptcy proceedings
to date has not provided the Company with adequate data from which to make a
conclusion that any amounts will be collected.
31
Table of Contents
The
Company has no material accrued environmental liabilities for its sites,
including sites in which governmental agencies have designated the Company 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. The Company is involved in various other lawsuits, claims and
inquiries, most of which are routine to the nature of its business. In the
opinion of management, the resolution of these matters will not have a material
effect on its financial position, or on the results of operations or liquidity.
Certain
of the Companys royalty payment calculations are being disputed. The Company believes that its royalty
calculations are in accordance with applicable leases and other
agreements. However, the disputed
amounts that it may be required to pay are up to approximately $6 million.
In July 2009, the Company received a
notice of proposed civil penalty from the Bureau of Land Management (BLM)
related to the Companys alleged non-compliance during 2007 with regulations
relating to the operation and position of certain valves in its Uinta basin
operations. The proposed civil penalty
was $69.6 million and reflects the theoretical maximum penalty amount under
applicable regulations, absent mitigating factors. In 2007 the Company immediately remediated
the instances of non-compliance, cooperated fully with the BLMs investigation
and the Company believes no production was lost, all royalties were paid and
there was no harm to the environment. Due to the above mitigating factors,
among others, the Company believes this matter will be resolved by the payment
of a penalty that will not exceed $2.1 million and accrued such amount in the
second quarter of 2009.
During the California energy crisis in 2000 and 2001, the Company had
electricity sales contracts with various utilities and a portion of the
electricity prices paid to the Company 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 the Company 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 adjustments to pricing under contracts with the
Company. 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.
As
of December 31, 2009, the Company had a gross liability for uncertain tax
benefits of $6.1 million and an additional $0.7 million of interest related to
its uncertain tax positions. At this time, the Company is unable to make a
reasonably reliable estimate of the timing of payments in individual years due
to uncertainties in the timing of tax audit outcomes; therefore, such amounts
are not included in the above contractual obligation table.
14.
Subsequent Events
The Company evaluates subsequent events through the
date the financial statements are issued, which for the annual period ended December 31,
2009, is February 25, 2010.
Effective
January, 2010, the Company has elected to de-designate all of its commodity and
interest rate contracts that had previously been designated as cash flow hedges
as of December 31, 2009 and have elected to discontinue hedge accounting
prospectively.
In January 2010, the Company
entered into an
agreement with a private seller to acquire interests in producing properties
principally in the Wolfberry trend in West Texas for approximately $126 million
in cash. The effective date of the transaction is January 1, 2010. Closing
is expected in March 2010.
In January 2010, the Company completed the sale
of 8,000,000 shares of its Class A Common Stock at $29.25 per share.
Net proceeds from the sale
of common stock, after deducting estimated underwriting discounts and
commissions and offering expenses, was $224.3 million. Net proceeds from the offering are expected
to be used to fund the planned acquisition of certain properties in the
Wolfberry trend of W. Texas and for general corporate purposes. Pending the
application of the proceeds for such purposes, the Company used the net
proceeds to reduce outstanding borrowings under its senior secured revolving
credit facility.
In
February 2010, the Company entered into an agreement with a private seller
to acquire interests in producing properties in the Wolfberry trend in W. Texas
for approximately $14 million cash.
32
Table of Contents
15.
Quarterly
Financial Data (Unaudited)
The following is a
tabulation of unaudited quarterly operating results for 2009 and 2008 (in
thousands, except per share data) and has been updated to reflect (1) the
presentation as discontinued operations of the Companys natural gas assets in
the Denver-Julesburg basin in Colorado (the DJ Basin assets), and (2) the
Companys implementation of authoritative guidance for determining whether
instruments granted in share-based payment transactions are participating
securities, which requires the revision of prior period basic and diluted
earnings per share data.
