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
March 31, 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 April 19, 2010, the registrant had
51,131,921 shares of Class A Common Stock ($.01 par value) outstanding.
The registrant also had 1,797,784 shares of Class B Stock ($.01 par value)
outstanding on April 19, 2010 all of which is held by an affiliate of the
registrant.
Table of Contents
BERRY
PETROLEUM COMPANY
FIRST QUARTER 2010 FORM 10-Q
TABLE OF CONTENTS
2
Table
of Contents
BERRY PETROLEUM COMPANY
Unaudited Condensed Balance Sheets
(In Thousands, Except Share
Information)
|
|
March 31,
2010
|
|
December 31,
2009
|
|
ASSETS
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
57
|
|
$
|
5,311
|
|
Short-term
investments
|
|
65
|
|
66
|
|
Accounts
receivable, net of allowance for doubtful accounts of $38,508
|
|
84,764
|
|
74,337
|
|
Deferred
income taxes
|
|
10,274
|
|
5,623
|
|
Fair
value of derivatives
|
|
6,164
|
|
11,527
|
|
Prepaid
expenses and other
|
|
10,878
|
|
6,612
|
|
Total
current assets
|
|
112,202
|
|
103,476
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment, net
|
|
2,269,848
|
|
2,106,385
|
|
Fair
value of derivatives
|
|
2,369
|
|
735
|
|
Other
assets
|
|
27,973
|
|
29,539
|
|
|
|
$
|
2,412,392
|
|
$
|
2,240,135
|
|
LIABILITIES
AND SHAREHOLDERS EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts
payable
|
|
$
|
76,641
|
|
$
|
63,096
|
|
Revenue
and royalties payable
|
|
16,909
|
|
25,878
|
|
Accrued
liabilities
|
|
42,498
|
|
29,320
|
|
Fair
value of derivatives
|
|
44,851
|
|
33,843
|
|
Total
current liabilities
|
|
180,899
|
|
152,137
|
|
Long-term
liabilities:
|
|
|
|
|
|
Deferred
income taxes
|
|
251,913
|
|
237,161
|
|
Senior
secured revolving credit facility
|
|
270,000
|
|
372,000
|
|
8¼ %
Senior subordinated notes due 2016
|
|
200,000
|
|
200,000
|
|
10¼%
Senior notes due 2014, net of unamortized discount of $12,877 and $13,456,
respectively
|
|
437,124
|
|
436,544
|
|
Asset
retirement obligation
|
|
46,919
|
|
43,487
|
|
Other
long-term liabilities
|
|
20,150
|
|
19,711
|
|
Fair
value of derivatives
|
|
57,773
|
|
75,836
|
|
|
|
1,283,879
|
|
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; 51,126,421 shares issued and
outstanding (42,952,499 in 2009)
|
|
511
|
|
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
|
|
316,313
|
|
89,068
|
|
Accumulated
other comprehensive loss
|
|
(56,972
|
)
|
(60,372
|
)
|
Retained
earnings
|
|
687,744
|
|
674,115
|
|
Total
shareholders equity
|
|
947,614
|
|
703,259
|
|
|
|
$
|
2,412,392
|
|
$
|
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
Three Months Ended March 31,
2010 and 2009
(In Thousands, Except Per Share Data)
|
|
Three months ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
Sales
of oil and gas
|
|
$
|
147,807
|
|
$
|
127,869
|
|
Sales
of electricity
|
|
9,933
|
|
10,270
|
|
Gas
marketing
|
|
8,272
|
|
7,581
|
|
Realized
and unrealized gain on derivatives, net
|
|
1,603
|
|
37,164
|
|
Interest
and other income, net
|
|
164
|
|
283
|
|
|
|
167,779
|
|
183,167
|
|
EXPENSES
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
47,036
|
|
37,384
|
|
Operating
costs - electricity generation
|
|
9,670
|
|
8,783
|
|
Production
taxes
|
|
5,204
|
|
5,652
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
35,907
|
|
36,398
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
795
|
|
959
|
|
Gas
marketing
|
|
7,786
|
|
7,284
|
|
General
and administrative
|
|
13,835
|
|
13,294
|
|
Interest
expense
|
|
17,447
|
|
10,050
|
|
Transaction
costs on acquisitions, net of gain
|
|
727
|
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
1,369
|
|
122
|
|
|
|
139,776
|
|
119,926
|
|
Income
before income taxes
|
|
28,003
|
|
63,241
|
|
Provision
for income taxes
|
|
10,334
|
|
21,462
|
|
Income
