Table of
Contents
UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-Q
x
Quarterly Report Pursuant to
Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended
June 30, 2010
o
Transition Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the transition period
from to
Commission file number
1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as
specified in its charter)
DELAWARE
|
|
77-0079387
|
(State of incorporation or
organization)
|
|
(I.R.S. Employer
Identification Number)
|
1999
Broadway, Suite 3700
Denver,
Colorado 80202
(Address of principal
executive offices, including zip code)
Registrants telephone
number, including area code:
(303) 999-4400
Indicate by check mark whether the registrant
(1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for
the past 90 days. YES
x
NO
o
Indicate by check mark whether the registrant has
submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to
Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant was required to
submit and post such files). YES
o
NO
o
Indicate by check mark whether the registrant is a
large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See definitions of large accelerated filer, accelerated
filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer
x
|
|
Accelerated filer
o
|
|
|
|
Non-accelerated filer
o
|
|
Smaller reporting company
o
|
Indicate by check mark whether the registrant is a
shell company (as defined in Rule 12b-2 of the Act). YES
o
NO
x
As of July 21, 2010, the registrant had
51,206,925 shares of Class A Common Stock ($.01 par value) outstanding.
The registrant also had 1,797,784 shares of Class B Stock ($.01 par value)
outstanding on July 21, 2010 all of which is held by an affiliate of the
registrant.
Table of Contents
BERRY PETROLEUM COMPANY
SECOND
QUARTER 2010 FORM 10-Q
TABLE OF
CONTENTS
2
Table of
Contents
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
June 30,
2010
|
|
December 31,
2009
|
|
ASSETS
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
239
|
|
$
|
5,311
|
|
Short-term investments
|
|
65
|
|
66
|
|
Accounts receivable, net
of allowance for doubtful accounts of $0 and $38,508, respectively
|
|
140,866
|
|
74,337
|
|
Deferred income taxes
|
|
4,006
|
|
5,623
|
|
Derivative instruments
|
|
7,557
|
|
11,527
|
|
Prepaid expenses and other
|
|
11,707
|
|
6,612
|
|
Total current assets
|
|
164,440
|
|
103,476
|
|
Oil and gas properties
(successful efforts basis), buildings and equipment, net
|
|
2,343,568
|
|
2,106,385
|
|
Derivative instruments
|
|
6,676
|
|
735
|
|
Other assets
|
|
26,398
|
|
29,539
|
|
|
|
$
|
2,541,082
|
|
$
|
2,240,135
|
|
LIABILITIES AND
SHAREHOLDERS EQUITY
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
78,902
|
|
$
|
63,096
|
|
Revenue and royalties
payable
|
|
23,234
|
|
25,878
|
|
Accrued liabilities
|
|
24,530
|
|
29,320
|
|
Line of credit
|
|
3,300
|
|
|
|
Derivative instruments
|
|
23,570
|
|
33,843
|
|
Total current liabilities
|
|
153,536
|
|
152,137
|
|
Long-term liabilities:
|
|
|
|
|
|
Deferred income taxes
|
|
302,065
|
|
237,161
|
|
Senior secured revolving
credit facility
|
|
310,000
|
|
372,000
|
|
8¼% Senior subordinated
notes due 2016
|
|
200,000
|
|
200,000
|
|
10¼% Senior notes due
2014, net of unamortized discount of $12,284 and $13,456, respectively
|
|
437,716
|
|
436,544
|
|
Asset retirement
obligation
|
|
49,313
|
|
43,487
|
|
Other long-term
liabilities
|
|
18,709
|
|
19,711
|
|
Derivative instruments
|
|
29,646
|
|
75,836
|
|
|
|
1,347,449
|
|
1,384,739
|
|
Shareholders equity:
|
|
|
|
|
|
Preferred stock, $.01 par
value, 2,000,000 shares authorized; no shares outstanding
|
|
|
|
|
|
Capital stock, $.01 par
value:
|
|
|
|
|
|
Class A Common Stock,
100,000,000 shares authorized; 51,206,925 and 42,952,499 shares issued
and outstanding, respectively
|
|
512
|
|
430
|
|
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
|
|
319,771
|
|
89,068
|
|
Accumulated other
comprehensive loss
|
|
(52,928
|
)
|
(60,372
|
)
|
Retained earnings
|
|
772,724
|
|
674,115
|
|
Total shareholders equity
|
|
1,040,097
|
|
703,259
|
|
|
|
$
|
2,541,082
|
|
$
|
2,240,135
|
|
The accompanying notes are
an integral part of these condensed financial statements.
3
Table of Contents
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income (Loss)
Three
Months Ended June 30, 2010 and 2009
(In
Thousands, Except Per Share Data)
|
|
Three months ended
June 30,
|
|
|
|
2010
|
|
2009
|
|
REVENUES AND OTHER INCOME
ITEMS
|
|
|
|
|
|
Sales of oil and gas
|
|
$
|
151,525
|
|
$
|
118,793
|
|
Sales of electricity
|
|
7,928
|
|
6,624
|
|
Gas marketing
|
|
5,004
|
|
4,848
|
|
Realized and unrealized
gain (loss) on derivatives, net
|
|
56,057
|
|
(31,130
|
)
|
Settlement of Flying J
bankruptcy claim
|
|
21,992
|
|
|
|
Interest and other income,
net
|
|
1,796
|
|
806
|
|
|
|
244,302
|
|
99,941
|
|
EXPENSES
|
|
|
|
|
|
Operating costs - oil and
gas production
|
|
46,452
|
|
34,738
|
|
Operating costs -
electricity generation
|
|
7,839
|
|
6,397
|
|
Production taxes
|
|
5,064
|
|
4,885
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
43,703
|
|
34,371
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
793
|
|
1,028
|
|
Gas marketing
|
|
4,357
|
|
4,232
|
|
General and administrative
|
|
12,155
|
|
13,164
|
|
Interest
|
|
16,340
|
|
10,589
|
|
Extinguishment of debt
|
|
|
|
10,492
|
|
Transaction costs on
acquisitions
|
|
1,908
|
|
|
|
Dry hole, abandonment,
impairment and exploration
|
|
266
|
|
17
|
|
Bad debt recovery
|
|
(38,508
|
)
|
|
|
|
|
100,369
|
|
119,913
|
|
Income (loss) before
income taxes
|
|
143,933
|
|
(19,972
|
)
|
Provision (benefit) for
income taxes
|
|
54,910
|
|
(7,204
|
)
|
Income (loss) from
continuing operations
|
|
89,023
|
|
(12,768
|
)
|
Loss from discontinued
operations, net of taxes
|
|
|
|
(212
|
)
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
89,023
|
|
$
|
(12,980
|
)
|
|
|
|
|
|
|
Basic net income (loss)
from continuing operations per share
|
|
$
|
1.65
|
|
$
|
(0.28
|
)
|
Basic net income (loss)
per share
|
|
$
|
1.65
|
|
$
|
(0.28
|
)
|
|
|
|
|
|
|
Diluted net income (loss)
from continuing operations per share
|
|
$
|
1.64
|
|
$
|
(0.28
|
)
|
Diluted net income (loss)
per share
|
|
$
|
1.64
|
|
$
|
(0.28
|
)
|
|
|
|
|
|
|
Dividends per share
|
|
$
|
0.075
|
|
$
|
0.075
|
|
Unaudited
Condensed Statements of Comprehensive Income (Loss)
Three
Months Ended June 30, 2010 and 2009
(In
Thousands)
Net income (loss)
|
|
$
|
89,023
|
|
$
|
(12,980
|
)
|
Unrealized losses on
derivatives, net of income taxes of $0 and ($44,776), respectively
|
|
|
|
(73,055
|
)
|
Reclassification of
realized gains on derivatives included in net income, net of income taxes of
$0 and ($5,708), respectively
|
|
|
|
(9,314
|
)
|
Accumulated other
comprehensive loss amortization of de-designated hedges, net of income taxes of
$2,478 and $0, respectively
|
|
4,044
|
|
|
|
Comprehensive income
(loss)
|
|
$
|
93,067
|
|
$
|
(95,349
|
)
|
The accompanying notes are
an integral part of these condensed financial statements.
4
Table of Contents
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income (Loss)
Six Months
Ended June 30, 2010 and 2009
(In
Thousands, Except Per Share Data)
|
|
Six months ended June 30,
|
|
|
|
2010
|
|
2009
|
|
REVENUES AND OTHER INCOME
ITEMS
|
|
|
|
|
|
Sales of oil and gas
|
|
$
|
299,332
|
|
$
|
246,662
|
|
Sales of electricity
|
|
17,861
|
|
16,895
|
|
Gas marketing
|
|
13,276
|
|
12,429
|
|
Realized and unrealized
gain on derivatives, net
|
|
57,661
|
|
6,034
|
|
Settlement of Flying J
bankruptcy claim
|
|
21,992
|
|
|
|
Interest and other income,
net
|
|
1,960
|
|
1,088
|
|
|
|
412,082
|
|
283,108
|
|
EXPENSES
|
|
|
|
|
|
Operating costs - oil and
gas production
|
|
93,488
|
|
72,122
|
|
Operating costs -
electricity generation
|
|
17,509
|
|
15,179
|
|
Production taxes
|
|
10,269
|
|
10,537
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
79,609
|
|
70,769
|
|
Depreciation, depletion &
amortization - electricity generation
|
|
1,588
|
|
1,987
|
|
Gas marketing
|
|
12,142
|
|
11,516
|
|
General and administrative
|
|
25,990
|
|
26,457
|
|
Interest
|
|
33,788
|
|
20,639
|
|
Extinguishment of debt
|
|
|
|
10,494
|
|
Transaction costs on
acquisitions
|
|
2,635
|
|
|
|
Dry hole, abandonment,
impairment and exploration
|
|
1,636
|
|
140
|
|
Bad debt recovery
|
|
(38,508
|
)
|
|
|
|
|
240,146
|
|
239,840
|
|
Income before income taxes
|
|
171,936
|
|
43,268
|
|
Provision for income taxes
|
|
65,244
|
|
14,258
|
|
Income from continuing
operations
|
|
106,692
|
|
29,010
|
|
Loss from discontinued
operations, net of taxes
|
|
|
|
(6,991
|
)
|
|
|
|
|
|
|
Net income
|
|
$
|
106,692
|
|
$
|
22,019
|
|
|
|
|
|
|
|
Basic net income from
continuing operations per share
|
|
$
|
2.01
|
|
$
|
0.63
|
|
Basic net loss from
discontinued operations per share
|
|
$
|
|
|
$
|
(0.15
|
)
|
Basic net income per share
|
|
$
|
2.01
|
|
$
|
0.48
|
|
|
|
|
|
|
|
Diluted net income from
continuing operations per share
|
|
$
|
2.00
|
|
$
|
0.63
|
|
Diluted net loss from
discontinued operations per share
|
|
$
|
|
|
$
|
(0.15
|
)
|
Diluted net income per
share
|
|
$
|
2.00
|
|
$
|
0.48
|
|
|
|
|
|
|
|
Dividends per share
|
|
$
|
0.15
|
|
$
|
0.15
|
|
Unaudited
Condensed Statements of Comprehensive Income (Loss)
Six Months
Ended June 30, 2010 and 2009
(In
Thousands)
Net income
|
|
$
|
106,692
|
|
$
|
22,019
|
|
Unrealized losses on
derivatives, net of income taxes of $0 and ($51,773), respectively
|
|
|
|
(84,472
|
)
|
Reclassification of
realized gains on derivatives included in net income, net of income taxes of
$0 and ($29,083), respectively
|
|
|
|
(47,452
|
)
|
Accumulated other
comprehensive loss amortization of de-designated hedges, net of income taxes of
$4,563 and $0, respectively
|
|
7,444
|
|
|
|
Comprehensive income
(loss)
|
|
$
|
114,136
|
|
$
|
(109,905
|
)
|
The accompanying notes are
an integral part of these condensed financial statements.
5
Table of Contents
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Six Months
Ended June 30, 2010 and 2009
(In
Thousands)
|
|
Six months ended June 30,
|
|
|
|
2010
|
|
2009
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
Net income
|
|
$
|
106,692
|
|
$
|
22,019
|
|
Depreciation, depletion
and amortization
|
|
81,197
|
|
74,944
|
|
Extinguishment of debt
|
|
|
|
10,494
|
|
Amortization of debt issue
costs and net discount
|
|
4,218
|
|
2,578
|
|
Dry hole and impairment
|
|
1,428
|
|
9,643
|
|
Unrealized (gain) loss on
derivatives
|
|
(46,110
|
)
|
8,287
|
|
Stock-based compensation
expense
|
|
5,008
|
|
4,980
|
|
Deferred income taxes
|
|
61,142
|
|
8,090
|
|
Loss on sale of oil and
natural gas properties
|
|
|
|
330
|
|
Other, net
|
|
|
|
(4,963
|
)
|
Cash paid for abandonment
|
|
(1,535
|
)
|
(176
|
)
|
Allowance for bad debt
|
|
(38,508
|
)
|
|
|
Change in book overdraft
|
|
2,007
|
|
(24,988
|
)
|
Increase in current assets
other than cash and cash equivalents
|
|
(33,176
|
)
|
(7,982
|
)
|
Decrease in current
liabilities other than book overdraft, line of credit and fair value of
derivatives
|
|
(7,494
|
)
|
(44,076
|
)
|
Net cash provided by
operating activities
|
|
134,869
|
|
59,180
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
Exploration and
development of oil and gas properties
|
|
(135,038
|
)
|
(73,126
|
)
|
Property acquisitions
|
|
(150,674
|
)
|
(11,668
|
)
|
Capitalized interest
|
|
(13,054
|
)
|
(12,626
|
)
|
Proceeds from sale of
assets
|
|
|
|
138,597
|
|
Net cash (used in)
provided by investing activities
|
|
(298,766
|
)
|
41,177
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
Proceeds from issuances on
line of credit
|
|
159,200
|
|
248,500
|
|
Payments on line of credit
|
|
(155,900
|
)
|
(273,800
|
)
|
Proceeds from issuance of
10¼% senior notes
|
|
|
|
304,025
|
|
Long-term borrowings under
credit facility
|
|
165,000
|
|
586,275
|
|
Repayments of long-term
borrowings under credit facility
|
|
(227,000
|
)
|
(937,176
|
)
|
Debt issue costs
|
|
|
|
(21,508
|
)
|
Financing obligation
|
|
(169
|
)
|
|
|
Dividends paid
|
|
(8,083
|
)
|
(6,831
|
)
|
Proceeds from issuance of
common stock, net
|
|
224,313
|
|
|
|
Proceeds from stock option
exercises
|
|
1,156
|
|
87
|
|
Excess tax benefit and
other
|
|
308
|
|
67
|
|
Net cash provided by (used
in) financing activities
|
|
158,825
|
|
(100,361
|
)
|
|
|
|
|
|
|
Net decrease in cash and
cash equivalents
|
|
(5,072
|
)
|
(4
|
)
|
Cash and cash equivalents
at beginning of year
|
|
5,311
|
|
240
|
|
Cash and cash equivalents
at end of period
|
|
$
|
239
|
|
$
|
236
|
|
The accompanying notes are
an integral part of these condensed financial statements.
6
Table of
Contents
Berry Petroleum Company
Notes to Condensed
Financial Statements
1.
Basis of Presentation
These Condensed Financial
Statements have been prepared in accordance with accounting principles
generally accepted in the United States of America (GAAP) for interim financial
reporting. All adjustments which are, in
the opinion of management, necessary to present fairly Berry Petroleum Companys
(the Company) financial position at June 30, 2010 and December 31,
2009 and results of operations and comprehensive income (loss) for the three
and six months ended June 30, 2010 and 2009, and its cash flows for the
six months ended June 30, 2010 and 2009 have been included. Interim
results are not necessarily indicative of expected annual results because of
the impact of fluctuations in prices received for oil and natural gas, as well
as other factors. In the course of
preparing the Condensed Financial Statements, management makes various
assumptions, judgments and estimates to determine the reported amounts of
assets, liabilities, revenues and expenses, and in the disclosures of
commitments and contingencies. Changes in these assumptions, judgments and
estimates will occur as a result of the passage of time and the occurrence of
future events, and, accordingly, actual results could differ from amounts
previously established.