|
|
|
|
|
|
|
|
|
|
Basic Net
Income(Loss)
|
|
Basic Net
Income(Loss)
|
|
Diluted Net
Income(Loss)
|
|
Diluted Net
Income(Loss)
|
|
|
|
Operating
Revenues
|
|
Income (Loss)
From
Continuing
Operations
|
|
Income
(Loss) from
Discontinued
Operations
|
|
Net Income
(Loss)
|
|
From
Continuing
Operations
Per Share
|
|
From
Discontinued
Operations
Per Share
|
|
From
Continuing
Operations
Per Share
|
|
From
Discontinued
Operations Per
Share
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
145,720
|
|
$
|
41,779
|
|
$
|
(6,781
|
)
|
$
|
34,998
|
|
$
|
0.92
|
|
$
|
(0.15
|
)
|
$
|
0.92
|
|
$
|
(0.15
|
)
|
Second Quarter (1)
|
|
130,265
|
|
(12,768
|
)
|
(212
|
)
|
(12,980
|
)
|
(0.28
|
)
|
|
|
(0.28
|
)
|
|
|
Third Quarter
|
|
141,809
|
|
18,339
|
|
668
|
|
19,007
|
|
0.41
|
|
0.01
|
|
0.40
|
|
0.01
|
|
Fourth Quarter (2)
|
|
147,768
|
|
12,618
|
|
387
|
|
13,005
|
|
0.28
|
|
0.01
|
|
0.28
|
|
0.01
|
|
|
|
$
|
565,562
|
|
$
|
59,968
|
|
$
|
(5,938
|
)
|
$
|
54,030
|
|
$
|
1.31
|
|
$
|
(0.13
|
)
|
$
|
1.30
|
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
170,824
|
|
$
|
39,536
|
|
$
|
3,495
|
|
$
|
43,031
|
|
$
|
0.88
|
|
$
|
0.08
|
|
$
|
0.86
|
|
$
|
0.08
|
|
Second Quarter
|
|
197,532
|
|
43,712
|
|
5,429
|
|
49,141
|
|
0.97
|
|
0.12
|
|
0.95
|
|
0.12
|
|
Third Quarter
|
|
225,491
|
|
49,615
|
|
3,733
|
|
53,348
|
|
1.10
|
|
0.08
|
|
1.08
|
|
0.08
|
|
Fourth Quarter (3)
|
|
154,676
|
|
(11,087
|
)
|
(904
|
)
|
(11,991
|
)
|
(0.24
|
)
|
(0.02
|
)
|
(0.24
|
)
|
(0.02
|
)
|
|
|
$
|
748,523
|
|
$
|
121,776
|
|
$
|
11,753
|
|
$
|
133,529
|
|
$
|
2.70
|
|
$
|
0.26
|
|
$
|
2.66
|
|
$
|
0.26
|
|
(1) Includes an unrealized pre-tax non-cash loss
on derivatives of $31.1 million, a pre-tax charge of $10.5 million for debt
extinguishment costs and a liability for a regulatory compliance matter of $2.1
million.
(2) Included in the fourth quarter of 2009 are
adjustments to correct the prior accounting for the Companys royalties in the
amount of $3.3 million, which resulted in decreasing its sales of oil and gas
and increasing its royalties payable.
Management concluded the impact was immaterial to the current and prior
periods. Also included in the fourth
quarter of 2009 is an impairment charge of $4.2 million related to the
write-down of a rig.
(3) Includes $38.5 million of bad debt expense
related to the allowance for bad debt taken for the bankruptcy of BWOC.
33
Table of Contents
16.
Supplemental Information About Oil & Gas Producing Activities
(Unaudited)
In January 2010, the FASB
issued Accounting Standards Update (ASU) No. 2010-03
Extractive
Activities Oil and Gas (Topic) 932.
The ASU amends previously issued
authoritative guidance. The objective of
the amendments included in the ASU is to align the oil and gas reserves
estimation and disclosure requirements with the requirements of the Securities
and Exchange Commission (SEC). The new
guidance, among other purposes, is primarily intended to provide investors with
34
Table of Contents
a more meaningful and
comprehensive understanding of oil and gas producing activities, updating the
definition of proved oil and gas reserves to indicate that entities must use
the average, first-day-of-the-month price during the 12-month period before the
ending date of the period covered by the report, disclosing geographical areas
that represent a certain percentage of proved reserves, updating the reserve
estimation requirements for changes in practice and technology that have occurred
over the past several decades and requiring an entity to disclose separately
the amounts and quantities for consolidated and equity method investments. The Company has applied this guidance to its
Financial Statements for the year-ended December 31, 2009. The new oil and gas reserve measurement and
reporting requirements were adopted for oil and gas reserves as of December 31,
2009. For accounting purposes, the new requirements constitute a change
in accounting principle inseparable from a change in estimate. Prior
reserve disclosures were not modified and the impact of the new requirements on
our oil and gas reserves was reflected as a change in estimate. Changes
in reserves estimates are applied on a prospective basis.