from continuing operations
|
|
17,669
|
|
41,779
|
|
Loss
from discontinued operations, net of taxes
|
|
|
|
(6,781
|
)
|
|
|
|
|
|
|
Net
income
|
|
$
|
17,669
|
|
$
|
34,998
|
|
|
|
|
|
|
|
Basic
net income from continuing operations per share
|
|
$
|
0.34
|
|
$
|
0.92
|
|
Basic
net loss from discontinued operations per share
|
|
$
|
|
|
$
|
(0.15
|
)
|
Basic
net income per share
|
|
$
|
0.34
|
|
$
|
0.77
|
|
|
|
|
|
|
|
Diluted
net income from continuing operations per share
|
|
$
|
0.34
|
|
$
|
0.92
|
|
Diluted
net loss from discontinued operations per share
|
|
$
|
|
|
$
|
(0.15
|
)
|
Diluted
net income per share
|
|
$
|
0.34
|
|
$
|
0.77
|
|
|
|
|
|
|
|
Dividends
per share
|
|
$
|
0.075
|
|
$
|
0.075
|
|
Unaudited Condensed Statements of
Comprehensive Income
Three Months Ended March 31,
2010 and 2009
(In Thousands)
Net
income
|
|
$
|
17,669
|
|
$
|
34,998
|
|
Unrealized
gains on derivatives, net of income taxes of $0 and $48,160, respectively
|
|
|
|
78,577
|
|
Reclassification
of realized gains on derivatives included in net income, net of income tax
benefits of $2,084 and $17,788, respectively
|
|
(3,400
|
)
|
(29,022
|
)
|
Comprehensive
income
|
|
$
|
14,269
|
|
$
|
84,553
|
|
The accompanying notes are an integral part of these
condensed financial statements.
4
Table of Contents
BERRY PETROLEUM COMPANY
Unaudited Condensed Statements of
Cash Flows
Three Months Ended March 31,
2010 and 2009
(In Thousands)
|
|
Three months ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
Net
income
|
|
$
|
17,669
|
|
$
|
34,998
|
|
Depreciation,
depletion and amortization
|
|
36,702
|
|
39,545
|
|
Amortization
of debt issue costs and net discount
|
|
2,098
|
|
1,088
|
|
Gain
on purchase of oil and natural gas properties
|
|
(1,358
|
)
|
|
|
Dry
hole and impairment
|
|
1,207
|
|
9,643
|
|
Unrealized
loss (gain) on derivatives
|
|
2,476
|
|
(22,842
|
)
|
Stock-based
compensation expense
|
|
3,031
|
|
2,988
|
|
Deferred
income taxes
|
|
8,548
|
|
21,059
|
|
Other,
net
|
|
|
|
(5,040
|
)
|
Cash
paid for abandonment
|
|
(22
|
)
|
(112
|
)
|
Change
in book overdraft
|
|
(1,377
|
)
|
(23,510
|
)
|
Increase
in current assets other than cash and cash equivalents
|
|
(14,179
|
)
|
(12,933
|
)
|
Increase
(decrease) in current liabilities other than book overdraft, line of credit
and fair value of derivatives
|
|
8,720
|
|
(36,755
|
)
|
Net
cash provided by operating activities
|
|
63,515
|
|
8,129
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
(47,958
|
)
|
(50,181
|
)
|
Property
acquisitions
|
|
(132,515
|
)
|
(1,173
|
)
|
Capitalized
interest
|
|
(5,967
|
)
|
(5,312
|
)
|
Deposits
on asset sales
|
|
|
|
14,000
|
|
Deposits
on potential property acquisitions
|
|
(500
|
)
|
|
|
Net
cash used in investing activities
|
|
(186,940
|
)
|
(42,666
|
)
|
Cash
flows from financing activities:
|
|
|
|
|
|
Proceeds
from issuances on line of credit
|
|
76,100
|
|
147,800
|
|
Payments
on line of credit
|
|
(76,100
|
)
|
(173,100
|
)
|
Long-term
borrowings under credit facility
|
|
125,000
|
|
159,600
|
|
Repayments
of long-term borrowings under credit facility
|
|
(227,000
|
)
|
(92,000
|
)
|
Debt
issue costs
|
|
|
|
(4,538
|
)
|
Financing
obligation
|
|
(83
|
)
|
|
|
Dividends
paid
|
|
(4,040
|
)
|
(3,416
|
)
|
Proceeds
from issuance of common stock, net
|
|
224,337
|
|
|
|
Proceeds
from stock option exercises
|
|
75
|
|
|
|
Excess
tax benefit and other
|
|
(118
|
)
|
|
|
Net
cash provided by financing activities
|
|
118,171
|
|
34,346
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
(5,254
|
)
|
(191
|
)
|
Cash
and cash equivalents at beginning of year
|
|
5,311
|
|
240
|
|
Cash
and cash equivalents at end of period
|
|
$
|
57
|
|
$
|
49
|
|
The accompanying notes are an integral part of these
condensed financial statements.