The Companys Financial Statements have been
prepared on a basis consistent with the accounting principles and policies
reflected in the Companys audited financial statements as of and for the year
ended December 31, 2009. The
year-end Condensed Balance Sheet was derived from audited Financial Statements
included in such report, but does not include all disclosures required by GAAP. Certain prior period amounts have been
reclassified to properly conform to current period financial statement
classification and presentation requirements.
We have revised our Condensed Statement of Comprehensive Income (Loss)
to reflect the correction of a prior period presentation error. The Company has concluded that the
presentation error was immaterial to the previously filed financial
statements. See Note 14 to the Condensed
Financial Statements.
The Companys cash management
process provides for the daily funding of checks as they are presented to the
bank. Included in accounts payable at June 30, 2010 and December 31,
2009 is $17.7 million and $15.7 million, respectively, representing outstanding
checks in excess of the bank balance (book overdraft).
2.
Bad Debt Allowance
The
Company recognized $38.5 million in bad debt expense in the year ended December 31,
2008 related to Flying J, Inc., its wholly owned subsidiary Big West Oil,
LLC and its wholly owned subsidiary Big West of California, LLC (BWOC) filing
for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code
on December 22, 2008. On July 6, 2010, the Joint Plan of
Reorganization of Flying J, Inc., BWOC, Big West Oil, LLC, Big West
Transportation, LLC and Longhorn Partners Pipeline, L.P. was confirmed under
Chapter 11 of the United State Bankruptcy Code. Additionally, on July 6,
2010, the United States Bankruptcy Court approved and confirmed that certain June 15,
2010 Stipulation and Agreed Order (the Stipulation) with Flying J Inc. and
certain of its affiliates (collectively Flying J), regarding the resolution of
the Companys claim in Flying Js pending bankruptcy. Pursuant to the Stipulation, each of the
Company and Flying J agreed that the total amount owed to the Company by Flying
J was $60.5 million and, as a result, the Company received $60.5 million in
cash on July 23, 2010. In the
second quarter ended June 30, 2010, the Company recorded a settlement of
its Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5
million. See Notes 12 and 13 to the
Condensed Financial Statements.
3.
Fair
Value Measurements
The
authoritative guidance for fair value measurements 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. The Company utilizes a
mid-market pricing convention (the mid-point price between bid and ask prices)
for valuation as a practical expedient for assigning fair value. Oil swaps,
natural gas swaps and interest rate swaps are valued using models which are
based on active market data and are classified within Level 2 of the fair value
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. These
models are industry-standard models that consider various assumptions,
including quoted forward prices for commodities, time value, volatility factors
and current market and contractual prices for the underlying instruments, as
well as other relevant economic
7
Table of Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
measures. The fair value of all derivative instruments
are estimated using a combined income and market valuation methodology based
upon forward commodity price and volatility curves. The curves are obtained
from independent pricing services, and the Company has made no adjustments to
the obtained prices. The pricing
services publish observable market information from multiple brokers and
exchanges. No proprietary models are
used by the pricing services for the inputs.
All valuations were compared against counterparty valuations to verify
the reasonableness of prices. 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 Company recognizes transfers between levels at the end of the
reporting period for which the transfer has occurred.
The
following tables set forth by level within the fair value hierarchy the Companys
net derivative assets and liabilities that were measured at fair value on a
recurring basis as of June 30, 2010 and December 31, 2009.
Assets and liabilities measured at fair
value on a recurring basis
June 30, 2010 (in millions)
|
|
Total carrying value
on the Condensed Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
liability, net
|
|
$
|
(27.8
|
)
|
$
|
(23.8
|
)
|
$
|
(4.0
|
)
|
Interest rate derivatives liability, net
|
|
(11.2
|
)
|
(11.2
|
)
|
|
|
Total derivative
liabilities, net at fair value
|
|
$
|
(39.0
|
)
|
$
|
(35.0
|
)
|
$
|
(4.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 (in millions)
|
|
Total carrying value on the
Condensed Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
liability, net
|
|
$
|
(88.5
|
)
|
$
|
(62.5
|
)
|
$
|
(26.0
|
)
|
Interest rate derivatives liability, net
|
|
(8.9
|
)
|
(8.9
|
)
|
|
|
Total derivative
liabilities, net at fair value
|
|
$
|
(97.4
|
)
|
$
|
(71.4
|
)
|
$
|
(26.0
|
)
|
Changes in Level 3 fair value
measurements
The table below includes a
rollforward of the Condensed Balance Sheet amounts (including the change in
fair value) for financial instruments classified by the Company within Level 3
of the fair value hierarchy. When a determination is made to classify a
financial instrument within Level 3 of the fair value hierarchy, the
determination is based upon the significance of the unobservable factors to the
overall fair value measurement. Level 3 financial instruments typically
include, in addition to the unobservable or Level 3 components, observable
components (that is, components that are actively quoted and can be validated
to external sources).
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
|
(in millions)
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Fair value (liability) asset, beginning of period
|
|
$
|
(34.5
|
)
|
$
|
137.5
|
|
$
|
(26.0
|
)
|
$
|
172.5
|
|
Total realized and unrealized gain (loss) included
in Realized and unrealized gain
(loss) on derivatives
|
|
41.2
|
|
(31.1
|
)
|
41.9
|
|
6.0
|
|
Purchases, sales and settlements, net
|
|
(10.7
|
)
|
(63.3
|
)
|
(19.9
|
)
|
(138.8
|
)
|
Transfers in and/or out of Level 3
|
|
|
|
|
|
|
|
3.4
|
|
Fair value (liability) asset, end of period
|
|
$
|
(4.0
|
)
|
$
|
43.1
|
|
$
|
(4.0
|
)
|
$
|
43.1
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) included in income
related to financial assets and liabilities still on the Condensed
Balance Sheet at June 30, 2010 and 2009
|
|
$
|
30.5
|
|
$
|
(31.1
|
)
|
$
|
22.0
|
|
$
|
(8.3
|
)
|
The $3.4 million of transfers
out of Level 3 for the six months ended June 30, 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 4 to the Condensed Financial Statements.
8
Table of Contents
Berry Petroleum Company
Notes to Condensed 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 and could be at similar
rates today. 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.
|
|
As of
June 30, 2010
|
|
(in millions)
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
|
|
|
|
|
|
Line of credit
|
|
$
|
3
|
|
$
|
3
|
|
Senior secured revolving credit facility
|
|
310
|
|
310
|
|
8.25% Senior subordinated notes due 2016
|
|
200
|
|
194
|
|
10.25% Senior notes due 2014
|
|
438
|
|
481
|
|
|
|
$
|
951
|
|
$
|
988
|
|
|
|
As of December 31, 2009
|
|
(in millions)
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
|
|
|
|
|
|
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
|
|
4.
Derivative
Instruments
The Company uses financial
derivative instruments as part of its price risk management program to achieve
a more predictable, economic cash flow from its oil and natural gas production
by reducing its exposure to price fluctuations. The Company has entered into
financial commodity swap and collar contracts to fix the floor and ceiling
prices received for a portion of the Companys oil and natural gas production.
The terms of the 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. The
Company periodically enters into interest rate derivative agreements to protect
against changes in interest rates on its floating rate debt. For further
discussion related to the fair value of the Companys derivatives see Note 3 to
the Condensed Financial Statements.
As
of June 30, 2010, the Company had the following commodity derivatives:
|
|
2010
|
|
2011
|
|
2012
|
|
Oil Bbl/D:
|
|
15,930
|
|
12,020
|
|
6,000
|
|
Natural Gas MMBtu/D:
|
|
19,000
|
|
15,000
|
|
15,000
|
|
The
Company entered into the following crude oil two-way collars during the six
months ended June 30, 2010:
|
|
Average
|
|
|
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
Term
|
|
Per Day
|
|
Prices
|
|
Full year 2010
|
|
500
|
|
$75.00/$93.95
|
|
Full year 2010
|
|
500
|
|
$75.00/$94.45
|
|
Full year 2011
|
|
500
|
|
$75.00/$100.75
|
|
Full year 2011
|
|
500
|
|
$75.00/$101.15
|
|
Full year 2011
|
|
1,000
|
|
$75.00/$91.25
|
|
Full year 2012
|
|
500
|
|
$75.00/$105.00
|
|
Full year 2012
|
|
500
|
|
$75.00/$106.00
|
|
Full year 2012
|
|
1,000
|
|
$75.00/$95.00
|
|
9
Table of Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
The
Company entered into the following crude oil three-way collars during the six
months ended June 30, 2010:
|
|
Average
|
|
|
|
|
|
Barrels
|
|
Floor/Swap/Ceiling
|
|
Term
|
|
Per Day
|
|
Prices
|
|
Full year 2011
|
|
1,000
|
|
$60.00 / $80.00 / $101.00
|
|
Full year 2012
|
|
1,000
|
|
$60.00 / $80.00 / $120.00
|
|
The
Company entered into the following natural gas swaps during the six months
ended June 30, 2010:
|
|
Average
|
|
|
|
|
|
MMBtus
|
|
Swap
|
|
Term
|
|
Per Day
|
|
Prices
|
|
Full year 2011
|
|
5,000
|
|
$
|
5.50
|
|
Full year 2012
|
|
5,000
|
|
$
|
5.75
|
|
Discontinuance of cash flow hedge accounting
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 elected to de-designate all of its commodity and interest rate
derivative contracts that had been previously designated as cash flow hedges as
of December 31, 2009. As a result,
subsequent to December 31, 2009, the Company recognizes all gains and
losses from changes in commodity derivative fair values immediately in earnings
rather than deferring any such amounts in AOCL.
At
December 31, 2009, AOCL consisted of $97.4 million, ($60.4 million, net of
tax) of unrealized losses, representing the change in the fair value of the
Companys open commodity and interest rate derivative contracts designated as
cash flow hedges as of that balance sheet date, less any ineffectiveness
recognized. As a result of discontinuing
hedge accounting on January 1, 2010, such fair values at December 31,
2009 are frozen in AOCL as of the de-designation date and reclassified into
earnings as the original hedge transactions settle. During the three and six months ended June 30,
2010, $6.5 million ($4.0 million, net of tax) and $12.0 million ($7.4 million,
net of tax), respectively, of amortization of AOCL relating to de-designated
commodity and interest rate hedges were reclassified from AOCL into
earnings. As of June 30, 2010, AOCL
consisted of $85.4 million ($52.9 million, net of tax) of unrealized losses on
commodity and interest rate derivative contracts that had been previously
designated as cash flow hedges. The
Company expects to reclassify into earnings from AOCL after-tax net losses of
$28.2 million related to de-designated commodity and interest rate derivative
contracts during the next twelve months.
At
June 30, 2010, the net fair value derivative liability was $39.0 million
as compared to a net fair value liability of $97.4 million at December 31,
2009 which reflects changes in commodity prices and interest rates. Based on
NYMEX strip pricing as of June 30, 2010, the Company expects to make net
payments under the existing derivatives of $6.6 million during the next twelve
months.
The
related cash flow impact of all of the Companys derivatives is reflected in
cash flows from operating activities.
The
Company presents its derivative assets and liabilities on its Condensed 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.
10
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
The
following table disaggregates the Companys net derivative assets and
liabilities into gross components before giving effect to master netting
arrangements. Finally, the Company identifies the line items on its
Condensed Balance Sheets in which these fair value amounts are included. The gross asset and liability values in the
table below are segregated between those derivatives designated in qualifying
hedge accounting relationships and those not designated in hedge accounting
relationships.
|
|
As of June 30, 2010
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
(in millions)
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
designated as hedging instruments
|
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Current
assets
|
|
$
|
10.9
|
|
Current
liability
|
|
$
|
20.6
|
|
Commodity
|
|
Long
term assets
|
|
7.1
|
|
Long
term liabilities
|
|
25.2
|
|
Interest rate
|
|
|
|
|
|
Long
term assets
|
|
0.4
|
|
Interest rate
|
|
|
|
|
|
Current
assets
|
|
3.4
|
|
Interest rate
|
|
|
|
|
|
Current
liability
|
|
3.0
|
|
Interest rate
|
|
|
|
|
|
Long
term liabilities
|
|
4.4
|
|
Total derivatives not
designated as hedging instruments
|
|
|
|
$
|
18.0
|
|
|
|
$
|
57.0
|
|
Total derivatives
|
|
|
|
$
|
18.0
|
|
|
|
$
|
57.0
|
|
|
|
As of December 31, 2009
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
(in millions)
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Commodity
|
|
Current
assets
|
|
$
|
15.5
|
|
Current
liability
|
|
$
|
30.8
|
|
Commodity
|
|
Long
term assets
|
|
0.4
|
|
Long
term liabilities
|
|
74.1
|
|
Commodity
|
|
Current
liability
|
|
0.2
|
|
|
|
|
|
Commodity
|
|
Long
term liabilities
|
|
1.2
|
|
|
|
|
|
Interest rate
|
|
Long
term assets
|
|
0.3
|
|
Current
assets
|
|
3.5
|
|
Interest rate
|
|
|
|
|
|
Current
liabilities
|
|
2.7
|
|
Interest rate
|
|
|
|
|
|
Long
term liabilities
|
|
3.0
|
|
Total derivatives designated
as hedging instruments
|
|
|
|
$
|
17.6
|
|
|
|
$
|
114.1
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
|
|
$
|
|
|
Current
assets
|
|
$
|
0.4
|
|
Commodity
|
|
|
|
|
|
Current
liabilities
|
|
0.5
|
|
Total derivatives not
designated as hedging instruments
|
|
|
|
$
|
|
|
|
|
$
|
0.9
|
|
Total derivatives
|
|
|
|
$
|
17.6
|
|
|
|
$
|
115.0
|
|
11
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
The tables below summarize the location and the
amount of derivative instrument gains (losses) before income taxes reported in
the Condensed Statements of Income (Loss) for the periods indicated (in
millions):
|
|
Location of Gain (Loss)
|
|
Three months Ended June 30,
|
|
Derivatives cash flow hedging relationships
|
|
Recognized in Income
|
|
2010
|
|
2009
|
|
Commodity
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
|
|
$
|
(146.5
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
(4.1
|
)
|
16.6
|
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
(22.6
|
)
|
Interest rate
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
|
|
$
|
5.9
|
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(2.4
|
)
|
(1.5
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
(0.3
|
)
|
|
|
Location of Gain (Loss)
|
|
Six Months Ended June 30,
|
|
Derivatives cash flow hedging relationships
|
|
Recognized in Income
|
|
2010
|
|
2009(1)
|
|
Commodity
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
|
|
$
|
(138.3
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
(6.9
|
)
|
79.1
|
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
0.3
|
|
Interest rate
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
|
|
$
|
2.1
|
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(5.1
|
)
|
(2.5
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
(0.3
|
)
|
(1) Prior year amounts have been revised. S
ee Note 14 to the Condensed Financial
Statements.
Amount of gain or (loss) recognized in income on
derivatives not designated as hedging instruments under authoritative guidance
for the periods indicated (in millions):
Derivatives not designated as Hedging
|
|
Location of Gain (Loss)
|
|
Three Months Ended June 30,
|
|
Instruments under authoritative guidance
|
|
Recognized in Income
|
|
2010
|
|
2009
|
|
Commodity
|
|
Realized
and unrealized gain (loss) on derivatives, net
|
|
$
|
58.8
|
|
$
|
(8.5
|
)
|
Interest Rates
|
|
Realized
and unrealized gain (loss) on derivatives, net
|
|
(2.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as Hedging
|
|
Location of Gain (Loss)
|
|
Six Months Ended June 30,
|
|
Instruments under authoritative guidance
|
|
Recognized in Income
|
|
2010
|
|
2009
|
|
Commodity
|
|
Realized and unrealized
gain (loss) on derivatives, net
|
|
$
|
63.7
|
|
$
|
(8.3
|
)
|
Commodity
|
|
Loss
from discontinued operations, net of taxes
|
|
|
|
(0.5
|
)
|
Interest Rates
|
|
Realized
and unrealized gain (loss) on derivatives, net
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
Credit risk
The
Company does not require collateral or other security from counterparties to
support derivative instruments. However, the agreements with those
counterparties typically contain netting provisions such that if a default
occurs, the non-defaulting party can offset the amount payable to the
defaulting party under the derivative contract with the amount due from the
defaulting party. As a result of the netting provisions the Companys maximum
amount of loss due to credit risk is limited to the net amounts due to and from
the counterparties under the derivative contracts. The maximum amount of loss
due to credit risk that the Company would have incurred if all counterparties to its derivative contracts
failed to perform at June 30, 2010 was $14.2 million. The credit rating of each of the
counterparties was AA-/Aa3, or better as of June 30, 2010. As of June 30, 2010, the Companys
largest three counterparties accounted for 93% of the value of its total
derivative positions.