The following sets forth
costs incurred for oil and gas property acquisition, development and
exploration activities, whether capitalized or expensed (in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Property acquisitions
|
|
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
$
|
13,497
|
|
$
|
667,996
|
|
$
|
|
|
Unproved
properties
|
|
|
|
|
|
56,247
|
|
Development (1)
|
|
138,168
|
|
385,599
|
|
278,398
|
|
Exploration
(2)
|
|
30,316
|
|
32,909
|
|
23,325
|
|
|
|
$
|
181,981
|
|
$
|
1,086,504
|
|
$
|
357,970
|
|
(1)
Development
costs include $4.9 million, $0.1 million and $1.2 million charged to expense
during 2009, 2008 and 2007, respectively.
(2)
Exploration costs include $0.2 million, $2.4 million
and $5.2 million that were charged to expense during 2009, 2008 and 2007,
respectively. Exploration costs include $30.1 million $23.2 million and $18.1 million
of capitalized interest in 2009, 2008 and 2007, respectively.
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent the Companys owned interests located solely within the
United States. Proved oil and gas
reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be
economically produciblefrom a given date forward, from known reservoirs, and
under existing economic conditions, operating methods, and government
regulationsprior to the time at which contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the
operator must be reasonably certain that it will commence the project within a
reasonable time. Proved developed are
proved reserves that can be expected to be recovered: (i) through existing
wells with existing equipment and operating methods or in which the cost of the
required equipment is relatively minor compared to the cost of a new well; and
(ii) through installed extraction equipment and infrastructure operational at the
time of the reserves estimate if the extraction is by means not involving a
well. Proved undeveloped reserves are
proved reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
For
the years ended December 31, 2009, 2008 and 2007 the Company engaged DeGolyer
and McNaughton (D&M) to estimate its proved oil and gas reserves and the
future net revenue to be derived from its properties. D&M is an independent petroleum
engineering consulting firm has provided consulting services throughout the
world for over 70 years.
Uncertainties
are inherent in estimating quantities of proved reserves, including many
factors beyond the Companys control. Reserve
engineering is a process of estimating subsurface accumulations of oil and gas
that cannot be measured in an exact manner, and the accuracy of any reserve
estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers
often vary, sometimes significantly. In
addition to the physical factors such as the results of drilling, testing, and
production subsequent to the date of an estimate, economic factors such as
changes in product prices or development and production expenses, may require
revision of such estimates. Accordingly,
oil and gas quantities ultimately recovered will vary from reserve
estimates. These estimates do not
include probable or possible reserves. The information provided does not
represent managements estimate of its expected future cash flows or value of
proved oil and gas reserves.
35
Table of Contents
Changes in estimated reserve quantities
The
net interest in estimated quantities of proved developed and undeveloped
reserves of crude oil and natural gas at December 31, 2009, 2008 and 2007,
and changes in such quantities during each of the years then ended were as
follows (in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
|
|
Mbbl
|
|
MMcf
|
|
MBOE
|
|
Mbbl
|
|
MMcf
|
|
MBOE
|
|
Mbbl
|
|
MMcf
|
|
MBOE
|
|
Proved
developed and Undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of year
|
|
125,251
|
|
724,135
|
|
245,940
|
|
116,602
|
|
315,464
|
|
169,179
|
|
112,538
|
|
226,363
|
|
150,262
|
|
Revision
of previous estimates
|
|
2,786
|
|
(34,564
|
)
|
(2,975
|
)
|
(10,211
|
)
|
(41,570
|
)
|
(17,139
|
)
|
(3,826
|
)
|
3,358
|
|
(3,262
|
)
|
Improved
recovery
|
|
|
|
|
|
|
|
7,600
|
|
|
|
7,600
|
|
4,500
|
|
|
|
4,500
|
|
Extensions
and discoveries
|
|
8,989
|
|
54,664
|
|
18,100
|
|
18,700
|
|
145,800
|
|
43,000
|
|
17,300
|
|
101,400
|
|
34,200
|
|
Property
sales
|
|
|
|
(126,600
|
)
|
(21,100
|
)
|
|
|
|
|
|
|
(6,700
|
)
|
|
|
(6,700
|
)
|
Production
|
|
(7,186
|
)
|
(22,657
|
)
|
(10,962
|
)
|
(7,440
|
)
|
(25,559
|
)
|
(11,700
|
)
|
(7,210
|
)
|
(15,657
|
)
|
(9,819
|
)
|
Purchase
of reserves in place
|
|
100
|
|
37,200
|
|
6,300
|
|
|
|
330,000
|
|
55,000
|
|
|
|
|
|
|
|
End
of year
|
|
129,940
|
|
632,178
|
|
235,303
|
|
125,251
|
|
724,135
|
|
245,940
|
|
116,602
|
|
315,464
|
|
169,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
of year
|
|
74,616
|
|
361,575
|
|
134,879
|
|
78,339
|
|
147,346
|
|
102,897
|
|
84,782
|
|
104,934
|
|
102,270
|
|
End
of year
|
|
82,870
|
|
255,520
|
|
125,456
|
|
74,616
|
|
361,575
|
|
134,879
|
|
78,339
|
|
147,346
|
|
102,897
|
|
The
standardized measure has been prepared using the average price during the 12
month period, determined as an unweighted average of the first-day-of-the-month
price for each month, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions, and year-end costs,
assuming statutory tax rates (adjusted for tax credits and other items), and a
ten percent annual discount rate
.