5
Table
of Contents
Berry
Petroleum Company
Notes to
Unaudited Financial Statements
1.
Basis of Presentation
These unaudited Condensed
Financial Statements have been prepared in accordance with accounting
principles generally accepted in the United States (GAAP) for interim financial
reporting. All adjustments which are, in the opinion of management,
necessary for a fair statement of Berry Petroleum Companys (the Company)
financial position at March 31, 2010 and December 31, 2009 and
results of operations and accumulated other comprehensive loss (AOCL) for the
three months ended March 31, 2010 and 2009, and its cash flows for the
three months ended March 31, 2010 and 2009 have been included. In the
opinion of management, all adjustments, which are of a normal recurring nature,
have been made which are necessary for a fair presentation of the financial
position. 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 initially established.
The unaudited Condensed
Financial Statements have been prepared on a basis consistent with the
accounting principles and policies reflected in the December 31, 2009
Financial Statements. For a more
complete understanding of the Companys operations, financial position and
accounting policies, the Unaudited Condensed Financial Statements and the notes
thereto should be read in conjunction with the Companys Annual Report on Form 10-K
for the year ended December 31, 2009 previously filed with the SEC. The
year-end Condensed Balance Sheet was derived from audited Financial Statements,
but does not include all disclosures required by GAAP.
The Companys cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at March 31, 2010 and December 31,
2009 is $14.4 million and $15.7 million, respectively, representing outstanding
checks in excess of the bank balance (book overdraft).
2.
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 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.
6
Table of
Contents
Berry
Petroleum Company
Notes to
Unaudited Financial Statements
The following tables set forth by level within the fair value hierarchy
the Companys derivative assets and liabilities that were measured at fair
value on a recurring basis as of March 31, 2010 and December 31,
2009.
Assets and liabilities measured
at fair value on a recurring basis
March 31, 2010 (in millions)
|
|
Total carrying value on the
Condensed Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivatives liability
|
|
$
|
(83.7
|
)
|
$
|
(49.2
|
)
|
$
|
(34.5
|
)
|
Interest rate
derivatives liability
|
|
(10.4
|
)
|
(10.4
|
)
|
|
|
Total derivative liabilities at fair value
|
|
$
|
(94.1
|
)
|
$
|
(59.6
|
)
|
$
|
(34.5
|
)
|
December 31, 2009 (in millions)
|
|
Total carrying value on the
Condensed Balance Sheet
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
Commodity derivatives liability
|
|
$
|
(88.5
|
)
|
$
|
(62.5
|
)
|
$
|
(26.0
|
)
|
Interest rate
derivatives liability
|
|
(8.9
|
)
|
(8.9
|
)
|
|
|
Total derivative liabilities 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).
(in millions)
|
|
Three months ended
March 31, 2010
|
|
Three months ended
March 31, 2009
|
|
|
|
|
|
|
|
Fair value (liability)
asset, beginning of period
|
|
$
|
(26.0
|
)
|
$
|
172.5
|
|
Total realized and
unrealized gains included in Realized
and unrealized gain on derivatives
|
|
(1.4
|
)
|
(22.9
|
)
|
Purchases, sales and
settlements, net
|
|
(7.1
|
)
|
(15.5
|
)
|
Transfers in and/or out
of Level 3
|
|
|
|
3.4
|
|
Fair value (liability)
asset, end of period
|
|
$
|
(34.5
|
)
|
$
|
137.5
|
|
|
|
|
|
|
|
Total unrealized
(losses) gains included in income related to financial assets and
liabilities still on the Condensed Balance Sheet at March 31, 2010 and
2009
|
|
$
|
(8.4
|
)
|
$
|
22.8
|
|
The $3.4 million of
transfers out of Level 3 for the three months ended March 31, 2009
represent crude oil collars that were converted to crude oil swaps during the
first quarter of 2009.