As of June 30, 2010,
the counterparties to the Companys commodity derivative contracts consist of
nine financial institutions. The Companys counterparties or their affiliates
are generally also lenders under the Companys senior revolving credit
facility. As a result, the counterparties to the Companys derivative
agreements share in the collateral supporting the Companys senior revolving
credit facility. The Company is not generally required to post additional
collateral under derivative agreements.
Certain of the Companys
derivative agreements contain provisions that require cross defaults and
acceleration of those instruments to any material debt. If the Company was to
default on any of its material debt agreements, it would be a violation of
these provisions, and the counterparties to the derivative instruments could
request immediate payment on derivative instruments that are in a net liability
position at that time. As of June 30, 2010, the Company was in a net
liability position with six of the counterparties to the Companys derivative
instruments, totaling $53.2 million.
5
.
Shareholders
Equity
In January 2010, the Company issued 8,000,000
shares of Class A Common Stock at a price of $29.25 per share. Net
proceeds from this offering were $224.3 million after deducting
underwriting discounts and commissions and offering expenses. The Company used the
net proceeds from the offering to fund the purchase of the March Acquisition
(as defined below) and to repay a portion of the outstanding borrowings under
the senior secured revolving credit facility.
See Note 6 to the Condensed Financial Statements.
6
.
Acquisitions
and Divestitures
In
March 2010, the Company acquired interests in producing properties
principally on 6,900 net acres in the Permian basin of West Texas (W. Texas)
for $133 million, comprised of an initial purchase price of $126 million, and
customary post-closing adjustments of approximately $7 million (the March Acquisition). The March Acquisition was financed with
the proceeds from the issuance of the Companys common stock in January of
2010. In April 2010, the Company
closed on the acquisition of an additional 3,200 net acres in the Permian basin
for approximately $14 million,
including normal post closing adjustments (the April Acquisition and,
together with the March Acquisition, the Permian Basin Acquisitions). The Permian Basin Acquisitions included
properties with total proved reserves of approximately 13 MMBOE, of which 83% were crude oil and 21% were proved developed.
13
Table of Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
The
Permian Basin Acquisitions qualify as business combinations and, as such, the
Company estimated the fair value of each property as of the acquisition date
(the date on which the Company obtained control of the properties). The fair value is the price that would be
received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date. Fair value measurements also utilize
assumptions of market participants. The
Company used a discounted cash flow model and made market assumptions as to
future commodity prices, projections of estimated quantities of oil and natural
gas reserves, expectations for timing and amount of future development and
operating costs, projections of future rates of production, expected recovery
rates and risk adjusted discount rates.
These assumptions represent Level 3 inputs.
The
following table summarizes the consideration paid to the seller and the amounts
of the assets acquired and liabilities assumed in the March Acquisition. The purchase price allocation is preliminary
and subject to customary adjustments.
|
|
(In thousands)
|
|
Consideration paid to seller:
|
|
|
|
Cash consideration
|
|
$
|
133,313
|
|
|
|
|
|
Recognized amounts of
identifiable assets acquired and liabilities assumed:
|
|
|
|
Proved developed and undeveloped properties
|
|
134,559
|
|
Fair value of derivatives
|
|
316
|
|
Asset retirement obligation
|
|
(1,367
|
)
|
Other liabilities assumed
|
|
(195
|
)
|
|
|
|
|
Total identifiable net assets
|
|
$
|
133,313
|
|
The
March Acquisition had an effective date of January 1, 2010, and
activity from January 1, 2010 through March 4, 2010 was treated as
purchase price adjustments. The
preliminary purchase price allocation included an estimate for activity between
January 1, 2010 and March 4, 2010; however, actual amounts were
greater than the Companys estimate which resulted in an increase to the total
cash consideration paid to the seller.
As a result, the initial $1.4 million of Gain on purchase of oil and
natural gas properties recorded in the first quarter of 2010 has been reversed
in the second quarter of 2010 to reflect the purchase price adjustments.
The
following table summarizes the consideration paid to the seller and the amounts
of the assets acquired and liabilities assumed in the April Acquisition. The preliminary purchase price allocation is
subject to customary adjustments and includes $1.6 million that remains in
escrow pending the resolution of certain obligations of the seller that have
not yet been satisfied.
|
|
(In thousands)
|
|
Consideration paid to seller:
|
|
|
|
Cash consideration
|
|
$
|
14,250
|
|
|
|
|
|
Recognized amounts of
identifiable assets acquired and liabilities assumed:
|
|
|
|
Proved developed and undeveloped properties
|
|
16,192
|
|
Asset retirement obligation
|
|
(1,942
|
)
|
|
|
|
|
Total identifiable net assets
|
|
$
|
14,250
|
|
Acquisition
costs of $0.5 million and $2.6 million have been recorded in the Condensed
Statements of Income (Loss) under the caption Transaction costs on acquisitions
in the three and six months ended June 30, 2010, respectively. Revenues of $6.6 million and $8.7 million
generated by the acquired properties have been included in the accompanying
Condensed Statements of Income (Loss) in the three and six months ended June 30,
2010, respectively. Earnings of $1.1
million and $1.6 million generated by the Permian Basin Aquisitions have been
included in the accompanying Condensed Statements of Income (Loss) in the three
and six months ended June 30, 2010, respectively.
Divestitures
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 reflected within
the $7.0 million Loss from discontinued operations, net of taxes, on its
Condensed Statement of Income (Loss) for the six months ended June 30,
2009.
14
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
Loss
from discontinued operations, net of taxes, on the accompanying Condensed
Statements of Income (Loss) is comprised of the following (in thousands):
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
|
|
$
|
(330
|
)
|
$
|
|
|
$
|
5,689
|
|
Total expenses
|
|
|
|
|
|
|
|
16,283
|
|
Loss from discontinued
operations, before income taxes
|
|
|
|
(330
|
)
|
|
|
(10,594
|
)
|
Income tax benefit
|
|
|
|
118
|
|
|
|
3,603
|
|
Loss from discontinued
operations, net of taxes
|
|
$
|
|
|
$
|
(212
|
)
|
$
|
|
|
$
|
(6,991
|
)
|
7.
Dry hole, abandonment, impairment and
exploration
During the three and six months ended June 30,
2010, the Company incurred dry hole, abandonment, impairment and exploration
expense of $0.3 million and $1.6 million, respectively, which was primarily a
result of mechanical failure encountered on one well in the Piceance basin. The
well was abandoned in favor of drilling a replacement well from the same well
pad. During the three months ended June 30,
2009, the Company did not incur any dry hole, abandonment, impairment and
exploration expense. During the six
months ended June 30, 2009 the Company had dry hole, abandonment,
impairment and exploration charges of $0.1 million.
8
.
Asset Retirement Obligation (ARO)
The following table summarizes the change in the ARO
for the six months ended June 30 (in thousands):
|
|
2010
|
|
2009
|
|
Beginning balance at
January 1
|
|
$
|
43,487
|
|
$
|
41,967
|
|
Liabilities incurred
|
|
1,860
|
|
|
|
Liabilities settled
|
|
(1,534
|
)
|
(175
|
)
|
Liabilities assumed
|
|
3,309
|
|
|
|
Disposition of assets
|
|
|
|
(2,752
|
)
|
Accretion expense
|
|
2,191
|
|
1,946
|
|
Ending balance at
June 30
|
|
$
|
49,313
|
|
$
|
40,986
|
|
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.
9.
Debt Obligations
Short-term line of credit
Borrowings
under the Companys senior secured money market line of credit (the Secured
Line of Credit) may be up to $30 million for a maximum of 30 days. The Secured Line of Credit may be terminated
at any time upon written notice by either the Company or the lender.
There was $3.3 million outstanding on the Secured
Line of Credit at June 30, 2010 and no outstanding borrowings at
December 31, 2009. 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 Secured Line of Credit at June 30, 2010 and
December 31, 2009 was 1.8% and 0%, respectively.
15
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
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:
|
|
2010
|
|
Thereafter
|
|
to Sep 2010
|
|
Mar 2011
|
|
Sep 2011
|
|
Thereafter
|
|
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
Agreement also contains a current ratio covenant which, as defined, must be at
least 1.0. The total outstanding debt at
June 30, 2010 under the Agreement, as amended, and the Secured Line of
Credit was $310 million and $3 million, respectively, and $24 million in
letters of credit have been issued under the facility, leaving $601 million in
borrowing capacity available under the Agreement. 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 Companys borrowing base of $938 million
was reconfirmed in April 2010.
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 semi-annually 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 Condensed 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.
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 Condensed 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 $125
million Notes.
The $125 million Notes and the $325 million Notes
are treated as a single series of debt securities and are carried on the
Condensed 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 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
Agreement contains restrictive covenants as described above. Under the Companys Notes and Sub 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 June 30, 2010.
|
|
As of June 30, 2010
|
|
Current Ratio (Not less
than 1.0)
|
|
6.0
|
|
Total Funded Debt Ratio to
EBITDAX (Not greater than 4.50)
|
|
2.8
|
|
Interest Coverage Ratio
(Not less than 2.5)
|
|
4.1
|
|
Senior Secured Debt Ratio
to EBITDAX (Not greater than 3.75)
|
|
0.9
|
|
16
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial Statements
The
weighted average interest rate on the Companys total outstanding borrowings
was 7.3% and 7.0% at June 30, 2010 and December 31, 2009,
respectively.
10.
Income
Taxes
The effective income tax rate for the three months
ended June 30, 2010 and 2009 was 38.1% and 36.1%, respectively. The effective income tax rate was 37.9% and
33.0% for the six months ended June 30, 2010 and 2009, respectively. The increase in rate is primarily due to a
one-time reduction in state deferred rates and uncertain tax positions in the
prior periods. Reductions in the rate
during the prior periods were the result of acquisitions in more tax favorable
jurisdictions that reduced future state tax obligations, as well as favorable
state tax incentives. The Companys
estimated annual effective tax rate varies from the 35% federal statutory rate
due to the effects of state income taxes and estimated permanent differences.
As of June 30, 2010, the Company had a gross
liability for uncertain tax benefits of $5.3 million all of which, if
recognized, would affect the effective tax rate. Gross uncertain tax positions
were reduced due to new evaluations of tax positions claimed. There were no
significant changes to the calculation since December 31, 2009. 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 of interest related to its uncertain tax
positions as of both June 30, 2010 and December 31, 2009.
11.
Earnings
per Share
Basic
net income per common share is calculated by dividing adjusted net income
available to common shareholders by the weighted average number of common
shares outstanding during each period. Diluted net income per common
share is calculated by dividing adjusted net income by the weighted average
number of diluted common shares outstanding, which includes the effect of
potentially dilutive securities. Potentially dilutive securities for
the diluted earnings per share calculations consist of unvested restricted
stock awards and outstanding stock options using the treasury
method. When a loss exists, all potentially dilutive securities are
anti-dilutive and are therefore excluded from the computation of diluted
earnings per share accordingly.
The
two-class method of computing earnings per share is required for those entities
that have participating securities. The two-class method is an earnings
allocation formula that determines earnings per share for participating
securities according to dividends declared (or accumulated) and participation
rights in undistributed earnings.
Restricted stock issued prior to January 1, 2010 under the Companys
stock incentive plans has the right to receive non-forfeitable dividends,
participating on an equal basis with common stock. Restricted stock issued
subsequent to January 1, 2010 under the Companys stock incentive plans no
longer has the right to receive non-forfeitable dividends. Therefore, unvested restricted stock issued
prior to January 1, 2010 must be allocated to both common stock and these
participating securities under the two-class method. Stock units issued to directors under the
Companys nonemployee directors deferred compensation plan also have the right
to be credited with non-forfeitable dividends, participating on an equal basis
with common stock. Stock options issued
under the Companys stock incentive plans do not participate in dividends.
17
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
The
following table shows the computation of basic and diluted net income (loss)
per share from continuing and discontinued operations for the three and six
months ended June 30, 2010 and 2009 (in thousands):
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Net income (loss) from
continuing operations
|
|
$
|
89,023
|
|
$
|
(12,768
|
)
|
$
|
106,692
|
|
$
|
29,010
|
|
Less: Income allocable to
participating securities
|
|
1,713
|
|
|
|
2,133
|
|
712
|
|
Income (loss) available
for shareholders
|
|
$
|
87,310
|
|
$
|
(12,768
|
)
|
$
|
104,559
|
|
$
|
28,298
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued
operations
|
|
$
|
|
|
$
|
(212
|
)
|
$
|
|
|
$
|
(6,991
|
)
|
Less: Income allocable to
participating securities
|
|
|
|
|
|
|
|
|
|
Loss from discontinued
operations available for shareholders
|
|
$
|
|
|
$
|
(212
|
)
|
$
|
|
|
$
|
(6,991
|
)
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per
share from continuing operations
|
|
$
|
1.65
|
|
$
|
(0.28
|
)
|
$
|
2.01
|
|
$
|
0.63
|
|
Basic loss per share from
discontinued operations
|
|
|
|
|
|
|
|
(0.15
|
)
|
Basic earnings (loss) per
share
|
|
$
|
1.65
|
|
$
|
(0.28
|
)
|
$
|
2.01
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss)
per share from continuing operations
|
|
$
|
1.64
|
|
$
|
(0.28
|
)
|
$
|
2.00
|
|
$
|
0.63
|
|
Diluted loss per share
from discontinued operations
|
|
|
|
|
|
|
|
(0.15
|
)
|
Diluted earnings (loss)
per share
|
|
$
|
1.64
|
|
$
|
(0.28
|
)
|
2.00
|
|
$
|
0.48
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic
|
|
52,965
|
|
44,606
|
|
52,027
|
|
44,594
|
|
Add: Dilutive effects of
stock options and RSUs
|
|
448
|
|
206
|
|
380
|
|
126
|
|
Weighted average shares
outstanding - dilutive
|
|
53,413
|
|
44,812
|
|
52,407
|
|
44,720
|
|
Options
to purchase 0.8 million and 1.2 million shares were not included in the diluted
earnings per share calculation for the three and six months ended June 30,
2010, respectively, because their effect would have been anti-dilutive. Options to purchase 1.7 million and 1.9
million shares were not included in the diluted earnings (loss) per share
calculation for the three and six months ended June 30, 2009,
respectively, because their effect would have been anti-dilutive.
12.
Commitments
and Contingencies
The Companys contractual obligations not included
in its Condensed Balance Sheet as of June 30, 2010 (except Long-term debt
and Asset retirement obligations) are as follows (in millions):
|
|
Total
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Long-term debt and
interest
|
|
$
|
1,264.6
|
|
$
|
38.6
|
|
$
|
70.5
|
|
$
|
376.9
|
|
$
|
62.6
|
|
$
|
485.7
|
|
$
|
230.3
|
|
Asset retirement
obligation
|
|
49.3
|
|
1.0
|
|
2.9
|
|
2.8
|
|
2.8
|
|
2.9
|
|
36.9
|
|
Operating lease obligations
|
|
15.3
|
|
1.2
|
|
2.6
|
|
2.6
|
|
2.6
|
|
2.6
|
|
3.7
|
|
Drilling and rig
obligations
|
|
31.5
|
|
6.0
|
|
25.5
|
|
|
|
|
|
|
|
|
|
Firm natural gas
transportation contracts
|
|
126.7
|
|
9.9
|
|
19.7
|
|
17.6
|
|
15.7
|
|
14.8
|
|
49.0
|
|
Total
|
|
$
|
1,487.4
|
|
$
|
56.7
|
|
$
|
121.2
|
|
$
|
399.9
|
|
$
|
83.7
|
|
$
|
506.0
|
|
$
|
319.9
|
|
Operating leases
The Company leases corporate and field offices in
California, Colorado and Texas. Rent expense with respect to its lease
commitments was $0.6 million for both the three months ended June 30, 2010
and 2009 and was $1.1 million for both the six months ended June 30, 2010
and 2009.
In 2006, the Company purchased a corporate aircraft
which was subsequently sold and contracted under a ten year operating lease
beginning December 2006.
18
Table of
Contents
Berry Petroleum Company
Notes to Condensed
Financial Statements
Drilling obligations
Included in the table above
are the Companys contractual obligations on its Piceance assets in
Colorado. As of June 30, 2010, the Company must spud additional
wells of its original 120 wells commitment by February 2011 to avoid
penalties of $0.2 million per well. The Companys satisfying this
commitment and further developing these assets depends on Piceance
infrastructure and access, drilling resources, including capital availability,
and other factors, all of which will be further evaluated throughout the
remainder of 2010.