No deduction
has been made for depletion, depreciation or any indirect costs such as general
corporate overhead or interest expense. Cash outflows for future production and
development costs include those cash flows associated with the ultimate
settlement of the asset retirement obligation.
Excluding
the effect of production and property sales, reserves increased 21.5 million
BOE from 2008 to 2009. The reserves increased 18 million BOE from the
Companys drilling and completion activities and 6 million BOE from
acquisitions. The acquisition reserves
include the 6 million BOE purchase in the Piceance Basin. The 18 million BOE increase resulting from
the Companys drilling and completion activities were primarily at its
Diatomite fields in California and its fields in the Piceance Basin. Reserve revisions across the company resulted
in a decrease of 3 million BOE due to performance. Specifically, the decrease is attributable to
a 1 million BOE increase in California, a 5 million BOE increase in the
Rockies, offset by a 9 million BOE decrease in East Texas.
The
reserve sales of 21 million BOE resulted from the sale of the Companys DJ
basin reserves.
Standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves (in thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Future
cash inflows
|
|
$
|
9,028,991
|
|
$
|
7,384,692
|
|
$
|
11,211,151
|
|
Future
production costs
|
|
(3,826,832
|
)
|
(2,920,664
|
)
|
(3,275,397
|
)
|
Future
development costs
|
|
(1,159,465
|
)
|
(1,196,394
|
)
|
(812,070
|
)
|
Future
income tax expense
|
|
(969,771
|
)
|
(511,291
|
)
|
(2,286,296
|
)
|
Future
net cash flows
|
|
3,072,923
|
|
2,756,343
|
|
4,837,388
|
|
10%
annual discount for estimated timing of cash flows
|
|
(1,627,176
|
)
|
(1,620,762
|
)
|
(2,417,882
|
)
|
Standardized
measure of discounted future net cash flows
|
|
$
|
1,445,747
|
|
$
|
1,135,581
|
|
$
|
2,419,506
|
|
Average
sales prices at December 31: (a)
|
|
|
|
|
|
|
|
Oil
($/Bbl)
|
|
$
|
52.06
|
|
$
|
30.03
|
|
$
|
79.19
|
|
Gas
($/Mcf)
|
|
$
|
3.58
|
|
$
|
4.85
|
|
$
|
6.27
|
|
BOE
Price
|
|
$
|
38.37
|
|
$
|
30.92
|
|
$
|
66.27
|
|
(a)
The new SEC and FASB reserves reporting rules
require the use of 12-month average commodity prices effective for 2009,
instead of year-end commodity prices used in 2008 and 2007.
36
Table of Contents
Changes in standardized measure of
discounted future net cash flows from proved oil and gas reserves (in
thousands):
|
|
2009
|
|
2008
|
|
2007
|
|
Standardized
measure - beginning of year
|
|
$
|
1,135,581
|
|
$
|
2,419,506
|
|
$
|
1,182,268
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas produced, net of production costs
|
|
(353,052
|
)
|
(497,866
|
)
|
(326,174
|
)
|
Revisions
to estimates of proved reserves:
|
|
|
|
|
|
|
|
Net
changes in sales prices and production costs
|
|
637,882
|
|
(2,686,941
|
)
|
1,451,140
|
|
Revisions
of previous quantity estimates
|
|
(33,943
|
)
|
(144,466
|
)
|
(78,758
|
)
|
Improved
recovery
|
|
|
|
64,058
|
|
108,655
|
|
Extensions
and discoveries
|
|
206,542
|
|
362,435
|
|
825,775
|
|
Change
in estimated future development costs
|
|
(52,824
|
)
|
(352,061
|
)
|
(286,439
|
)
|
Purchases
of reserves in place
|
|
29,348
|
|
667,862
|
|
|
|
Sales
of reserves in place
|
|
(138,265
|
)
|
|
|
(98,680
|
)
|
Development
costs incurred during the period
|
|
110,200
|
|
173,184
|
|
132,002
|
|
Accretion
of discount
|
|
131,745
|
|
354,672
|
|
162,257
|
|
Income
taxes
|
|
(190,727
|
)
|
631,372
|
|
(687,103
|
)
|
Other
|
|
(36,740
|
)
|
143,826
|
|
34,563
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease)
|
|
310,166
|
|
(1,283,925
|
)
|
1,237,238
|
|
|
|
|
|
|
|
|
|
Standardized
measure - end of year
|
|
$
|
1,445,747
|
|
$
|
1,135,581
|
|
$
|
2,419,506
|
|
17.