For further discussion
related to the Companys derivatives see Note 3 to the Condensed Financial
Statements.
7
Table of
Contents
Berry
Petroleum Company
Notes to
Unaudited Financial Statements
Fair Market Value
of Financial Instruments
The Company used various assumptions and methods in
estimating the fair values of its financial instruments. The carrying amounts
of cash and cash equivalents and accounts receivable approximated their fair
value due to the short-term maturity of these instruments. The carrying amount
of the Companys credit facilities approximated fair value, because the
interest rates on the credit facilities are variable. The fair values of the
8.25% senior subordinated notes due 2016 and the 10.25% senior notes due 2014
were estimated based on quoted market prices. The fair values of the Companys
derivative instruments and other investments are discussed above.
|
|
As of
March 31, 2010
|
|
(in millions)
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
|
|
|
|
|
|
Senior secured revolving credit facility
|
|
$
|
270
|
|
$
|
270
|
|
8.25% Senior subordinated notes due 2016
|
|
200
|
|
202
|
|
10.25% Senior notes due 2014
|
|
437
|
|
495
|
|
|
|
$
|
907
|
|
$
|
967
|
|
|
|
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
|
|
3.
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 in an attempt to normalize the mix of fixed
and floating interest rates within its debt portfolio.
The Companys derivative contracts have been executed
primarily with counterparties that are party to its senior secured revolving
credit facility.
Neither the Company nor its counterparties are
required to post collateral in connection with its derivative positions and
netting agreements are in place with each of the Companys counterparties
allowing the Company to offset its derivative asset and liability
positions. The credit rating of each of
these counterparties was AA-/Aa3, or better as of March 31, 2010. As of March 31, 2010, the Companys
largest three counterparties accounted for 74% of the value of its total
derivative positions.
As of March 31, 2010, the Company had the
following commodity derivatives:
|
|
2010
|
|
2011
|
|
2012
|
|
Oil Bbl/D:
|
|
15,930
|
|
11,020
|
|
5,000
|
|
Natural Gas MMBtu/D:
|
|
19,000
|
|
10,000
|
|
10,000
|
|
For further discussion related to the fair value of the Companys
derivatives see Note 2 to the Condensed Financial Statements.
8
Table of
Contents
Berry
Petroleum Company
Notes to
Unaudited Financial Statements
The Company entered into the following crude oil collars during the three
months ended March 31, 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
|
|
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
AOCL. Effective January 1, 2010,
however, 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
months ended March 31, 2010, $5.5 million ($3.4 million, net of tax) of
derivative losses relating to de-designated commodity and interest rate hedges
were reclassified from AOCL into earnings.
As of March 31, 2010, AOCL consisted of $91.9 million ($57.0
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 $22.7 million
related to de-designated commodity and interest rate derivative contracts
during the next twelve months.
At March 31, 2010, the net fair value derivative
liability was $94.1 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 March 31, 2010, the
Company expects to make payments under the existing derivatives of $35.3
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.