Firm natural gas
transportation
In July 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 three months ended June 30,
2010 and 2009, the Company incurred $1.5 and $0, respectively, under the
agreements. For the six months ended June 30,
2010 and 2009, the Company incurred $2.6 million and $0, respectively, under
the agreements.
In
June 2009, the Company amended its natural gas firm transportation
agreement 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 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 Condensed Statements of Income (Loss) is $0.6 million for both
the three months ended June 30, 2010 and 2009. The pre-tax net of its gas
marketing revenue and its gas marketing expense in the Condensed Statements of
Income (Loss) is $1.1 million and $0.9 million for the six months ended June 30,
2010 and 2009, respectively.
Berry has signed firm transportation service agreements
with El Paso Corporation for an average total of 35,000 MMBtu/D of firm
transportation on the proposed Ruby Pipeline from Opal, WY to Malin, OR. The expectation is that the project will
proceed and be in service in 2011.
Other commitments
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 2,720 Bbl/D in the first six months of 2010.
In
December 2008, Flying J, Inc., 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. The Company has settled its
claim in the Flying J bankruptcy and received a payment of $60.5 million on July 23,
2010. See Note 13 to the Condensed
Financial Statements.
19
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial
Statements
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, 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 the Company 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 California Public Utilities
Commission (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.
13.
Subsequent
Events
On July 6, 2010, the Joint Plan of
Reorganization of Flying J, Inc., BWOC, Big West Oil, LLC, Big West
Transportation, LLC and Longhorn Partners Pipeline, L.P. was confirmed under
Chapter 11 of the United State Bankruptcy Code.
In addition, the
United States Bankruptcy Court approved and confirmed that certain June 15,
2010 Stipulation and Agreed Order (the Stipulation) with Flying J Inc. and
certain of its affiliates (collectively Flying J), regarding the resolution of
the Companys claim in Flying Js pending bankruptcy. Pursuant to the Stipulation, each of the
Company and Flying J agreed that the total amount owed to the Company by Flying
J arising out of Flying Js voluntary bankruptcy filed December 22, 2008
was $60.5 million and, as a result, the Company received $60.5 million in cash
on July 23, 2010. In the second
quarter ended June 30, 2010 the Company recorded a settlement of its
Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5
million.
14.
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 errors are summarized in the tables below:
The components of
comprehensive income (loss):
|
|
For the twelve months
December 31, 2009
|
|
|
|
As Previously Reported
|
|
As Revised
|
|
|
|
|
|
|
|
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 summarizes
the impacts of the Companys derivative instruments gains (losses) before
income taxes reported in the Statements of Income (Loss) for the twelve months
ended December 31, 2009:
|
|
|
|
Twelve Months Ended
December 31, 2009
|
|
Derivatives cash flow hedging relationships
|
|
Location of Gain (Loss)
Recognized in Income
|
|
Previously
Reported
|
|
As Adjusted
|
|
Commodity
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
(240.9
|
)
|
$
|
(206.4
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
65.0
|
|
79.3
|
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
13.7
|
|
(0.6
|
)
|
Interest rate
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
8.8
|
|
$
|
(2.7
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(7.0
|
)
|
(7.0
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
|
|
The
Company also noted that the presentation error existed in the quarterly filings
for the periods ended March 31, 2009, June 30, 2009, September 30,
2009 and March 31, 2010 and the related disclosures in Note 4 for the
periods ended March 31, 2009, June 30, 2009 and September 30,
2009. The Company concluded that the presentation
error was immaterial to the previously filed financial statements. The effects of the presentation errors are
summarized in the tables below:
The components of
comprehensive income (loss):
|
|
For the Three Months Ended
March 31, 2009
|
|
|
|
As Previously Reported
|
|
As Revised
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
34,998
|
|
$
|
34,998
|
|
Unrealized gains (losses)
on derivatives, net of income taxes
|
|
78,577
|
|
(11,417
|
)
|
Reclassification of
realized (gains) losses, net of income taxes
|
|
(29,022
|
)
|
(38,138
|
)
|
Comprehensive income
(loss)
|
|
$
|
84,553
|
|
$
|
(14,557
|
)
|
20
Table of Contents
Berry Petroleum Company
Notes to Condensed Financial Statements
The table below summarizes
the impacts of the Companys derivative instruments gains (losses) before
income taxes reported in the Statements of Income (Loss) for the three months
ended March 31, 2009:
|
|
|
|
Three Months Ended
March 31, 2009
|
|
Derivatives cash flow hedging relationships
|
|
Location of Gain (Loss)
Recognized in Income
|
|
Previously
Reported
|
|
As Adjusted
|
|
Commodity
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
45.4
|
|
$
|
8.3
|
|
Gain (Loss) Reclassified
from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
48.2
|
|
62.5
|
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
22.7
|
|
22.8
|
|
Interest rate
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
(3.4
|
)
|
$
|
(3.8
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(1.0
|
)
|
(1.0
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
|
|
|
|
The components of
comprehensive income (loss):
|
|
For the Three Months Ended
June 30, 2009
|
|
For the Six Months Ended
June 30, 2009
|
|
|
|
As Previously
Reported
|
|
As Revised
|
|
As Previously
Reported
|
|
As Revised
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss) Income
|
|
$
|
(12,980
|
)
|
$
|
(12,980
|
)
|
$
|
22,019
|
|
$
|
22,019
|
|
Unrealized gains (losses)
on derivatives, net of income taxes
|
|
91,952
|
|
(73,055
|
)
|
170,529
|
|
(84,472
|
)
|
Reclassification of
realized (gains) losses, net of income taxes
|
|
(9,583
|
)
|
(9,314
|
)
|
(38,605
|
)
|
(47,452
|
)
|
Comprehensive income
(loss)
|
|
$
|
69,389
|
|
$
|
(95,349
|
)
|
$
|
153,943
|
|
$
|
(109,905
|
)
|
The table below summarizes
the impacts of the Companys derivative instruments gains (losses) before
income taxes reported in the Statements of Income (Loss) for the six months
ended June 30, 2009:
|
|
|
|
Six Months Ended June 30,
2009
|
|
Derivatives cash flow hedging relationships
|
|
Location of Gain (Loss)
Recognized in Income
|
|
Previously
Reported
|
|
As Adjusted
|
|
Commodity
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in
AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
175.2
|
|
$
|
(138.3
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
40.2
|
|
79.1
|
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
14.6
|
|
0.3
|
|
Interest rate
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
(4.6
|
)
|
$
|
2.1
|
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(1.6
|
)
|
(2.5
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
(0.3
|
)
|
(0.3
|
)
|
21
Table of
Contents
Berry Petroleum Company
Notes to Condensed Financial Statements
The
components of comprehensive
income
(loss):
|
|
For the Three Months Ended
September 30, 2009
|
|
For the Nine Months Ended
September 30, 2009
|
|
|
|
As Previously
Reported
|
|
As Revised
|
|
As Previously
Reported
|
|
As Revised
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,007
|
|
$
|
19,007
|
|
$
|
41,026
|
|
$
|
41,026
|
|
Unrealized gains (losses)
on derivatives, net of income taxes
|
|
(563
|
)
|
3,306
|
|
169,966
|
|
(81,166
|
)
|
Reclassification of
realized (gains) losses, net of income taxes
|
|
(454
|
)
|
(2,289
|
)
|
(39,059
|
)
|
(49,741
|
)
|
Comprehensive income
(loss)
|
|
$
|
17,990
|
|
$
|
20,024
|
|
$
|
171,933
|
|
$
|
(89,881
|
)
|
The table below summarizes
the impacts of the Companys derivative instruments gains (losses) before
income taxes reported in the Statements of Income (Loss) for the three and nine
months ended September 30, 2009:
|
|
|
|
Three Months Ended
September 30, 2009
|
|
Nine Months Ended
September 30, 2009
|
|
Derivatives cash flow
hedging relationships
|
|
Location of Gain (Loss)
Recognized in Income
|
|
Previously
Reported
|
|
As Adjusted
|
|
Previously
Reported
|
|
As Adjusted
|
|
Commodity
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
(0.7
|
)
|
$
|
9.3
|
|
$
|
174.5
|
|
$
|
(128.9
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Sales of oil and gas
|
|
1.6
|
|
5.6
|
|
41.8
|
|
84.7
|
|
Gain (Loss)
Recognized in Income (Ineffective portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
(0.6
|
)
|
(0.6
|
)
|
14.0
|
|
(0.2
|
)
|
Interest rate
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss)
Recognized in AOCL (Effective Portion)
|
|
Accumulated other comprehensive income
(loss)
|
|
$
|
0.7
|
|
$
|
(4.5
|
)
|
$
|
(3.9
|
)
|
$
|
(2.4
|
)
|
Gain (Loss)
Reclassified from AOCL into Income (Effective Portion)
|
|
Interest expense
|
|
(1.1
|
)
|
(1.9
|
)
|
(2.7
|
)
|
(4.4
|
)
|
Gain (Loss)
Recognized in Income (Ineffective Portion)
|
|
Realized and unrealized gain (loss) on derivatives, net
|
|
0.1
|
|
0.1
|
|
(0.2
|
)
|
(0.2
|
)
|
The
components of comprehensive income (loss):
|
|
For the Three Months Ended
March 31, 2010
|
|
|
|
As Previously Reported
|
|
As Revised
|
|
Net Income
|
|
$
|
17,669
|
|
$
|
17,669
|
|
Unrealized gains (losses)
on derivatives, net of income taxes
|
|
|
|
|
|
Accumulated other
comprehensive loss amortization of de-designated hedges, net of income taxes
|
|
(3,400
|
)
|
3,400
|
|
Comprehensive income
(loss)
|
|
$
|
14,269
|
|
$
|
21,069
|
|
22
Table of
Contents
Berry Petroleum Company
Managements Discussion
and Analysis of Financial Condition and Results of Operations
Item
2. Managements Discussion and Analysis
of Financial Condition and Results of Operations
The following is
managements discussion and analysis of certain significant factors that have
affected aspects of our financial position and the results of operations during
the periods included in the accompanying Condensed Financial Statements. You should read this in conjunction with the
discussion under Managements Discussion and Analysis of Financial Condition
and Results of Operations and the audited Financial Statements for the year
ended December 31, 2009 included in our Annual Report on Form 10-K
and the Condensed Financial Statements included elsewhere herein.
The
profitability of our operations in any particular accounting period will be
directly related to the realized prices of oil, gas and electricity sold, the
type and volume of oil and gas produced and electricity generated and the
results of development, exploitation, acquisition, exploration and hedging
activities. The realized prices for natural gas and electricity will fluctuate
from one period to another due to regional market conditions and other factors,
while oil prices will be predominantly influenced by global supply and demand.
The aggregate amount of oil and gas produced may fluctuate based on the success
of development and exploitation of oil and gas reserves pursuant to current
reservoir management. We benefit from lower natural gas prices as we are a consumer
of natural gas in our California operations. In the Rocky Mountains and E.
Texas we benefit from higher natural gas pricing. The cost of natural gas used
in our steaming operations and electrical generation, production rates, labor,
equipment costs, maintenance expenses, and production taxes are expected to be
the principal influences on operating costs. Accordingly, our results of
operations may fluctuate from period to period based on the foregoing principal
factors, among others.
In the second quarter of 2010, diatomite production
decreased 836 BOE/D compared to the first quarter of 2010. The decline is primarily due to the inability
to drill new wells as we await permits and certain operational changes that we
have implemented to facilitate higher production volumes when development
drilling resumes. There is no update on
when we will be able to resume drilling new wells in the diatomite. Currently the Division of Oil, Gas and
Geothermal Resources (DOGGR) is working towards adoption of new regulations for
the development of diatomite, which is estimated to take six to twelve months
to complete. However, we are currently
working with the DOGGR on an interim solution that would allow diatomite
development to resume in the last half of 2010.
The operational changes that we made during the first half of 2010
should allow us to drill with multiple rigs, accelerate development and
significantly improve efficiency when the new permits are issued. In the interim we have reallocated drilling
capital from the diatomite project to the Permian, adding a second rig in mid
July, and plan to add a third rig in August, expanding our drilling program to
approximately 37 wells in the Permian.
Notable Second Quarter Items.
·
Achieved production averaging 32,854 BOE/D,
comprised of 67% crude oil, up 12% from the first quarter of 2010
·
Generated discretionary cash flow
(1)
of $142 million, comprised of $81 million from
operations and a $61 million recovery from our claim in the Flying J bankruptcy
·
DOGGR in California determined new
regulations are needed for the cyclic injection of steam in the diatomite
·
While diatomite production
was down 836 BOE/D, production from Berrys other California assets increased
565 BOE/D compared to the first quarter of 2010
·
Completed three
horizontal Haynesville wells with a 30-day average production of 9 to 10 MMcf/D
per well
·
Established operations in the Permian basin
with production of 1,033 BOE/D, in line with expectations
·
Closed on the acquisition of an additional
3,200 acres in the Permian basin for $14 million
·
Settled our claim in the Flying J bankruptcy
and received payment of $60.5 million on July 23, 2010
Notable Items and Expectations for the Third Quarter and Full Year 2010.
·
Anticipating 2010 average
production between 32,250 and 33,000 BOE/D, an 8% to 10% increase over 2009
·
Working with the DOGGR on an interim solution
that would allow diatomite development to resume in the last half of 2010
·
Planning to run a three rig
drilling program in the Permian basin in the third quarter of 2010
·
Expecting 2010 development
capital expenditures of up to $290 million to be fully funded from operating
cash flow
(1)
Discretionary
cash flow is considered a non-GAAP performance measure and reference should be
made to
Reconciliation of Non-GAAP Measures
at the end of this Item 2 for further explanation of this performance
measure, as well as a reconciliation to the most directly comparable GAAP
measure.
23
Table of
Contents
Results of Operations
In
the second quarter of 2010, we reported net income from continuing operations
of $89.0 million, or $1.64 per diluted share, and net cash flows from
operations of $71.4 million. Net income from continuing operations includes a
$30.0 million gain on derivatives as a result of non-cash changes in fair
values and amortization of frozen fair values and a $37.4 million Flying J
settlement, offset by $1.2 million of purchase price adjustments related to the
March Acquisition, as defined below.
During
the first six months of 2010, we reported net income from continuing operations
of $106.7 million, or $2.00 per diluted share, and net cash flows from
operations was $134.9 million. Net
income from continuing operations includes a $29.2 million gain on derivatives
as result of non-cash changes in fair values and amortization of frozen fair
values and a $37.5 million Flying J settlement, offset by $0.8 million of dry
hole costs and $1.6 million of transaction related costs related to the
acquisition of certain properties in the Permian basin, as discussed below.
Acquisitions.
Permian Basin
Acquisitions.
In March 2010, we acquired interests in
producing properties principally on 6,900 net acres in the Permian basin of
West Texas (W. Texas) from a private seller for approximately
$
133
million, including normal post closing adjustments (the March Acquisition).
In April 2010 we closed on the acquisition of an additional 3,200 acres in
the Permian basin for approximately $14
million, including normal post closing adjustments (the April Acquisition
and, together with the March Acquisition, the Permian Basin
Acquisitions). The Permian Basin
Acquisitions included properties with total proved reserves of approximately 13 MMBOE, of which 83% were crude oil and 21% were proved developed. We now have a drilling inventory of over 200
locations on forty-acre spacing in the Wolfberry trend targeting the Spraberry
Dean, Wolfcamp and Strawn formations.
Revenues
.
Approximately 73% of our revenues are generated
through the sale of oil and natural gas production under either negotiated
contracts or spot gas purchase contracts at market prices. Approximately 4% of
our revenues are derived from electricity sales from cogeneration facilities
which supply approximately 28% of our steam requirement for use in our
California thermal heavy oil operations.
We have invested in these facilities for the purpose of lowering our
steam costs, which are significant in the production of heavy crude oil.
Approximately 3% of our revenues are derived from gas marketing sales which
represent our excess capacity on the Rockies Express pipeline which we used to
market natural gas purchased from our working interest partners.