Correction of Other Comprehensive Income (Loss)
The Company noted a
presentation error in the Statements of Comprehensive Income (Loss) and the
related disclosures in Note 3 to the audited financial statements contained in
the Companys Annual Report on Form 10-K for the year ended
December 31, 2009. The Company has concluded that the presentation error
was immaterial to the audited financial statements contained in the 2009
Form 10-K. The effects of the presentation error are summarized in the
tables below:
The components of
comprehensive income (loss):
|
|
For the twelve months ended
December 31, 2009
|
|
|
|
As Previously
Reported
|
|
As Revised (1)
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
54,030
|
|
$
|
54,030
|
|
Unrealized gains (losses)
on derivatives, net of income taxes
|
|
205,318
|
|
(129,287
|
)
|
Reclassification of
realized (gains) losses, net of income taxes
|
|
(31,249
|
)
|
(44,782
|
)
|
Comprehensive income
(loss)
|
|
$
|
228,099
|
|
$
|
(120,039
|
)
|
The table below contained in
Note 3 to the audited financial statements summarizes the impacts of the
Companys derivative instruments gains (losses) before income taxes reported in
the Statements of Income (Loss) and the Statement of Comprehensive Income
(Loss) for the twelve months ended December 31, 2009:
Previously Reported
Derivatives cash
flow hedging
relationships
|
|
Amount of Gain
(Loss) Recognized
in AOCL on
Derivative
(Effective portion)
|
|
Location of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)
|
|
Amount of Gain
(Loss)
Reclassified from
AOCL into
Income (Effective
Portion)
|
|
Location of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Amount of Gain (Loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Commodity - Oil
|
|
$
|
(222.3
|
)
|
Sales of oil and gas
|
|
$
|
53.9
|
|
Sales of oil and gas
|
|
$
|
|
|
Commodity - Natural Gas
|
|
(18.6
|
)
|
Sales of oil and gas
|
|
11.1
|
|
Gain (loss) on derivatives
|
|
13.7
|
|
Interest rate
|
|
8.8
|
|
Interest expense
|
|
(7.0
|
)
|
Gain (loss) on derivatives
|
|
|
|
Total
|
|
$
|
(232.1
|
)
|
|
|
$
|
58.0
|
|
|
|
$
|
13.7
|
|
Revised (2)
Derivatives cash
flow hedging
relationships
|
|
Amount of Gain
(Loss) Recognized
in AOCL on
Derivative
(Effective portion)
|
|
Location of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)
|
|
Amount of Gain
(Loss)
Reclassified from
AOCL into
Income (Effective
Portion)
|
|
Location of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Amount of Gain (Loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
|
|
Commodity - Oil
|
|
$
|
(219.3
|
)
|
Sales of oil and gas
|
|
$
|
53.9
|
|
Sales of oil and gas
|
|
$
|
|
|
Commodity - Natural Gas
|
|
12.9
|
|
Sales of oil and gas
|
|
25.4
|
|
Gain (loss) on derivatives
|
|
(0.6
|
)
|
Interest rate
|
|
(2.7
|
)
|
Interest expense
|
|
(7.0
|
)
|
Gain (loss) on derivatives
|
|
|
|
Total
|
|
$
|
(209.1
|
)
|
|
|
$
|
72.3
|
|
|
|
$
|
(0.6
|
)
|
(1) Revised amounts are reflected in the Statement
of Comprehensive Income (Loss) for the year ended December 31, 2009 within this
Form 10-K/A.
(2) Revised amounts are reflected in Note 3
to the financial statements within this Form 10-K/A.
37
Table of Contents
PART IV
Item 15.
Exhibits,
Financial Statement Schedules
A. Financial Statements and
Schedules
See
Item 8 Index to Financial Statements and Supplementary Data in this Form
10-K/A.