9
Table of
Contents
Berry
Petroleum Company
Notes to
Unaudited Financial Statements
The following table disaggregates the Companys net derivative assets
and liabilities into gross components on a contract-by-contract basis before
giving effect to master netting arrangements. Finally, the Company
identifies the line items on its 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 March 31, 2010
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
(in millions)
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
Total derivatives
designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Oil
|
|
Current assets
|
|
$
|
4.5
|
|
Current liability
|
|
$
|
44.9
|
|
Commodity Oil
|
|
|
|
|
|
Long term liabilities
|
|
57.6
|
|
Commodity Natural Gas
|
|
Current assets
|
|
5.2
|
|
|
|
|
|
Commodity Natural Gas
|
|
Current liability
|
|
3.0
|
|
|
|
|
|
Commodity Natural Gas
|
|
Long term assets
|
|
2.4
|
|
|
|
|
|
Commodity Natural Gas
|
|
Long term liabilities
|
|
3.6
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
Current assets
|
|
3.5
|
|
Interest rate contracts
|
|
|
|
|
|
Current liability
|
|
3.0
|
|
Interest rate contracts
|
|
|
|
|
|
Long term liabilities
|
|
3.8
|
|
Total derivatives not
designated as hedging instruments
|
|
18.7
|
|
|
|
112.8
|
|
Total Derivatives
|
|
|
|
$
|
18.7
|
|
|
|
$
|
112.8
|
|
|
|
As of December 31, 2009
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
(in millions)
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Balance Sheet
Classification
|
|
Fair Value
|
|
Commodity Oil
|
|
Current assets
|
|
$
|
14.2
|
|
Current liability
|
|
$
|
30.8
|
|
Commodity Oil
|
|
|
|
|
|
Long term liabilities
|
|
74.1
|
|
Commodity Natural Gas
|
|
Current assets
|
|
1.3
|
|
|
|
|
|
Commodity Natural Gas
|
|
Long term assets
|
|
0.4
|
|
|
|
|
|
Commodity Natural Gas
|
|
Current liability
|
|
0.2
|
|
|
|
|
|
Commodity Natural Gas
|
|
Long term liabilities
|
|
1.2
|
|
|
|
|
|
Interest rate contracts
|
|
Long term assets
|
|
0.3
|
|
Current assets
|
|
3.5
|
|
Interest rate contracts
|
|
|
|
|
|
Current liabilities
|
|
2.7
|
|
Interest rate contracts
|
|
|
|
|
|
Long term liabilities
|
|
3.0
|
|
Total derivatives designated as hedging instruments under authoritative
guidance
|
|
$
|
17.6
|
|
|
|
$
|
114.1
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Natural Gas
|
|
|
|
|
|
Current assets
|
|
0.4
|
|
Commodity Natural Gas
|
|
|
|
|
|
Current liabilities
|
|
0.5
|
|
Total derivatives not designated as hedging instruments under
authoritative guidance
|
|
|
|
|
|
0.9
|
|
Total Derivatives
|
|
|
|
$
|
17.6
|
|
|
|
$
|
115.0
|
|
10
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
The
tables below summarize the location and the amount of derivative instrument
gains and losses reported in the Condensed Statements of Income for the periods
indicated. (in millions):
Three Months Ended March 31, 2010
Derivatives cash flow
hedging relationships
|
|
Amount of
Gain (Loss)
Recognized in
AOCL on
Derivative
(Effective
portion)
|
|
Location of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)
|
|
Amount of
Gain (Loss)
Reclassified
from AOCL
into Income
(Effective
Portion)
|
|
Location of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from Effectiveness
Testing)
|
|
Amount of
Gain (Loss)
Recognized in
Income of
Derivative
(Ineffective
Portion and
Amount
Excluded from
Effectiveness
Testing)
|
|
Commodity - Oil
|
|
$
|
|
|
Sales of oil and gas
|
|
$
|
(3.2
|
)
|
|
|
$
|
|
|
Commodity - Natural Gas
|
|
|
|
Sales of oil and gas
|
|
0.4
|
|
|
|
|
|
Interest rate
|
|
|
|
Interest expense
|
|
(2.7
|
)
|
|
|
|
|
Total
|
|
$
|
|
|
|
|
$
|
(5.5
|
)
|
|
|
$
|
|
|
Three Months Ended March 31, 2009
Derivatives cash flow
hedging relationships
|
|
Amount of
Gain (Loss)
Recognized in
AOCL on
Derivative
(Effective
portion)
|
|
Location of Gain
(Loss) Reclassified
from AOCL into
Income (Effective
Portion)
|
|
Amount of
Gain (Loss)
Reclassified
from AOCL
into Income
(Effective
Portion)
|
|
Location of Gain (loss)
Recognized in Income of
Derivative (Ineffective
Portion and Amount
Excluded from Effectiveness
Testing)
|
|
Amount of
Gain (Loss)
Recognized in
Income of
Derivative
(Ineffective
Portion and
Amount
Excluded from
Effectiveness
Testing)
|
|
Commodity - Oil
|
|
$
|
36.5
|
|
Sales of oil and gas
|
|
$
|
41.6
|
|
Realized and unrealized