The following results from continuing operations are
in millions (except per share data) for the three and six month periods ended:
|
|
Three months ended,
|
|
Six months ended,
|
|
|
|
June 30,
2010
|
|
June 30,
2009
|
|
March 31,
2010
|
|
June 30,
2010
|
|
June 30,
2009
|
|
Sales of oil
|
|
$
|
125
|
|
$
|
103
|
|
$
|
122
|
|
$
|
246
|
|
$
|
201
|
|
Sales of gas
|
|
27
|
|
16
|
|
26
|
|
53
|
|
46
|
|
Total sales of oil and gas
|
|
$
|
152
|
|
$
|
119
|
|
$
|
148
|
|
$
|
299
|
|
$
|
247
|
|
Sales of electricity
|
|
8
|
|
6
|
|
10
|
|
18
|
|
17
|
|
Gas marketing
|
|
5
|
|
5
|
|
8
|
|
13
|
|
12
|
|
Realized and unrealized
gain (loss) on derivatives, net
|
|
56
|
|
(31
|
)
|
2
|
|
58
|
|
6
|
|
Settlement on Flying J
bankruptcy claim
|
|
22
|
|
|
|
|
|
22
|
|
|
|
Interest and other income,
net
|
|
1
|
|
1
|
|
|
|
2
|
|
1
|
|
Total revenues and other
income
|
|
$
|
244
|
|
$
|
100
|
|
$
|
168
|
|
$
|
412
|
|
$
|
283
|
|
Net income (loss) from
continuing operations
|
|
$
|
89
|
|
$
|
(13
|
)
|
$
|
18
|
|
$
|
107
|
|
$
|
29
|
|
Diluted earnings (loss)
per share from continuing operations
|
|
$
|
1.64
|
|
$
|
(0.28
|
)
|
$
|
0.34
|
|
$
|
2.00
|
|
$
|
0.63
|
|
24
Table of
Contents
Operating data
. The following
table is for the three months ended:
|
|
June 30,
2010
|
|
%
|
|
June 30,
2009
|
|
%
|
|
March 31,
2010
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy oil production (Bbl/D)
|
|
17,492
|
|
54
|
|
16,822
|
|
57
|
|
17,752
|
|
61
|
|
Light oil production
(Bbl/D)
|
|
4,377
|
|
13
|
|
3,085
|
|
11
|
|
2,754
|
|
9
|
|
Total oil production
(Bbl/D)
|
|
21,869
|
|
67
|
|
19,907
|
|
68
|
|
20,506
|
|
70
|
|
Natural gas production
(Mcf/D)
|
|
65,909
|
|
33
|
|
56,174
|
|
32
|
|
53,309
|
|
30
|
|
Total (BOE/D)
|
|
32,854
|
|
100
|
|
29,270
|
|
100
|
|
29,391
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas BOE for
continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales
price
|
|
$
|
50.81
|
|
|
|
$
|
45.74
|
|
|
|
$
|
55.99
|
|
|
|
Average sales price
including cash derivative settlements
|
|
53.11
|
|
|
|
45.74
|
|
|
|
57.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, per Bbl for
continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average WTI price
|
|
$
|
78.05
|
|
|
|
$
|
59.79
|
|
|
|
$
|
78.88
|
|
|
|
Price sensitive royalties
|
|
(2.90
|
)
|
|
|
(2.08
|
)
|
|
|
(3.04
|
)
|
|
|
Quality differential and
other
|
|
(9.71
|
)
|
|
|
(7.86
|
)
|
|
|
(8.12
|
)
|
|
|
Crude oil derivatives non
cash amortization (a)
|
|
(2.42
|
)
|
|
|
|
|
|
|
(1.72
|
)
|
|
|
Crude oil derivatives cash
settlements (b)
|
|
|
|
|
|
8.91
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
63.02
|
|
|
|
$
|
58.76
|
|
|
|
$
|
66.00
|
|
|
|
Add: Crude oil derivatives
non cash amortization
|
|
2.42
|
|
|
|
|
|
|
|
1.72
|
|
|
|
Crude oil derivative cash
settlements (c)
|
|
0.01
|
|
|
|
|
|
|
|
(0.22
|
)
|
|
|
Average realized oil price
|
|
$
|
65.45
|
|
|
|
$
|
58.76
|
|
|
|
$
|
67.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price for
continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Henry Hub price
per MMBtu
|
|
$
|
4.09
|
|
|
|
$
|
3.51
|
|
|
|
$
|
5.30
|
|
|
|
Conversion to Mcf
|
|
0.20
|
|
|
|
0.18
|
|
|
|
0.27
|
|
|
|
Natural gas derivatives
non cash amortization (a)
|
|
0.12
|
|
|
|
|
|
|
|
0.07
|
|
|
|
Natural gas derivative
cash settlements (b)
|
|
|
|
|
|
0.21
|
|
|
|
|
|
|
|
Location, quality
differentials and other
|
|
0.02
|
|
|
|
(0.72
|
)
|
|
|
(0.15
|
)
|
|
|
Natural gas revenue per
Mcf
|
|
$
|
4.43
|
|
|
|
$
|
3.18
|
|
|
|
$
|
5.49
|
|
|
|
Less: Natural gas
derivatives non cash amortization
|
|
(0.12
|
)
|
|
|
|
|
|
|
(0.07
|
)
|
|
|
Natural gas derivative
cash settlements (c)
|
|
0.46
|
|
|
|
|
|
|
|
0.11
|
|
|
|
Average realized natural
gas price per Mcf
|
|
$
|
4.77
|
|
|
|
$
|
3.18
|
|
|
|
$
|
5.53
|
|
|
|
(a)
Includes non-cash amortization of frozen
December 31, 2009 fair values resulting from January 1, 2010
discontinuing of hedge accounting, recorded in Oil and natural gas sales
(b)
Includes cash settlements on derivatives prior to January 1,
2010, for which we had elected hedge accounting, recorded in Oil and natural
gas sales
(c)
Includes cash settlements on derivatives subsequent to January 1,
2010, for which we had discontinued hedge accounting, recorded in Realized and
unrealized gain (loss) on derivatives, net
25
Table of
Contents
The
following table is for the six months ended:
|
|
June 30,
2010
|
|
%
|
|
June 30,
2009
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Heavy oil production
(Bbl/D)
|
|
17,621
|
|
57
|
|
16,646
|
|
53
|
|
Light oil production
(Bbl/D)
|
|
3,570
|
|
11
|
|
3,076
|
|
10
|
|
Total oil production
(Bbl/D)
|
|
21,191
|
|
68
|
|
19,722
|
|
63
|
|
Natural gas production
(Mcf/D)
|
|
59,644
|
|
32
|
|
69,502
|
|
37
|
|
Total operations (BOE/D)
|
|
31,132
|
|
100
|
|
31,305
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin Production
(BOE/D)
|
|
|
|
|
|
1,542
|
|
|
|
Production - Continuing
Operations (BOE/D)
|
|
31,132
|
|
|
|
29,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas BOE for
continuing operations:
|
|
|
|
|
|
|
|
|
|
Average realized sales
price
|
|
$
|
53.24
|
|
|
|
$
|
46.44
|
|
|
|
Average sales price
including cash derivative settlements
|
|
54.98
|
|
|
|
46.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, per Bbl, for
continuing operations:
|
|
|
|
|
|
|
|
|
|
Average WTI price
|
|
$
|
78.46
|
|
|
|
$
|
51.58
|
|
|
|
Price sensitive royalties
|
|
(2.97
|
)
|
|
|
(1.55
|
)
|
|
|
Quality differential and
other
|
|
(8.95
|
)
|
|
|
(8.77
|
)
|
|
|
Crude oil derivatives non
cash amortization (a)
|
|
(2.08
|
)
|
|
|
|
|
|
|
Crude oil derivative cash
settlements (b)
|
|
|
|
|
|
16.36
|
|
|
|
Oil Revenue
|
|
$
|
64.46
|
|
|
|
$
|
57.62
|
|
|
|
Add: Crude oil derivatives
non cash amortization
|
|
2.08
|
|
|
|
|
|
|
|
Crude oil derivative cash
settlements (c)
|
|
(0.10
|
)
|
|
|
|
|
|
|
Average realized oil price
|
|
$
|
66.44
|
|
|
|
$
|
57.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price for
continuing operations:
|
|
|
|
|
|
|
|
|
|
Average Henry Hub price
per MMBtu
|
|
$
|
4.70
|
|
|
|
$
|
4.21
|
|
|
|
Conversion to Mcf
|
|
0.24
|
|
|
|
0.21
|
|
|
|
Natural gas derivatives
non cash amortization (a)
|
|
0.10
|
|
|
|
|
|
|
|
Natural gas derivative
cash settlements (b)
|
|
|
|
|
|
0.70
|
|
|
|
Location, quality
differentials and other
|
|
(0.13
|
)
|
|
|
(0.96
|
)
|
|
|
Natural gas revenue per
Mcf
|
|
$
|
4.91
|
|
|
|
$
|
4.16
|
|
|
|
Less: Natural gas
derivatives non cash amortization
|
|
(0.10
|
)
|
|
|
|
|
|
|
Natural gas derivative
cash settlements (c)
|
|
0.30
|
|
|
|
|
|
|
|
Average realized natural
gas price per Mcf
|
|
$
|
5.11
|
|
|
|
$
|
4.16
|
|
|
|
(a)
Includes non-cash amortization of frozen
December 31, 2009 fair values resulting from January 1, 2010
discontinuing of hedge accounting, recorded in Oil and natural gas sales
(b)
Includes cash settlements on derivatives prior to January 1,
2010, for which we had elected hedge accounting, recorded in Oil and natural
gas sales
(c)
Includes cash settlements on derivatives subsequent to January 1,
2010, for which we had discontinued hedge accounting, recorded in Realized and
unrealized gain (loss) on derivatives, net
Sales of Oil and Natural Gas.
Oil and gas revenue increased 28% to $152 million in
the second quarter of 2010 compared to $119 million in the second quarter of
2009. The increase is primarily due to a
12% increase in sales volumes and an increase in the average sales price to
$50.81 per BOE in the second quarter of 2010 from $45.74 per BOE in the second
quarter of 2009. Oil and gas revenue
increased 3% in the second quarter of 2010 compared to the first quarter of
2010. The increase is primarily due to a
12% increase in sales volume offset by a decrease in the average sales price to
$50.81 per BOE in the second quarter of 2010 from $55.99 per BOE in the first
quarter of 2010. Approximately 67% of
our oil and gas sales volumes in the second quarter of 2010 were crude oil, with
80% of the crude oil being heavy oil produced in California which was sold
under various contracts with prices tied to the San Joaquin posted price.
26
Table of
Contents
Oil and gas revenue increased 21% to $299 million in
the six months ended June 30, 2010 compared to $247 million in the six
months ended June 30, 2009. The
increase is primarily due to an increase in the average sales price to $53.24
per BOE in the six months ended June 30, 2010 from $46.44 per BOE in the
six months ended June 30, 2009.
Effective January 1, 2010, we elected to
de-designate all of our commodity derivative 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 of discontinuing hedge
accounting on January 1, 2010, changes in fair values at December 31,
2009 are frozen in accumulated other comprehensive loss (AOCL) as of the
de-designation date and will be reclassified into oil and gas revenues in
future periods as the original hedged transactions affect earnings. As a result, in the three and six months
ended June 30, 2010, we reclassified $4.1 million and $6.9 million,
respectively, of non-cash derivative losses relating to de-designated commodity
hedges from AOCL into earnings under the caption Sales of oil and gas. Beginning January 1, 2010 all of our
derivative contract fair value gains and losses are recognized immediately in
earnings as Realized and unrealized gain (loss) on derivatives, net. Cash flow is impacted to the extent that
actual cash settlements under these contracts result in making or receiving a
payment from the counterparty, and such cash settlement gains and losses are
also recorded to earnings as Realized and unrealized gain (loss) on
derivatives, net. See Realized and unrealized gain (loss) on derivatives, net below.
The average sales price for
oil sales during the second quarter of 2010 was $63.02 per BOE, an increase of
7% or $4.26 per BOE compared to the second quarter of 2009. The average sales price for oil sales during
the six months ended June 30, 2010 was $64.46 per BOE, an increase of 12%
or $6.84 per BOE compared to the six months ended June 30, 2009. The range of NYMEX light sweet crude prices
for the second quarter of 2010, based upon settlements, was from a low of
$68.01 to a high of $86.84. NYMEX light
sweet crude prices for the second quarter of 2009, based upon settlements, was
a low of $45.88 and a high of $72.68.
The range of NYMEX light sweet crude prices for the six months ended June 30,
2010, based upon settlements, ranged from a low of $68.01 to a high of
$86.84. NYMEX light sweet crude prices for
the six months ended June 30, 2009, based upon settlements, had a low of
$33.98 and a high of $72.68. In
California the differential on June 30, 2010 was $6.82 and ranged from a
low of $6.82 to a high of $8.95 per barrel during the second quarter of 2010.
The California differential ranged from a low of $6.45 to a high of $8.18 per
barrel during the second quarter of 2009.
The California differential ranged from a low of $6.82 to a high of
$8.95 per barrel during the six months ended June 30, 2010. In Utah, we
are a party to a crude oil sales contract through June 30, 2013 with a
refiner for the purchase of our 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 our 40 degree black wax (light)
crude oil can vary seasonally and this contract provides a stable outlet for
our crude oil.
The average sales price for
gas sales during the second quarter of 2010 was $4.43 per Mcf, an increase of
39% or $1.25 per Mcf compared to the second quarter of 2009. The average sales
price for gas sales during the six months ended June 30, 2010 was $4.91
per Mcf, an increase of 18% or $0.75 per Mcf compared to the six months ended June 30,
2009. We sell our produced natural gas at various indices. Henry Hub (HH) natural gas averaged $4.09 in
the second quarter of 2010, $3.51 in the second quarter of 2009, $4.70 in the
six months ended June 30, 2010 and $4.21 in the six months ended June 30,
2009. As of mid-2009, the pricing of our
Piceance basin natural gas production is tied to the eastern markets in Lebanon
or Clarington, Ohio, which averaged $0.12 above HH for the second quarter of
2010 and $0.16 above HH for the six months ended June 30, 2010. The Piceance basin natural gas was sold in
the six months ended June 30, 2009 based upon a mid-continent index such
as PEPL, which averaged $0.24 below HH in the second quarter of 2009 and
averaged $1.21 below HH in the six months ended June 30, 2009. Correspondingly, most of the Uinta basin
natural gas is sold based on a Questar index which averaged $0.53 below HH for
the second quarter of 2010 and $1.12 below HH for the second quarter of
2009. The Questar index averaged $0.40
and $1.42 below HH for the six months ended June 30, 2010 and 2009,
respectively. The E. Texas natural gas
production was generally sold during the six months ended June 30, 2010 at
the Florida Zone 1 index which was the same as HH for the second quarter and
six months ended June 30, 2010. The
E. Texas natural gas production was sold during the six months ended June 30,
2009 at the Texas Eastern - East Texas index, which averaged $0.20 below HH for
the second quarter of 2009 and $0.21 below HH for the six months ended June 30,
2009.
Sales of Electricity.
Electricity
revenues increased in the second quarter of 2010 compared to the second quarter
of 2009 due to an increase in sales volume and an increase in electricity
prices. Electricity operating costs
increased in the second quarter of 2010 compared to the second quarter of 2009
due to an increase in fuel gas cost.
Electricity revenues decreased in the second quarter of 2010 compared to
the first quarter of 2010 due to a 7% decrease in sales volumes and a 16%
decrease in electricity prices.
Electricity operating costs decreased in the second quarter of 2010
compared to the first quarter of 2010 due to a 22% decrease in fuel gas cost.
We purchased approximately 26 MMBtu/D and 28 MMBtu/D of natural gas as fuel for
use in our cogeneration facilities for the three months ended June 30,
2010 and March 31, 2010, respectively.
Electricity
revenues increased in the six months ended June 30, 2010 compared to the
six months ended June 30, 2009 as a result of an increase in sales
volume. Electricity operating costs
increased in the six months ended June 30, 2010 compared to the six months
ended June 30, 2009 due to 36% higher fuel gas cost.