B. Exhibits
Exhibit No.
|
|
Description
of Exhibit
|
|
|
|
3.1*
|
|
Registrants Amended and
Restated Certificate of Incorporation (filed as Exhibit 3.1 to the
Registrants Quarterly Report on Form 10-Q for the period ended June 30,
2006, File No. 1-09735).
|
3.2*
|
|
Registrants Restated
Bylaws dated December 11, 2009 (filed as Exhibit 3.1 to the Registrants
Current Report on Form 8-K on December 11, 2009, File No. 1-09735).
|
4.1*
|
|
Form of Indenture between
Berry Petroleum Company and Wells Fargo Bank, National Association, as
Trustee (filed as Exhibit 4.3 to the Registrants Registration Statement on
Form S-3ASR on June 15, 2006, File No. 1-9735).
|
4.2*
|
|
First Supplemental
Indenture, dated as of October 24, 2006, between the Registrant and Wells
Fargo Bank, National Association as Trustee relating to the Registrants 8 1/4%
Senior Subordinated Notes due 2016 (filed as Exhibit 4.1 to the Registrants
Current Report on Form 8-K on October 25, 2006 File No. 1-9735).
|
4.3*
|
|
Registrants 8.25% Senior
Subordinated Notes (filed as Form 425B5 on October 19, 2006).
|
4.4*
|
|
Registrants Certificate
of Designation, Preferences and Rights of Series B Junior Participating
Preferred Stock (filed as Exhibit A to the Registrants Registration
Statement on Form 8-A12B on December 7, 1999, File No. 001-09735).
|
4.5*
|
|
Rights Agreement between
Registrant and ChaseMellon Shareholder Services, L.L.C. dated as of December
8, 1999 (filed by the Registrant on Form 8-A12B on December 7, 1999, File No.
001-09735).
|
4.6*
|
|
Registrants 10¼ % Senior
Notes due 2014 (filed as Form 425B5 on August 12, 2009)
|
4.7*
|
|
Indenture, dated June 15,
2006,between Berry Petroleum Company and Wells Fargo Bank, National
Association, as Trustee (filed as Exhibit 4.1 to the Registrants Current
Report on Form 8-K on May 29, 2009, File No. 1-09735)
|
4.8*
|
|
First Supplemental
Indenture, dated May 27, 2009, between Berry Petroleum Company and Wells
Fargo Bank, National Association, as Trustee (filed as Exhibit 4.2 to the
Registrants Current Report on Form 8-K on May 29, 2009, File No. 1-09735)
|
4.9*
|
|
Form of 10 ¼% Senior Notes
due 2014 (Included in Exhibit 4.2 to the Registrants Current Report on Form
8-K on May 29, 2009, File No. 1-09735)
|
10.1*
|
|
Instrument for Settlement
of Claims and Mutual Release by and among Registrant, Victory Oil Company,
the Crail Fund and Victory Holding Company effective October 31, 1986 (filed
as Exhibit 10.13 to Amendment No. 1 to the Registrants Registration
Statement on Form S-4 filed on May 22, 1987, File No. 33-13240).
|
10.2*
|
|
Description of Short-Term
Cash Incentive Plan of Registrant (filed as Exhibit 10.1 to the Registrants
Annual Report on Form 10-K for the period ended December 31, 2006, File
No. 1-9735).
|
10.3*
|
|
Form of Change in Control
Severance Protection Agreement dated August 24, 2006, by and between
Registrant and selected employees of the Company (filed as Exhibit 99.1 to
the Registrants Current Report on Form 8-K on August 24, 2006, File No.
1-9735).
|
10.4*
|
|
Amended and Restated 1994
Stock Option Plan (filed as Exhibit 4.1 to the Registrants Registration
Statement on Form S-8 filed on August 20, 2002, File No. 333-98379).
|
10.5*
|
|
First Amendment to the
Registrants Amended and Restated 1994 Stock Option Plan dated as of June 23,
2006 (filed as Exhibit 99.3 to the Registrants Current Report on Form 8-K
June 26, 2006, File No. 1-9735).
|
10.6*
|
|
Berry Petroleum Company
2005 Equity Incentive Plan (filed as Exhibit 4.2 to the Registrants Form S-8
filed on July 29, 2005, File No. 333-127018).
|
10.7*
|
|
Form of the Stock Option
Agreement, by and between Registrant and selected employees, directors, and
consultants (filed as Exhibit 4.3 to the Registrants Form S-8 filed on July
29, 2005, File No. 333-127018).
|
10.8*
|
|
Form of the Stock
Appreciation Rights Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 4.4 to the
Registrants Form S-8 filed on July 29, 2005, File No. 333-127018).