gain on derivatives, net
|
|
$
|
14.3
|
|
Commodity - Natural Gas
|
|
8.9
|
|
Sales of oil and gas
|
|
6.6
|
|
|
|
|
|
Commodity - Oil
|
|
|
|
|
|
|
|
Realized and unrealized
gain on derivatives, net
|
|
22.7
|
|
Interest rate
|
|
(3.4
|
)
|
Interest expense
|
|
(1.0
|
)
|
|
|
|
|
Total
|
|
$
|
42.0
|
|
|
|
$
|
47.2
|
|
|
|
$
|
37.0
|
|
Amount
of gain or (loss) recognized in income on derivatives not designated as hedging
instruments under authoritative guidance for the three months ended March 31,
2010 and 2009:
Three Months Ended March 31, 2010
Derivatives not designated
as Hedging Instruments
under authoritative guidance
|
|
Location of Gain (Loss) Recognized in Income
on Derivative
|
|
Amount of Gain (Loss) Recognized
in Income on Derivatives not
designated as Hedging Instruments
under authoritative guidance
|
|
|
|
|
|
|
|
Commodity Oil
|
|
Realized and unrealized gain on derivatives, net
|
|
$
|
(7.5
|
)
|
Commodity - Natural Gas
|
|
Realized and unrealized gain on derivatives, net
|
|
12.4
|
|
Interest Rates
|
|
Realized and unrealized gain on derivatives, net
|
|
(3.3
|
)
|
Total derivatives not
designated as hedging instruments
|
|
$
|
1.6
|
|
11
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
Three
Months Ended March 31, 2009
Derivatives not designated
as Hedging Instruments
under authoritative guidance
|
|
Location of Gain (Loss) Recognized in Income
on Derivative
|
|
Amount of Gain (Loss) Recognized
in Income on Derivatives not
designated as Hedging Instruments
under authoritative guidance
|
|
|
|
|
|
|
|
Commodity Oil
|
|
Realized and unrealized gain on derivatives, net
|
|
$
|
0.2
|
|
Commodity - Natural Gas
|
|
Loss from discontinued operations, net of taxes
|
|
(0.5
|
)
|
Total derivatives not
designated as hedging instruments
|
|
$
|
(0.3
|
)
|
During
the three months ended March 31, 2010, the Company recorded a $1.6 million
gain under the caption Realized and
unrealized gain on derivatives, net resulting from a gain for the change
in fair value of $3.3 million, net of a loss for cash settlements of $1.7 million.
During the three months ended March 31, 2009,
the Company recorded a $37.2 million gain under the caption Realized and
unrealized gain on derivatives, net. In
conjunction with the sale of the DJ basin assets, during the first quarter of
2009, the Company concluded that the forecasted transaction in certain of its
hedging relationships was not probable of occurring. As such, the Company reclassified a gain of
$14.3 million from AOCL to the Condensed Statements of Income under the caption
Realized and unrealized gain on derivatives, net.
The Company also recognized an unrealized gain of
$22.9 million on the Condensed Statements of Income under the caption Realized and unrealized gain on derivatives,
net for the three months ended March 31, 2009, as a result of
ineffectiveness related to sales prices that were not highly correlated with
the Companys hedges. The Company
recorded an unrealized net loss of $0.5
million on the Condensed Statements of Income under the caption Loss
from discontinued operations, net of taxes during the first quarter of 2009 related to natural gas derivatives
entered into on behalf of the purchaser of the Companys DJ assets for which
the Company did not elect hedge accounting.
4
.
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
Wolfberry Acquisition and to repay a portion of the outstanding borrowings
under the senior secured revolving credit facility. See Note 5 to the Condensed Financial
Statements.
5
.
Acquisitions and Divestitures
Acquisitions
On March 5, 2010,
the Company acquired interests in producing properties principally on 6,900
acres in the Wolfberry trend in the Permian basin of West Texas (W. Texas) for
$132 million, including an initial purchase price of $126 million, and
customary post-closing adjustments of approximately $6 million (Wolfberry
Acquisition). The acquisition had an
effective date of January 1, 2010 and activity from January 1, 2010
through March 4, 2010 was a purchase price adjustment. The acquisition was financed with the
proceeds from the issuance of the Companys common stock in January of
2010. The Company operates
approximately 70% of, and has an average 68.5% working interest (54.1% net
revenue interest) in, the properties acquired in the Wolfberry trend.