27
Table of Contents
|
|
Three months ended
|
|
Six months ended
|
|
|
|
June 30,
2010
|
|
June 30,
2009
|
|
March 31,
2010
|
|
June 30,
2010
|
|
June 30,
2009
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (in millions)
|
|
$
|
7.9
|
|
$
|
6.6
|
|
$
|
9.9
|
|
$
|
17.9
|
|
$
|
16.9
|
|
Operating costs (in
millions)
|
|
$
|
7.8
|
|
$
|
6.4
|
|
$
|
9.7
|
|
$
|
17.5
|
|
$
|
15.2
|
|
Electric power produced -
MWh/D
|
|
2,009
|
|
2,007
|
|
2,154
|
|
2,081
|
|
2,049
|
|
Electric power sold -
MWh/D
|
|
1,840
|
|
1,783
|
|
1,979
|
|
1,909
|
|
1,860
|
|
Average sales price/MWh
|
|
$
|
47.47
|
|
$
|
46.99
|
|
$
|
56.17
|
|
$
|
53.18
|
|
$
|
53.14
|
|
Fuel gas cost/MMBtu
(including transportation)
|
|
$
|
4.18
|
|
$
|
3.12
|
|
$
|
5.39
|
|
$
|
4.80
|
|
$
|
3.54
|
|
Natural Gas Marketing.
We have long-term firm transportation contracts
for our Piceance natural gas production, with total capacity of 35,000
MMBtu/D. We pay a demand charge for this capacity and our own
production does not currently fill that capacity. In order to maximize our firm
transportation, we bought our partners share of the gas produced in the
Piceance at the market rate for that area. We used our excess transportation to
move this gas to where it was eventually sold. The pre-tax net of our gas
marketing revenue and our gas marketing expense in the Condensed Statements of
Income (Loss) for the three months ended June 30, 2010 and 2009 is $0.6
million. The pre-tax net of our gas marketing revenue and our gas marketing
expense in the Condensed Statements of Income (Loss) for the six months ended June 30,
2010 and 2009 is $1.1 million and $0.9 million. Firm transportation costs
related to all of our Rockies Express volumes is reflected in Operating costs -
oil and gas production and total $3.7 million and $2.5 million for the three
months ended June 30, 2010 and 2009, respectively and $6.9 million and $5.0
million for the six months ended June 30, 2010 and 2009, respectively.
Realized and unrealized g
ain
(loss) on derivatives, net.
Realized and unrealized g
ain (loss) on
derivatives, net is primarily related to derivatives for which we did not elect
hedge accounting or derivatives which did not qualify for cash flow hedge
accounting either at their inception or where hedge accounting was discontinued
during their term. When the criteria for cash flow hedge accounting is not met,
or when cash flow hedge accounting is not elected, realized gains and losses
(i.e., cash settlements) are recorded in Realized and unrealized gain (loss) on
derivatives, net in the Condensed Statements of Income (Loss). Similarly, changes
in the fair value of the derivative instruments are recorded as unrealized
gains or losses in the Realized and unrealized gain (loss) on derivative, net
in the Condensed Statements of Income (Loss).
In contrast, cash settlements for derivative instruments that qualify
for hedge accounting are recorded as additions to or reductions of oil and gas
revenues, while changes in fair value of cash flow hedges are recognized, to
the extent the hedge is effective, in AOCL until the hedged item is recognized
in earnings. Realized and unrealized gain (loss) on
derivatives, net also includes any hedge ineffectiveness on cash flow hedges
that qualify for hedge accounting.
During 2009, we entered
into certain commodity derivative contracts that we did not designate as cash
flow hedges. In addition, effective
January 1, 2010, we elected to de-designate all of our commodity and
interest rate derivative contracts that had been previously designated as cash
flow hedges as of December 31, 2009 and have elected to discontinue hedge
accounting prospectively. Accordingly,
beginning January 1, 2010 derivative contract fair value gains and losses
are recognized immediately in earnings.
Cash flow is impacted to the extent that actual cash settlements under
these contracts result in making or receiving a payment from the counterparty,
and such cash settlement gains and losses are also recorded to earnings under
the caption
Realized and unrealized
gain (loss) on derivatives, net.
28
Table of
Contents
The
following table sets forth the cash settlements and non-cash mark-to-market
adjustments for the derivative contracts not designated as hedges recorded in Realized
and unrealized gain (loss) on derivatives, net for the periods indicated:
|
|
Three months ended
|
|
Six months ended
|
|
|
|
June 30,
2010
|
|
June 30,
2009
|
|
March 31,
2010
|
|
June 30,
2010
|
|
June 30,
2009
|
|
Cash
receipts (payments):
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives -
oil
|
|
$
|
21
|
|
$
|
|
|
$
|
(414
|
)
|
$
|
(393
|
)
|
$
|
|
|
Commodity derivatives -
natural gas
|
|
2,757
|
|
|
|
517
|
|
3,274
|
|
|
|
Financial derivatives -
interest
|
|
(1,829
|
)
|
|
|
(1,826
|
)
|
(3,655
|
)
|
|
|
Mark-to-market gain
(loss):
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives -
oil
|
|
$
|
58,852
|
|
$
|
(7,436
|
)
|
$
|
(7,112
|
)
|
$
|
51,741
|
|
$
|
(7,275
|
)
|
Commodity derivatives -
natural gas
|
|
(2,888
|
)
|
(1,030
|
)
|
11,939
|
|
9,051
|
|
(1,030
|
)
|
Financial derivatives -
interest
|
|
(856
|
)
|
|
|
(1,501
|
)
|
(2,357
|
)
|
|
|
Total Realized and
unrealized gain (loss) on derivatives, net for items not under hedge
accounting
|
|
$
|
56,057
|
|
$
|
(8,466
|
)
|
$
|
1,603
|
|
$
|
57,661
|
|
$
|
(8,305
|
)
|
For the three and six months ended June 30,
2009, a
portion of the change in fair value for hedges that we have designated
as cash flow hedges impacts our income as our sales price was not perfectly
correlated with our hedges. As a result,
for the three months ended June 30, 2009, we recognized an unrealized net
loss of approximately $22.6 million on the Condensed Statement of Income (Loss)
under the caption Realized and unrealized gain
(loss) on derivatives, net. In
the six months ended June 30, 2010,
we reclassified a gain of $14.3 million from AOCL to the Condensed Statements
of Income (loss) under the caption Realized
and unrealized gain (loss) on derivatives, net. The $14.3 gain was in conjunction with the
first quarter 2009 sale of the DJ basin assets, in which we concluded that the
forecasted transaction in certain of our hedging relationships was not
probable.
Settlement in Flying J bankruptcy
.
On
July 6, 2010, that certain Joint Plan of Reorganization of Flying J, Inc.,
Big West of California, LLC, Big West Oil, LLC, Big West Transportation, LLC
and Longhorn Partners Pipeline, L.P. was confirmed under Chapter 11 of the
United State Bankruptcy Code. Additionally, on July 6, 2010, the
United States Bankruptcy Court approved and confirmed the June 15, 2010
Stipulation and Agreed Order (the Stipulation) with Flying J Inc. and certain
of its affiliates (collectively Flying J), regarding the resolution of our claim
in Flying Js pending bankruptcy.
Pursuant to the Stipulation, we and Flying J agreed that the total
amount owed to us by Flying J was $60.5 million. We received $60.5 million in cash on July 23, 2010. In the second quarter ended June 30,
2010, we recorded a settlement of our Flying J bankruptcy claim of $22.0
million and a bad debt recovery of $38.5 million. See Notes 12 and 13 to the Condensed
Financial Statements.
29
Table of
Contents
Oil and Gas Operating and Other
Expenses.
The following table presents information about our
continuing operating expenses for each of the three month periods ended:
|
|
Amount per BOE
|
|
Amount (in thousands)
|
|
|
|
June 30,
2010
|
|
June 30,
2009
|
|
March 31,
2010
|
|
June 30,
2010
|
|
June 30,
2009
|
|
March 31,
2010
|
|
Operating costs oil and
gas production
|
|
$
|
15.54
|
|
$
|
13.03
|
|
$
|
17.78
|
|
$
|
46,452
|
|
$
|
34,738
|
|
$
|
47,036
|
|
Production taxes
|
|
1.69
|
|
1.83
|
|
1.97
|
|
5,064
|
|
4,885
|
|
5,204
|
|
DD&A oil and gas
production
|
|
14.62
|
|
12.89
|
|
13.57
|
|
43,703
|
|
34,371
|
|
35,907
|
|
G&A
|
|
4.07
|
|
4.94
|
|
5.23
|
|
12,155
|
|
13,164
|
|
13,835
|
|
Interest expense
|
|
5.47
|
|
3.97
|
|
6.60
|
|
16,340
|
|
10,589
|
|
17,447
|
|
Total
|
|
$
|
41.39
|
|
$
|
36.66
|
|
$
|
45.15
|
|
$
|
123,714
|
|
$
|
97,747
|
|
$
|
119,429
|
|
·
Operating costs
in the second quarter of 2010 were $46.5 million or $15.54 per BOE, compared to
$34.7 million or $13.03 per BOE in the second quarter of 2009 and $47.0 million
or $17.78 per BOE in the first quarter of 2010.
Steam costs are the primary variable component of our operating costs
and fluctuate based on the amount of steam we inject and the price of fuel used
to generate steam. The following table
presents steam information:
|
|
June 30,
2010
(2Q10)
|
|
June 30,
2009
(2Q09)
|
|
2Q10
to 2Q09
Change
|
|
March 31,
2010
(1Q10)
|
|
2Q10 to
1Q10
Change
|
|
Average volume of steam
injected (Bbl/D)
|
|
110,467
|
|
107,739
|
|
3
|
%
|
118,733
|
|
(7
|
)%
|
Fuel gas cost/MMBtu
(including transportation)
|
|
$
|
4.18
|
|
$
|
3.12
|
|
34
|
%
|
$
|
5.39
|
|
(22
|
)%
|
Approximate net fuel gas
volume consumed in steam generation (MMBtu/D)
|
|
33,501
|
|
29,459
|
|
14
|
%
|
36,699
|
|
(9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in operating costs compared to the second quarter of 2009
is primarily due to a 34% increase in fuel gas costs as a result of increased
natural gas prices and a 14% increase in fuel gas volume consumed in steam
generation. The decrease in operating
costs compared to the first quarter of 2010 is primarily due to a 22% decrease
in fuel gas costs as a result of decreased natural gas prices and a 9% decrease
in fuel gas volume consumed in steam generation.
·
Production taxes in the second quarter of
2010 were $5.1 million or $1.69 per BOE, compared to $4.9 million or $1.83 per
BOE in the second quarter of 2009 and $5.2 million or $1.97 per BOE in the
first quarter of 2010. Severance taxes
paid in Utah, Colorado and Texas are directly related to the field sales price
of the commodity. In California, our production is burdened with ad valorem
taxes on our total proved reserves. The
decrease in production taxes, on a per barrel basis, compared to the second
quarter of 2009 is due to a decrease in the assessed ad valorem tax values
attributed to our California properties.
The decrease in production taxes, on a per barrel basis, compared to the
first quarter of 2010 is primarily related to well incentives claimed on
various severance tax filings and decreases in assessed ad valorem tax values
attributed to our Texas properties.
·
Depreciation, depletion and amortization
(DD&A) in the second quarter of 2010 was $43.7 million or $14.62 per BOE,
compared to $34.4 million or $12.89 per BOE in the second quarter of 2009 and
$35.9 million or $13.57 per BOE in the first quarter of 2010. The increase in
DD&A in the second quarter of 2010 compared to both the second quarter of
2009 and the first quarter of 2010 is primarily due to the increase in
production from assets outside of California which have higher per barrel
DD&A rates than our California properties.
·
General and administrative expense (G&A)
in the second quarter of 2010 was $12.2 million or $4.07 per BOE, compared to
$13.2 million or $4.94 in the second quarter of 2009 and $13.8 million or $5.23
per BOE in the first quarter of 2010.
The decrease in G&A in the second quarter of 2010 compared to the
second quarter of 2009 is due to the liability that was established in the
second quarter of 2009 for a regulatory compliance matter, offset by an
increase resulting from additional headcount due to staffing of the Permian
asset team. The decrease in G&A in
the second quarter of 2010 compared to the first quarter of 2010 is due to
director compensation paid in the first quarter of 2010. Approximately 65% of our G&A is related
to compensation.
30
Table of
Contents
·
Interest expense in the
second quarter of 2010 was $16.3 million or $5.47 per BOE, compared to $10.6
million or $3.97 per BOE in the second quarter of 2009 and $17.4 million or
$6.60 per BOE in the first quarter of 2010.
The increase in interest expense compared to the second quarter of 2009
was due to the issuance of our 10.25% senior notes due 2014, in May 2009. The amortization of the net discount and
deferred loan costs attributable to the senior notes is also included in
interest expense. Interest expense
decreased compared to the first quarter of 2010 primarily due to an increase in
interest costs capitalized in the second quarter of 2010 compared to the first
quarter of 2010. Additionally, in the
second quarter of 2010, we reclassified $2.4 million, or $0.80 per BOE of
non-cash derivative losses relating to de-designated interest rate hedges from
AOCL into earnings. Interest expense in the second quarter of 2010 was $4.67
per BOE, excluding the non-cash derivative losses.
The following table presents information about our continuing operating
expenses for each of the six month periods ended:
|
|
Amount per BOE
|
|
Amount (in thousands)
|
|
|
|
June 30,
2010
|
|
June 30,
2009
|
|
June 30,
2010
|
|
June 30,
2009
|
|
Operating costs oil and
gas production
|
|
$
|
16.59
|
|
$
|
13.39
|
|
$
|
93,488
|
|
$
|
72,122
|
|
Production taxes
|
|
1.82
|
|
1.96
|
|
10,269
|
|
10,537
|
|
DD&A oil and gas
production
|
|
14.13
|
|
13.14
|
|
79,609
|
|
70,769
|
|
G&A
|
|
4.61
|
|
4.91
|
|
25,990
|
|
26,457
|
|
Interest expense
|
|
6.00
|
|
3.83
|
|
33,788
|
|
20,639
|
|
Total
|
|
$
|
43.15
|
|
$
|
37.23
|
|
$
|
243,144
|
|
$
|
200,524
|
|
·
Operating costs
in the six months ended June 30, 2010 were $93.5 million or $16.59 per
BOE, compared to $72.1 million or $13.39 per BOE in the six months ended June 30,
2009. Steam costs are the primary
variable component of our operating costs and fluctuate based on the amount of
steam we inject and the price of fuel used to generate steam. The following table presents steam
information for each of the six months periods ended:
|
|
June 30, 2010
|
|
June 30, 2009
|
|
Change
|
|
Average volume of steam
injected (Bbl/D)
|
|
114,577
|
|
105,118
|
|
9
|
%
|
Fuel gas cost/MMBtu
(including transportation)
|
|
$
|
4.80
|
|
$
|
3.54
|
|
36
|
%
|
Approximate net fuel gas
volume consumed in steam generation (MMBtu/D)
|
|
35,097
|
|
27,887
|
|
26
|
%
|
|
|
|
|
|
|
|
|
|
|
The increase in operating costs is primarily due to a 36% increase in
fuel gas costs as a result of increased natural gas prices and a 26% increase
in fuel gas volume consumed in steam generation.
·
Production taxes in the six months ended June 30,
2010 were $10.3 million or $1.82 per BOE, compared to $10.5 million or $1.96
per BOE in the six months ended June 30, 2009. Severance taxes paid in Utah, Colorado and
Texas are directly related to the field sales price of the commodity. In
California, our production is burdened with ad valorem taxes on our total
proved reserves. The decrease in
production taxes compared to the six months ended June 30, 2009 is due to
a decrease in the assessed ad valorem tax values attributed to our California
properties.
·
Depreciation, depletion and amortization
(DD&A) in the six months ended June 30, 2010 was $79.6 million or
$14.13 per BOE, compared to $70.8 million or $13.14 per BOE in the six months
ended June 30, 2009. The increase
in the six months ended June 30, 2010 compared to the six months ended June 30,
2009 is primarily due to the increase in production from assets outside of
California which have higher per barrel DD&A rates than our California
properties.
·
General and administrative expense (G&A)
in the six months ended June 30, 2010 was $26.0 million or $4.61 per BOE,
compared to $26.5 million or $4.91 in the six months ended June 30, 2009.
·
Interest expense in the six
months ended June 30, 2010 was $33.8 million or $6.00 per BOE, compared to
$20.6 million or $3.83 per BOE in the six months ended June 30, 2009. The increase in interest expense compared to
the six months ended June 30, 2009 was due to the issuance of our 10.25%
senior notes due 2014, in May 2009.
The amortization of the net discount and deferred loan costs
attributable to the senior notes is also included in interest expense. Additionally, in the six months ended June 30,
2010, we reclassified $5.1 million, or $0.91 per BOE, of non-cash derivative
losses relating to de-designated interest rate hedges from AOCL into earnings.