|
10.9*
|
|
Form of Stock Award
Agreement, by and between Registrant and selected employees, directors, and
consultants (filed as Exhibit 99.4 to the Registrants Current Report on Form
8-K June 26, 2006, File No. 1-9735).
|
10.10*
|
|
Form of Restricted Stock
Award Agreement, by and between Registrant and selected directors (filed as
Exhibit 99.1 on Form 8-K filed on December 17, 2007, File No. 1-9735).
|
10.11*
|
|
Form of Restricted Stock
Award Agreement, by and between Registrant and selected officers (filed as
|
38
Table of Contents
|
|
Exhibit 99.2on Form 8-K
December 17, 2007, File No. 1-9735).
|
10.12
|
|
Non-Employee Director
Deferred Stock and Compensation Plan (as amended and restated effective
November 19, 2008).
|
10.13*
|
|
Amended and Restated
Employment Contract dated as of June 23, 2006 by and between the Registrant
and Robert F. Heinemann (filed as Exhibit 99.1 to the Registrants Current
Report on Form 8-K June 26, 2006, File No. 1-9735).
|
10.14*
|
|
Stock Award Agreement
dated as of June 23, 2006 by and between the Registrant and Robert F. Heinemann
(filed as Exhibit 99.2 to the Registrants Current Report on Form 8-K June
26, 2006, File No. 1-9735).
|
10.15*
|
|
Employment Agreement dated
November 19, 2008 by and between Berry Petroleum Company and David D. Wolf
(Filed as Exhibit 10.1 in Registrants Form 8-K/A filed on November 21, 2008,
File No. 1-9735)
|
10.16*
|
|
Employment Agreement dated
November 19, 2008 by and between Berry Petroleum Company and Michael Duginski
(filed as Exhibit 10.1 in Registrants Form 8-K filed on November 21, 2008,
File No. 1-9735)
|
10.17*
|
|
Amended and Restated
Credit Agreement, dated as of July 15, 2008, by and between the Registrant
and Wells Fargo Bank, N.A. and other financial institutions (filed as Exhibit
10.1 to the Registrants Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2008, File No. 1-9735).
|
10.18*
|
|
Credit Agreement by and
among Berry Petroleum Company, Societe Generale, SG Americas Securities, LLC,
BNP Paribas Securities Corp., BNP Paribas, and other financial institutions
dated July 31, 2008 (filed as Exhibit 10.2 on Form 10-Q for the period ended
September 30, 2008, File No. 1-09735).
|
10.19*
|
|
First Amendment to Amended
and Restated Credit Agreement, by and between Berry Petroleum Company, Wells
Fargo Bank, N.A. and other financial institutions, dated as of October 17,
2008 (filed on October 17, 2008, as Exhibit 10.1 to the Registrants Current
Report on Form 8-K File No. 1-9735).
|
10.20*
|
|
Joinder Agreement dated
November 13, 2008 by and among Berry Petroleum Company, Wells Fargo Bank, N.A.,
and Bank of Montreal (filed as Exhibit 10.1in Registrants Form 8-K filed on
November 17, 2008, File No. 1-9735).
|
10.22*
|
|
Crude oil purchase
contract, dated November 14, 2005 between Registrant and Big West of
California, LLC (filed as Exhibit 99.2 on Form 8-K filed on November 22,
2005, File No. 1-9735).
|
10.21*
|
|
Joinder Agreement dated
December 2, 2008 by and among Berry Petroleum Company, Wells Fargo Bank,
N.A., and Calyon New York Branch (filed as Exhibit 10.1in Registrants Form
8-K filed on December 4, 2008, File No. 1-9735).
|
10.23* **
|
|
Carry and Earning
Agreement, dated June 7, 2006, between Registrant and EnCana Oil & Gas
(USA), Inc. (filed as Exhibit 99.2 on Form 8-K on June 19, 2006, File No.
1-9735).
|
10.24* **
|
|
Crude Oil Supply Agreement
between the Registrant and Holly Refining and Marketing Company - Woods Cross
(filed as Exhibit 10.22 to the Registrants Annual Report on Form 10-K for
the period ended December 31,2006, File No. 1-0735).
|
10.25*
|
|
Purchase and Sale
Agreement Between OBrien Resources, LLC, Sepco II, LLC, Liberty Energy, LLC,
Crow Horizons Company and OBenco II LP collectively as Seller and Berry
Petroleum Company as Purchaser, dated as of June 10, 2008 (filed as Exhibit
10.2 to the Registrants Quarterly Report on Form 10-Q for the period ended
June 30, 2008, File No. 1-9735).