The Wolfberry Acquisition
qualifies as a business combination and, as such, the Company estimated the
fair value of this property as of the March 5, 2010 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 fair value of the
properties acquired exceeded the consideration paid to the seller by $1.4
million which the Company recorded in the Condensed Statements of Income under
the caption Transaction costs on acquisitions, net of gain. The gain resulted from the changes in oil and
natural gas prices used to value the reserves.
12
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
The acquisition related
costs totaling $2.1 million have been recorded in the Condensed Statements of
Income under the caption Transaction costs on acquisitions, net of gain. Revenues of $1.7 million and earnings of $0.5
million generated by the acquired properties from March 5, 2010 to March 31,
2010 have been included in the accompanying Condensed Statements of Income.
The following table
summarizes the consideration paid to the seller and the amounts of the assets
acquired and liabilities assumed as of March 5, 2010. The purchase price allocation is preliminary
and subject to customary adjustments.
|
|
(In thousands)
|
|
Consideration
paid to seller:
|
|
|
|
Cash, net of accrued
purchase price adjustment
|
|
$
|
132,241
|
|
|
|
|
|
Recognized
amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
Proved developed and
undeveloped properties
|
|
134,649
|
|
Fair value of
derivatives
|
|
316
|
|
Asset retirement
obligation
|
|
(1,367
|
)
|
|
|
|
|
Total
identifiable net assets
|
|
$
|
133,598
|
|
In February 2010,
the Company entered into an agreement and paid a deposit of $0.5 million with a
private seller to acquire interests in producing properties in the Wolfberry
trend in W. Texas for approximately $14 million cash. This transaction closed in April 2010.
The initial accounting for the business combination is not complete pending
detailed analyses of the facts and circumstances that existed as of the
acquisition date.
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 aggregated within the $6.8
million Loss from discontinued operations, net of taxes, on its Condensed
Statement of Income for the three months ended March 31, 2009.
Loss from discontinued
operations, net of taxes, on the accompanying statements of income is comprised
of the following (in thousands):
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Total
revenues
|
|
|
|
$
|
6,018
|
|
Total
expenses
|
|
|
|
16,283
|
|
Loss
from discontinued operations, before income taxes
|
|
|
|
(10,265
|
)
|
Income
tax benefit
|
|
|
|
3,484
|
|
Loss
from discontinued operations, net of taxes
|
|
|
|
$
|
(6,781
|
)
|
6.
Dry hole,
abandonment, impairment and exploration
In the
first quarter of 2010 the Company incurred dry hole, abandonment, impairment
and exploration expense of $1.4 million, 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. In the first quarter of 2009 the Company had
dry hole, abandonment, impairment and exploration charges of $0.1 million.
13
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
7
.
Asset Retirement Obligation (ARO)
The
following table summarizes the change in the ARO for the three months ended March 31
(in thousands):
|
|
2010
|
|
2009
|
|
Beginning
balance at January 1
|
|
$
|
43,487
|
|
$
|
41,967
|
|
Liabilities
incurred
|
|
1,024
|
|
|
|
Liabilities
settled
|
|
(22
|
)
|
(113
|
)
|
Acquisition
of assets
|
|
1,367
|
|
|
|
Accretion
expense
|
|
1,063
|
|
1,002
|
|
Ending
balance at March 31
|
|
$
|
46,919
|
|
$
|
42,856
|
|
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.
8.
Debt Obligations
Short-term lines of credit
Borrowings under 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. In conjunction with the amendment to the Companys
senior secured credit facility, on July 15, 2008, the Secured Line of
Credit was collateralized by oil and natural gas properties representing at
least 80% of the present value of the Companys proved reserves.
There
were no outstanding borrowings on the Secured Line of Credit at March 31,
2010 or 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 March 31, 2010
and December 31, 2009 was 0%.
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 contains a
current ratio covenant which, as defined, must be at least 1.0. The total outstanding debt at March 31,
2010 under the Agreement, as amended, and the Line of Credit was $270 million
and zero, respectively, and $4 million in letters of credit have been issued
under the facility, leaving $664 million in borrowing capacity
available. The maximum amount available is subject to semi-annual
redeterminations of the borrowing base, based on the value of the Companys
proved oil and gas reserves, in April and October of each year in
accordance with the lenders customary procedures and
practices. Both the Company and the banks have the bilateral right
to one additional redetermination each year.