Interest expense in the six months ended June 30, 2010 was $5.09 per BOE,
excluding the non-cash derivative losses.
31
Table of Contents
2010 Guidance.
For 2010 the Company is issuing the following guidance:
|
|
Anticipated Range per BOE in 2010 ($/BOE)
|
|
|
|
$60 WTI/$4 HH
|
|
$60 WTI/$5 HH
|
|
$75 WTI/$6 HH
|
|
Operating costs-oil and
gas production
|
|
$
|
16.00 17.00
|
|
$
|
17.00 18.00
|
|
$
|
18.00 19.00
|
|
Production taxes
|
|
1.75 2.25
|
|
1.75 2.25
|
|
2.00 2.50
|
|
DD&A oil and gas
production
|
|
|
|
14.00 16.00
|
|
|
|
G&A
|
|
|
|
4.00 4.50
|
|
|
|
Interest expense
|
|
|
|
5.00 - 6.50
|
|
|
|
Total
|
|
|
|
$
|
41.75 47.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transaction costs on acquisitions.
In the three and six months
ended June 30, 2010, transaction costs on acquisitions were $1.9 million
and $2.6 million, respectively. In the
three and six months ended June 30, 2010, we recorded $0.5 million and
$2.6 million of acquisition related expenses, respectively, for the acquisition
of certain properties in the Permian basin.
The March 2010 acquisition had an effective date of January 1,
2010 and the activity from January 1, 2010 through March 4, 2010 was
treated as purchase price adjustments.
Our preliminary purchase price allocation included an estimate for the
activity between January 1, 2010 and March 4, 2010; however, actual
amounts were greater than our estimate which resulted in an increase to the
total cash consideration paid to the seller.
As a result, the initial $1.4 million of Gain on purchase of oil and
natural gas properties recorded in the first quarter of 2010 has been reversed
in the second quarter of 2010 to reflect the purchase price adjustments.
Dry hole, abandonment, impairment and exploration.
In the three and six months
ended June 30, 2010 we incurred dry hole, abandonment, impairment and
exploration expense of $0.3 million and $1.6 million, respectively, which was
primarily a result of mechanical failure encountered on one well in the
Piceance basin. The well was abandoned
in favor of drilling a replacement well from the same well pad. During the three months ended June 30,
2009, we did not incur any dry hole, abandonment, impairment and exploration
expense. During the six months ended June 30,
2009 we had dry hole, abandonment, impairment and exploration charges of $0.1
million.
Loss on discontinued
operations.
On March 3, 2009, we
entered into an agreement to sell our DJ basin assets and related
hedges for $154 million before customary closing adjustments. The closing
date of the sale of our DJ basin assets was April 1, 2009. We
recorded an impairment charge of $9.6 million, which is aggregated within loss
from discontinued operations, net of tax, on the Condensed Statement of Income
(Loss) for the six months ended June 30, 2009.
Income Tax Expense.
The effective
income tax rate for the three months ended June 30, 2010 and 2009 was
38.1% and 36.1%, respectively. The effective income tax rate for the six months
ended June 30, 2010 and 2009 was 37.9% and 33.0%, respectively. The increase in rate is primarily due to a
one-time reduction in state deferred rates and uncertain tax positions in the
prior periods. Reductions in the rate
during prior periods were the result of acquisitions in more tax favorable
jurisdictions that reduced future state tax obligations, as well as favorable
state tax incentives. Our estimated
annual effective tax rate varies from the 35% federal statutory rate due to the
effects of state income taxes and estimated permanent differences. See Note 10 to the Condensed Financial
Statements.
Drilling Activity.
The following table sets forth certain information regarding drilling
activities (including operated and non-operated wells):
|
|
Three months ended
June 30, 2010
|
|
Six months ended
June 30, 2010
|
|
Asset Team
|
|
Gross Wells
|
|
Net Wells
|
|
Gross Wells
|
|
Net Wells
|
|
S. Midway
|
|
26
|
|
25
|
|
53
|
|
52
|
|
N. Midway
|
|
3
|
|
3
|
|
17
|
|
17
|
|
Permian
|
|
4
|
|
4
|
|
5
|
|
5
|
|
Uinta
|
|
26
|
|
23
|
|
38
|
|
35
|
|
E. Texas
|
|
2
|
|
2
|
|
4
|
|
4
|
|
Piceance
|
|
6
|
|
4
|
|
9
|
|
6
|
|
Totals
|
|
67
|
|
61
|
|
126
|
|
119
|
|
32
Table of Contents
Properties
We currently have six asset teams as follows: South
Midway-Sunset (S. Midway), North Midway-Sunset including diatomite (N. Midway),
Permian, Uinta, E. Texas and Piceance. Our S. Midway asset team is primarily
focused on production and generates significant cash flow to fund our planned
drilling inventory in our N. Midway, Piceance, E. Texas, Uinta and W. Texas
projects.
S. Midway
This asset
team is responsible for our S. Midway leases including Homebase, Formax and
Ethel D, as well as our Poso Creek property.
In the second quarter of 2010 we drilled 26 wells, almost all of which
focused on enhancing our thermal recovery at the Homebase and Formax
leases. These new wells are currently on
production and are performing in line with expectations. The balance of the wells drilled included several
steam injection and observation wells at Poso Creek. Average daily production in the second
quarter of 2010 from all S. Midway assets was approximately 12,076 BOE/D, a 3%
increase from the first quarter of 2010.
N. Midway
Our N. Midway asset
team includes our Diatomite, Placerita and McKittrick assets and several N.
Midway-Sunset leases. Our diatomite
production in the second quarter was 2,730 BOE/D. The production decline
in the diatomite compared to the first quarter of 2010 is due to the inability
to drill new wells as we await permits and certain operational changes we have
implemented to facilitate higher production volumes when development drilling
resumes. We continue to invest in infrastructure for the
diatomite. There is no update on when we will be able to resume
drilling new wells in the diatomite.
However, we are currently working with the DOGGR on an interim solution
that would allow diatomite development to resume in the last half of 2010. We continue to evaluate McKittrick and are
encouraged with the results to date.
Average daily production in the second quarter of 2010 from all N.
Midway assets was approximately 5,414 BOE/D.
Permian
Our Permian asset
team executed a one rig drilling program in the second quarter of 2010 and we
plan to execute a three rig drilling program for the remainder of 2010,
increasing production over the course of the year. We now have an inventory of
over 200 drilling locations on forty-acre spacing in the Wolfberry trend. We have opened a Midland, Texas office and
have fully staffed our Permian asset team. Average daily production in the second
quarter of 2010 was approximately 1,033 BOE/D.
Uinta
In the second
quarter of 2010, production from our Uinta basin assets averaged 5,217
BOE/D. We drilled 26 wells with a two
rig drilling program, targeting higher oil potential areas of Brundage Canyon
and Lake Canyon. The Ashley Forest
Development EIS continues to progress and the draft EIS public comment period ended
in the second quarter of 2010. Approval
of the final EIS is anticipated in the next six to nine months. Our drilling inventory in the Uinta is
approximately 300 locations distributed between Brundage Canyon, the Ashley
Forest and Lake Canyon.
E. Texas
In the
second quarter of 2010, production from our E. Texas assets averaged 31.0
MMcfe/D. We continue to operate a one
rig program which is now drilling horizontal Haynesville wells in our Darco
field located in Harrison County. In the
second quarter of 2010 we successfully drilled two additional horizontal wells
and completed three horizontal wells. As
of June 30, 2010 we had four Haynesville wells completed and online. Lateral lengths have ranged from 4,257 feet
to 4,590 feet and have been completed between 13 and 16 fracture stimulation
treatments. Well performance on our
second and third wells for the first 30 days average production has ranged from
9 to 10 MMcf/D per well.
Piceance
In the
second quarter of 2010, production from the Piceance basin averaged 23.6
MMcfe/D. We continued to operate a one
rig drilling program focusing on remaining lease earning obligations. We drilled 6 wells in the second quarter and
continued to utilize improved completions techniques with 4 new well completions
and 6 uphole recompletions in the second quarter. Results from these completions continue to
meet our expectations.
33
Table of Contents
Financial Condition, Liquidity and Capital Resources
Our exploration,
development, and acquisition activities require us to make significant
operating and capital expenditures.
Historically, we have used cash flow from operations and our bank credit
facilities as our primary sources of liquidity.
We have also used the debt and equity markets as other sources of
financing and, as market conditions have permitted, we have engaged in asset
monetization transactions.
Changes in the market prices for oil and natural gas
directly impact our level of cash flow generated from operations. We employ derivative instruments in our risk
management strategy in an attempt to minimize the adverse effects of wide
fluctuations in the commodity prices on our cash flow. As of June 30, 2010 we had approximately
75% and 45% of our expected 2010 and 2011 oil production, respectively, hedged
with derivative instruments in the form of swaps and collars and we had
approximately 30% and 20% of our 2010 and 2011 expected natural gas production,
respectively , hedged with derivative instruments in the form of swaps and
collars. This level of derivatives is expected to provide a measure of
certainty of the cash flow that we will receive for a portion of our production
in 2010 and 2011. In the future, we may
determine to increase or decrease our derivative positions. Most of our
derivatives counterparties were commercial banks that are parties to our credit
facilities, or their affiliates. See
Item 3, Quantitative and Qualitative Disclosures About Market Risk for
further details concerning our hedging activities.
We have a $1.5 billion senior secured revolving
credit facility with a current borrowing base of $938 million and $601 million
of available borrowing capacity. At June 30,
2010, we had $310 million in borrowings and $24 million in letters of credit
outstanding under the credit facility. Our borrowing base is subject to semi-annual
redeterminations in April and October of each year and was
reconfirmed in April 2010. The borrowing base is determined by the
lenders (a syndicate of banks),
taking into consideration the estimated value of our proved oil and gas
reserves based on pricing models determined by the lenders. In addition, we may borrow up to $30 million
for a maximum of 30 days under our Secured Line of Credit. There was $3.3 million outstanding on the
Secured Line of Credit at June 30, 2010 and no outstanding borrowings at December 31,2009. See Note 9 to the Condensed Financial
Statements.
We received $60.5 million
in cash upon settlement of our Flying J bankruptcy claim on July 23,
2010. We used the proceeds from the
settlement to reduce outstanding borrowings under our senior secured revolving
credit facility, which increased our available borrowing capacity to over $650
million.
The debt and equity markets
have served as our primary source of financing to fund large acquisitions and
other transactions. In January 2010, we sold to the public 8 million
shares of our common stock at a price of $29.25 per share and received $224
million of net proceeds after deducting the underwriting discounts and the
offering expenses. We used the net
proceeds to fund the March Acquisition and to reduce our outstanding
borrowings under our senior secured revolving credit facility. In May 2009, we issued $325 million
principal amount of 10.25% senior notes due 2014 and in August 2009 we
issued an additional $125 million principal amount of our 10.25% senior notes
due 2014. See Note 9 to the Condensed
Financial Statements.
Our ability to access the debt and equity capital
markets on economical terms is affected by general economic conditions, the
financial markets, the credit ratings assigned to our debt by independent
credit rating agencies, our operational and financial performance, the value
and performance of equity and debt securities, prevailing commodity prices, and
other macroeconomic factors outside of our control.
We also have engaged in asset dispositions as a
means of generating additional cash to fund expenditures and enhance our
financial flexibility. For example, in April 2009, we sold our DJ basin
assets and related hedges for $154 million before customary closing adjustments
and in July 2009 we completed the sale of our E. Texas gathering system
for $18 million in cash.
Cash Flows
Operating activities -
Net cash flows
provided by operating activities are primarily affected by the price of crude
oil and natural gas, production volumes, and changes in working capital. The increase in net cash provided by
operating activities of $75.7 million in the first six months of 2010 compared
to the first six months of 2009 is primarily due to higher realized commodity
sales prices in the first six months of 2010 compared to the first six months
of 2009.
Investing Activities -
Cash flows used
by investing activities are primarily comprised of acquisition, exploration and
development of oil and gas properties net of dispositions of oil and gas
properties. Net cash used in investing
activities in the first six months of 2010 primarily consisted of the Permian
Basin Acquisitions. Net cash provided by
investing activities in the first six months of 2009 primarily consisted of
proceeds from the sale of the DJ basin assets in 2009.
34
Table of Contents
Financing Activities -
Net cash
provided by financing activities in the first six months of 2010 included
proceeds from the issuance of stock of $224.3 million, the net repayment of
borrowings under our senior secured revolving credit facility and our Secured
Line of Credit of $58.7 million and dividends paid of $8.1 million. Net cash used in financing activities in the
first six months of 2009 included the net repayment of borrowings under our
senior secured revolving credit facility and our Secured Line of Credit of
$376.2 million, debt issuance costs of $21.5 million and dividends paid of $6.8
million, offset by the net proceeds from the issuance of 10¼% senior notes of
$304.0 million.
Capital Expenditures
We establish a capital budget for each calendar year
based on our development opportunities and the expected cash flow from
operations for that year. We may revise
our capital budget during the year as a result of acquisitions and/or drilling
outcomes or significant changes in cash flows.
In 2010, we are expecting a capital program of up to $290 million, and
we expect to fully fund this program from operating cash flow. Our capital expenditures for the second
quarter of 2010 totaled $87.1 million for development and capitalized interest
of $7.1 million compared to total capital expenditures for the second quarter
of 2009 of $22.9 million for development and capitalized interest of $7.3
million. Our capital expenditures for
the six months ended June 30, 2010 totaled $135.0 million for development
and capitalized interest of $13.1 million compared to total capital
expenditures for the six months ended June 30, 2009 of $73.1 million for
development and capitalized interest of $12.6 million. We expect our 2010
capital program will allow us to increase production from 2009 levels to
average 2010 production between 32,250 BOE/D and 33,000 BOE/D.
We believe that our cash
flow provided by operating activities and funds available under our credit
facilities will be sufficient to fund our operating and capital expenditures
budget and our short-term contractual operations during 2010. However, if our revenue and cash flow
decrease in the future as a result of deterioration in economic conditions or
an adverse change in commodity prices, we may have to reduce our spending
levels. As we have operational control of all of our assets and we have limited
drilling commitments, we believe that we have the financial flexibility to
adjust our spending levels, if necessary, to meet our financial obligations.
Critical Accounting Policies and Estimates
Reference
should be made to the corresponding section in Part II, Item 7
of our Annual Report on Form 10-K for the year ended December 31,
2009 for a discussion of other critical accounting policies that we consider as
being of particular importance to the portrayal of our financial position and
results of operations and which require the application of significant judgment
by management.
Derivatives and Hedging.
We periodically
enter into commodity derivative contracts to manage our exposure to oil and
natural gas price volatility. We also enter 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 AOCL 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, have no
effect on the Condensed Statements 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 and any ineffective portion of the derivative instruments
change in fair value is recognized immediately in earnings. The
estimated fair value of our 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 we report in our Condensed Financial Statements changes as these
estimates are revised to reflect actual results, changes in market conditions
or other factors, many of which are beyond our control. Effective
January 1, 2010, we have elected to de-designate all of our 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. At December 31, 2009, AOCL consisted of $97
million ($60 million after tax) of unrealized losses, representing the fair
value of our cash flow hedges as of the Condensed Balance Sheet date, less any
ineffectiveness recognized. As a result of discontinuing hedge
accounting on January 1, 2010, such changes in fair 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. We expect to reclassify into earnings
from AOCL the frozen value related to de-designated commodity hedges during the
next three years. See Note 4 to the
Condensed Financial Statements.
35
Table of Contents
Recent Accounting Standards and 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 our financial
position or results of operations.
Reconciliation of Non-GAAP Measures
Discretionary Cash Flow
In
addition to reporting cash provided by operating activities as defined under
GAAP, we present discretionary cash flow, which is a non-GAAP liquidity
measure. Discretionary cash flow consists of cash provided by operating
activities before changes in working capital items. Management uses
discretionary cash flow as a measure of liquidity and believes it provides
useful information to investors because it assesses cash flow from operations
for each period before changes in working capital, which fluctuates due to the
timing of collections of receivables and the settlements of liabilities. The
following table provides a reconciliation of cash provided by operating
activities, the most directly comparable GAAP measure, to adjusted
discretionary cash flow for the period presented.