|
10.26*
|
|
Overriding Royalty
Purchase Agreement between OBrien Resources, LLC, as Seller and Berry
Petroleum Company as Purchaser, dated as of June 10, 2008 (filed as Exhibit
10.3 to the Registrants Quarterly Report on Form 10-Q for the period ended
June 30, 2008, File No. 1-9735).
|
10.27*
|
|
Second Amendment to the
Amended and Restated Credit Agreement, dated as of February 19, 2009 (filed
as Exhibit 10.1 to the Registrants Current Report on Form 8-K on February
20, 2009, File No. 1-9735).
|
10.28 * **
|
|
Crude Oil Purchase
Contract dated March 20, 2009, between the Registrant and Tesoro Corporation
(filed as Exhibit 10.1 to the Registrants Quarterly Report on Form 10-Q for
the period ended March 31, 2009, File No. 1-09735)
|
10.29*
|
|
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 (filed as Exhibit 10.2
to the Registrants Quarterly Report on Form 10- for the period ended March
31, 2009, File No. 1-09735)
|
10.30*
|
|
Second Lien Credit
Agreement date April 27, 2009, among Registrant, Wells Fargo Energy Capital,
Inc., as administrative agent, and certain financial institutions, as Lenders
and agents (Filed as Exhibit 10.3 to the Registrants Quarterly Report on
Form 10- for the period ended March 31, 2009, File No. 1-09735)
|
10.31*
|
|
Underwriting
Agreement, dated May 21, 2009, by and between Registrant and Wachovia Capital
Markets, LLC, RBS Securities Inc., BNP Paribas Securities Corp., SG Americas
Securities, LLC and Calyon Securities (USA) Inc., (filed as Exhibit 1.1 to
the Registrants Current Report on Form 8-K on May 27, 2009, File No.
1-9735).
|
10.32*
|
|
Underwriting Agreement,
dated August 11, 2009, by and among Registrant and Wachovia Capital Markets,
LLC, RBS Securities Inc., BNP Paribas Securities Corp., SG Americas
Securities, LLC and Calyon Securities (USA) Inc., as representatives of the
underwriters named therein (filed as Exhibit 1.1 to the Registrants Current
Report on Form 8-K on August 13, 2009, File No. 1-9735).
|
39
Table of Contents
10.33*
**
|
|
Crude
Oil Purchase Contract dated September 24, 2009 between the Registrant and
ExxonMobil Oil Corporation (filed as Exhibit 10.2 to the Registrants
Quarterly Report on Form 10-Q for the period ended September 30, 2009, File
No. 1-9735).
|
10.34*
|
|
Underwriting Agreement
dated January 14, 2010 by and between Registrant and the several Underwriters
listed in Schedule 1 thereto (filed as Exhibit 1.1 to the Registrants
Current Report on Form 8-K on January 19, 2010, File No. 1-9735).
|
12.1
|
|
Ratio of Earnings to Fixed
Charges.
|
23.1
|
|
Consent of
PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
|
23.2
|
|
Consent of DeGolyer and
MacNaughton.
|
31.1
|
|
Certification of Chief
Executive Officer pursuant to SEC Rule 13(a)-14(a).
|
31.2
|
|
Certification of Chief
Financial Officer pursuant to SEC Rule 13(a)-14(a).
|
32.1
|
|
Certification of Chief
Executive Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the
U.S. Code.
|
32.2
|
|
Certification of Chief
Financial Officer pursuant to Section 1350 of Chapter 63 of Title 18 of the
U.S. Code.
|
99.1*
|
|
Form of Indemnity
Agreement of Registrant (filed as Exhibit 99.1 in Registrants Annual Report
on Form 10-K filed on March 31, 2005, File No. 1-9735).
|
99.2*
|
|
Form of B Group Trust
(filed as Exhibit 28.3 to Amendment No. 1 to Registrants Registration
Statement on Form S-4 filed on May 22, 1987, File No. 33-13240).
|
99.3
|
|
Report of DeGolyer and
MacNaughton dated February 19, 2010 regarding Registrants reserves
estimates.
|
*
|
Incorporated by reference
|
**
|
Portions of this exhibit
have been omitted pursuant to a request for confidential treatment
|
|
Previously filed as an exhibit to the
original Form 10-K filed on February 25, 2010
|
40
Table of Contents
Pursuant to the requirements
of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized on August 11, 2010.
|
BERRY PETROLEUM COMPANY
|
|
|
|
|
|
By:/s/
Jamie L. Wheat
|
|
|
JAMIE
L. WHEAT
|
|
|
Controller
|
|
|
(Principal
Accounting Officer)
|
|
41
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