(in millions)
|
|
For the Three Months
Ended June 30, 2010
|
|
For the Three Months
Ended June 30, 2009
|
|
Net cash provided by
operating activities
|
|
$
|
71.4
|
|
$
|
51.1
|
|
Add back: Net increase
(decrease) in current assets
|
|
19.0
|
|
(5.0
|
)
|
Add back: Net decrease in
current liabilities including book overdraft
|
|
12.8
|
|
8.8
|
|
Add back: Recovery of
Flying J bad debt
|
|
38.5
|
|
|
|
Discretionary cash flow
|
|
$
|
141.7
|
|
$
|
54.9
|
|
36
Table of
Contents
Berry Petroleum Company
Quantitative and Qualitative
Disclosures About Market Risk
Item 3. Quantitative and Qualitative Disclosures
About Market Risk
As
discussed in Note 3 to the Condensed Financial Statements, to minimize the
effect of a downturn in oil and gas prices and protect our profitability and
the economics of our development plans, we enter into crude oil and natural gas
derivative 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 our future financial
commitments. This price hedging program is designed to moderate the effects of
a severe crude oil and natural gas price downturn while allowing us to
participate in some commodity price increases. In California, we benefit from
lower natural gas pricing, as we are a consumer of natural gas in our
operations, and elsewhere we benefit from higher natural gas pricing. We have
hedged, and may hedge in the future, both natural gas purchases and sales as
determined appropriate by management. Management regularly monitors the crude
oil and natural gas markets and our financial commitments to determine if,
when, and at what level some form of crude oil and/or natural gas hedging
and/or basis adjustments or other price protection is appropriate and in
accordance with policy established by our board of directors. Currently, our derivatives are in the form of
swaps and collars. However, we may use a
variety of derivative instruments in the future to hedge WTI or the index gas
price. A two-way collar is a combination
of options, a sold call and purchased put.
The purchased put establishes a minimum price (floor) and the sold call
establishes a maximum price (ceiling) we will receive for the volumes under
contract. A three-way collar is a
combination of options, a sold call, a purchased put and a sold put. The
purchased put establishes a minimum price unless the market price falls below
the sold put, at which point the minimum price would be NYMEX plus the
difference between the purchased put and the sold put strike price. The sold call establishes a maximum price
(the ceiling) we will receive for the volumes under contract. We utilize costless collars which is an
options position by which the proceeds from the sale of the call option fund
the purchase of a put option.
In total, we have approximately 75% and 45% of our
expected 2010 and 2011 oil production, respectively, hedged in the form of
swaps and collars. In total, we have
approximately 30% and 20% of our 2010 and 2011 expected natural gas production,
respectively, hedged in the form of swaps and collars. A ten dollar change in oil prices impacts our
annual operating cash flow by approximately $8 million. A one dollar change in natural gas prices
impacts annual operating cash flow by approximately $2 million.
37
Table of Contents
The
following table summarizes our commodity derivative position as of June 30,
2010:
Term
|
|
Average
Barrels
Per Day
|
|
Average
Prices
|
|
Crude Oil Sales (NYMEX WTI) Two-Way Collars
|
|
|
|
|
|
Full year 2010
|
|
1,000
|
|
$65.15 / $75.00
|
|
Full year 2010
|
|
1,000
|
|
$65.50 / $78.50
|
|
Full year 2010
|
|
280
|
|
$80.00 / $90.00
|
|
Full year 2010
|
|
1,000
|
|
$100.00/$161.10
|
|
Full year 2010
|
|
1,000
|
|
$100.00/$150.30
|
|
Full year 2010
|
|
1,000
|
|
$100.00/$160.00
|
|
Full year 2010
|
|
1,000
|
|
$100.00/$150.00
|
|
Full year 2010
|
|
1,000
|
|
$100.00/$158.50
|
|
Full year 2010
|
|
1,000
|
|
$70.00/$86.00
|
|
Full year 2010
|
|
500
|
|
$75.00/$93.95
|
|
Full year 2010
|
|
500
|
|
$75.00/$94.45
|
|
Full year 2011
|
|
270
|
|
$80.00 / $90.00
|
|
Full year 2011
|
|
1,000
|
|
$55.20/$70.00
|
|
Full year 2011
|
|
1,000
|
|
$55.00 / $70.50
|
|
Full year 2011
|
|
1,000
|
|
$55.00/$68.65
|
|
Full year 2011
|
|
1,000
|
|
$55.00/$68.00
|
|
Full year 2011
|
|
1,000
|
|
$55.00/$71.20
|
|
Full year 2011
|
|
1,000
|
|
$60.00/$76.00
|
|
Full year 2011
|
|
1,000
|
|
$60.00/$81.25
|
|
Full year 2011
|
|
500
|
|
$75.00/$100.75
|
|
Full year 2011
|
|
500
|
|
$75.00/$101.15
|
|
Full year 2011
|
|
1,000
|
|
$75.00/$91.25
|
|
Full year 2012
|
|
1,000
|
|
$63.00/$82.60
|
|
Full year 2012
|
|
1,000
|
|
$63.00/$83.50
|
|
Full year 2012
|
|
1,000
|
|
$70.00/$93.00
|
|
Full year 2012
|
|
500
|
|
$75.00/$105.00
|
|
Full year 2012
|
|
500
|
|
$75.00/$106.00
|
|
Full year 2012
|
|
1,000
|
|
$75.00/$95.00
|
|
|
|
|
|
|
|
Crude Oil Sales (NYMEX WTI) Three-Way Collars
|
|
|
|
|
|
Full year 2011
|
|
1,000
|
|
$60.00/$80.00/$101.00
|
|
Full year 2012
|
|
1,000
|
|
$60.00/$80.00/$120.00
|
|
|
|
|
|
|
|
Crude Oil Sales (NYMEX WTI) Swaps
|
|
|
|
|
|
|
Full year 2010
|
|
1,000
|
|
$61.00
|
|
Full year 2010
|
|
1,000
|
|
$61.25
|
|
Full year 2010
|
|
1,000
|
|
$64.80
|
|
Full year 2010
|
|
1,000
|
|
$62.03
|
|
Full year 2010
|
|
1,000
|
|
$63.00
|
|
Full year 2010
|
|
1,000
|
|
$63.75
|
|
Full year 2010
|
|
650
|
|
$56.90
|
|
Full year 2011
|
|
500
|
|
$57.36
|
|
Full year 2011
|
|
500
|
|
$57.40
|
|
Full year 2011
|
|
500
|
|
$57.50
|
|
Full year 2011
|
|
250
|
|
$61.80
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH) Two-way Collars
|
|
|
|
|
|
Full year 2010
|
|
2,000
|
|
$6.00/$8.60
|
|
Full year 2010
|
|
3,000
|
|
$6.00/$8.65
|
|
Full year 2010
|
|
1,000
|
|
$6.50/$8.75
|
|
Full year 2010
|
|
1,000
|
|
$6.50/$8.85
|
|
Full year 2010
|
|
2,000
|
|
$6.50/$8.90
|
|
|
|
|
|
|
|
|
38
Table of Contents
Full year 2011
|
|
5,000
|
|
$6.00/$7.25
|
|
Full year 2012
|
|
5,000
|
|
$6.00/$7.70
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH TO PEPL) Basis Swaps
|
|
|
|
|
|
Full year 2010
|
|
2,000
|
|
$1.05
|
|
Full year 2010
|
|
3,000
|
|
$1.00
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH TO NGPL) Basis Swaps
|
|
|
|
|
|
Full year 2010
|
|
2,000
|
|
$0.49
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH TO HSC) Basis Swaps
|
|
|
|
|
|
Full year 2010
|
|
2,000
|
|
$0.38
|
|
Full year 2010
|
|
2,500
|
|
$0.35
|
|
Full year 2011
|
|
2,500
|
|
$0.33
|
|
Full year 2012
|
|
2,500
|
|
$0.32
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH TO NGPL-Tex OK)
Basis Swaps
|
|
|
|
|
|
Full year 2010
|
|
2,500
|
|
$0.42
|
|
Full year 2011
|
|
2,500
|
|
$0.46
|
|
Full year 2012
|
|
2,500
|
|
$0.44
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH) Swaps
|
|
|
|
|
|
Full year 2010
|
|
5,000
|
|
$5.73
|
|
Full year 2010
|
|
5,000
|
|
$6.02
|
|
Full year 2011
|
|
5,000
|
|
$5.50
|
|
Full year 2011
|
|
5,000
|
|
$6.89
|
|
Full year 2012
|
|
5,000
|
|
$5.75
|
|
Full year 2012
|
|
5,000
|
|
$7.16
|
|
The
related cash flow impact of all of our derivatives is reflected in cash flows
from operating activities.
Based on average NYMEX futures prices as of June 30,
2010 (WTI $79.43; HH $5.49) for the term of our derivatives we would expect to
make pre-tax future cash payments or to receive payments over the remaining
term of our crude oil and natural gas derivatives in place as follows:
|
|
June 30, 2010
|
|
Impact of percent change in futures prices
on pre-tax future cash (payments) and receipts
|
|
|
|
NYMEX Futures
|
|
-40%
|
|
-20%
|
|
+ 20%
|
|
+40%
|
|
Average WTI Futures Price
(2010 2012)
|
|
$
|
79.43
|
|
$
|
47.66
|
|
$
|
63.54
|
|
$
|
95.31
|
|
$
|
111.20
|
|
Average HH Futures Price
(2010 2012)
|
|
5.49
|
|
3.29
|
|
4.39
|
|
6.59
|
|
7.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil gain/(loss) (in
millions)
|
|
$
|
(29.9
|
)
|
$
|
196.2
|
|
$
|
66.9
|
|
$
|
(129.4
|
)
|
$
|
(227.7
|
)
|
Natural Gas gain/(loss)
(in millions)
|
|
11.6
|
|
54.1
|
|
34.5
|
|
(1.0
|
)
|
(16.2
|
)
|
Total
|
|
$
|
(18.3
|
)
|
$
|
250.3
|
|
$
|
101.4
|
|
$
|
(130.4
|
)
|
$
|
(243.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net pre-tax future cash
(payments) and receipts by year (in millions) based on average price in each
year:
|
|
|
|
|
|
|
|
|
|
|
|
2010 (WTI $76.45; HH
$4.94)
|
|
5.3
|
|
103.8
|
|
53.0
|
|
(35.7
|
)
|
(75.4
|
)
|
2011 (WTI $79.31; HH
$5.46)
|
|
(28.1
|
)
|
76.0
|
|
20.4
|
|
(87.2
|
)
|
(147.7
|
)
|
2012 (WTI $81.03; HH
$5.79)
|
|
4.5
|
|
70.5
|
|
28.0
|
|
(7.5
|
)
|
(20.8
|
)
|
Total
|
|
$
|
(18.3
|
)
|
$
|
250.3
|
|
$
|
101.4
|
|
$
|
(130.4
|
)
|
$
|
(243.9
|
)
|
Interest Rates.
Our exposure
to changes in interest rates results primarily from long-term debt. In
October 2006, we issued, in a public offering, $200 million principal
amount of 8.25% senior subordinated notes due 2016. In May 2009, we issued, in a public
offering, $325 million of 10.25% senior notes due 2014. In August 2009, we issued, in a public
offering, an additional $125 million of 10.25% senior notes due 2014. At June 30, 2010, total long-term debt
outstanding was $947.7 million. Interest on amounts borrowed under our credit
facility is charged at LIBOR plus 2.25% to 3.0% plus the credit facilitys margin
through July 15, 2012. Based on June 30, 2010 credit facility borrowings,
a 1% change in interest rates, including our interest rate derivatives, would
have an annualized $0.4 million after tax impact on our Condensed Financial
Statements.
39
Table of Contents
We
have entered into interest rate derivatives as shown below to swap the floating
rate under our senior secured credit facility (LIBOR) for a fixed interest
rate.
Derivative Term
|
|
Notional
Amount
$MM
|
|
Fixed Rate
|
|
4/1/2009 6/30/2012
|
|
100
|
|
4.74
|
%
|
4/15/2009 7/15/2012
|
|
100
|
|
1.99
|
%
|
9/15/2009 7/15/2012
|
|
50
|
|
2.31
|
%
|
As
of June 30, 2010, as a result of our interest rate derivative contracts and the
Notes, we have a total of $900 million of fixed rate positions averaging 7.8%.
Berry Petroleum Company
Controls and Procedures
Item 4. Controls and Procedures
As
of June 30, 2010, we have carried out an evaluation under the supervision of,
and with the participation of, our management, including our Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to
Rule 13a-15 under the Securities Exchange Act of 1934, as amended.
Based
on their evaluation as of June 30, 2010, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls and procedures
(as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities
Exchange Act of 1934) are effective to ensure that the information required to
be disclosed by us in the reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information
required to be disclosed by us in such reports is accumulated and communicated
to our management, including our principal executive officer and principal
financial officer, as appropriate to allow timely decisions regarding required
disclosure.
There
was no change in our internal control over financial reporting that occurred
during the three months ended June 30, 2010 that have materially affected, or
are reasonably likely to materially affect, our internal control over financial
reporting. We may make changes in our internal control procedures from time to
time in the future.
Forward
Looking Statements
Safe
harbor under the Private Securities Litigation Reform Act of 1995: Any
statements in this Form 10-Q that are not historical facts are
forward-looking statements that involve risks and uncertainties. Words such as plan,
will, intend, continue, target(s), expect, achieve, future, may,
could, goal(s), anticipate, estimate or other comparable words or
phrases, or the negative of those words, and other words of similar meaning
indicate forward-looking statements and important factors which could affect
actual results. Forward-looking statements are made based on managements
current expectations and beliefs concerning future developments and their
potential effects upon Berry Petroleum Company. These items are discussed at
length in Part I, Item 1A on page 17 of our Annual Report on
Form 10-K for the year ended December 31, 2009, filed with the SEC on
February 25, 2010, under the heading Risk Factors and all material
changes are updated in Part II, Item 1A within this Form 10-Q.
40
Table of Contents
Berry Petroleum Company
Signature
PART II. OTHER INFORMATION
Item 1. Legal
Proceedings
While we are, from time to
time, a party to certain lawsuits in the ordinary course of business, we do not
believe any of such existing lawsuits will have a material adverse effect on
our operations, financial condition, or liquidity.
Item
1A. Risk Factors
For
additional information about our risk factors, see Item 1A of our Annual Report
on Form 10-K for the year ended December 31, 2009 filed with the SEC on
February 25, 2010.
Item
2. Unregistered Sales of Equity
Securities and Use of Proceeds
None.
Item 3.
Defaults Upon Senior Securities
None.
Item 4. Removed
and Reserved
Item 5. Other
Information
None.
Item 6.
Exhibits
Exhibit No.
|
|
Description of Exhibit
|
|
|
|
10.1*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan (filed as Exhibit 4.3 to the
Registrants Form S-8 filed on June 23, 2010, File No. 333-167698).
|
10.2*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan Form of Restricted Stock Unit
Agreement (filed as Exhibit 4.4 to the Registrants Form S-8 filed on June
23, 2010, File No. 333-167698).
|
10.3*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan Form of Restricted Stock Unit
Agreement Officers (filed as Exhibit 4.5 to the Registrants Form S-8 filed
on June 23, 2010, File No. 333-167698).
|
10.4*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan Form of Restricted Stock Unit
Agreement Directors (filed as Exhibit 4.6 to the Registrants Form S-8
filed on June 23, 2010, File No. 333-167698).
|
10.5*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan Form of Stock Option Agreement
(filed as Exhibit 4.7 to the Registrants Form S-8 filed on June 23, 2010,
File No. 333-167698).
|
10.6*
|
|
Berry
Petroleum Company 2010 Equity Incentive Plan Form of Stock Appreciation
Rights Agreement (filed as Exhibit 4.8 to the Registrants Form S-8 filed on
June 23, 2010, File No. 333-167698).
|
12.1
|
|
Computation
of Ratio of Earnings to Fixed Charges
|
31.1
|
|
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
|
32.1
|
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
101.INS
|
|
XBRL Instance Document**
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document**
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document**
|
101.LAB
|
|
XBRL Taxonomy Label Linkbase Document**
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document**
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document**
|
*
Incorporated herein by reference
**
To be filed by amendment
41
Table of Contents
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
BERRY PETROLEUM COMPANY
|
|
|
|
/s/
Jamie L. Wheat
|
|
Jamie
L. Wheat
|
|
Controller
|
|
(Principal
Accounting Officer)
|
|
Date: August
9, 2010
|
|
42
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