The Companys borrowing base was reconfirmed in April 2010. The Agreement is collateralized by oil and
natural gas properties representing at least 80% of the present value of the
Companys proved reserves. The Agreement
matures on July 15, 2012.
14
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
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 previously issued $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 Sub Notes and 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 March 31, 2010.
|
|
As of March 31, 2010
|
|
Current
Ratio (Not less than 1.0)
|
|
5.7
|
|
Total
Funded Debt Ratio to EBITDAX (Not greater than 4.50)
|
|
3.0
|
|
Interest
Coverage Ratio (Not less than 2.5)
|
|
3.7
|
|
Senior
Secured Debt Ratio to EBITDAX (Not greater than 3.75)
|
|
0.9
|
|
The weighted average
interest rate on the Companys total outstanding borrowings was 7.5% and 7.0%
at March 31, 2010 and December 31, 2009, respectively.
9.
Income Taxes
The
effective income tax rate was 36.9% for the first quarter of 2010 compared to
33.9% for the first quarter of 2009. The increase in rate for the first quarter
is primarily due to one-time reductions in deferred state taxes in the prior
quarter. Reductions in the rate during
the prior quarter were the result of acquisitions in more tax favorable
jurisdictions, reducing future state tax obligations in addition to 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 March 31,
2010, the Company had a gross liability for uncertain tax benefits of
$6.5 million of which $5.3 million, if recognized, would affect the
effective tax rate. 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 $0.8 million and $0.7 million of interest related to its
uncertain tax positions as of March 31, 2010 and December 31, 2009,
respectively.
15
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
10.
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. Stock
units issued to directors under the Companys stock incentive plans also have
the right to receive 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.
Therefore, restricted stock issued to employees prior to January 1, 2010
and stock units issued to directors are participating securities and earnings
must now be allocated to both common stock and these participating securities
under the two-class method.
The following
table shows the computation of basic and diluted net income (loss) per share
from continuing and discontinued operations for the three months ended March 31,
2010 and 2009 (in thousands):
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
2009
|
|
Net
income from continuing operations
|
|
$
|
17,669
|
|
$
|
41,779
|
|
Less:
Income allocable to participating securities
|
|
359
|
|
3,416
|
|
Income
available for shareholders
|
|
$
|
17,310
|
|
$
|
38,363
|
|
|
|
|
|
|
|
Net
loss from discontinued operations
|
|
$
|
|
|
$
|
(6,781
|
)
|
Less:
Income allocable to participating securities
|
|
|
|
|
|
Loss
from discontinued operations available for shareholders
|
|
$
|
|
|
$
|
(6,781
|
)
|
|
|
|
|
|
|
Basic
earnings per share from continuing operations
|
|
$
|
0.34
|
|
$
|
0.92
|
|
Basic
loss per share from discontinued operations
|
|
|
|
(0.15
|
)
|
Basic
earnings per share
|
|
$
|
0.34
|
|
$
|
0.77
|
|
|
|
|
|
|
|
Diluted
earnings per share from continuing operations
|
|
$
|
0.34
|
|
$
|
0.92
|
|
Diluted
loss per share from discontinued operations
|
|
|
|
(0.15
|
)
|
Diluted
earnings per share
|
|
$
|
0.34
|
|
$
|
0.77
|
|
|
|
|
|
|
|
Weighted
average shares outstanding - basic
|
|
51,076
|
|
44,581
|
|
Add:
dilutive effects of stock options
|
|
365
|
|
12
|
|
Weighted
average shares outstanding - dilutive
|
|
51,441
|
|
44,593
|
|
Options to purchase $1.2
million and $2.3 million shares were not included in the diluted earnings
(loss) per share calculation for the three months ended March 31, 2010 and
2009, respectively, because their effect would have been anti-dilutive.
16
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
11.
Commitments and
Contingencies
The
Companys contractual obligations not included in its Condensed Balance Sheet
as of March 31, 2010 (except Long-term debt and ARO) are as follows (in
millions):
|
|
Total
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Long-term
debt and interest
|
|
$
|
1,234
|
|
$
|
52
|
|
$
|
69
|
|
$
|
335
|
|
$
|
63
|
|
$
|
485
|
|
$
|
230
|
|
ARO
|
|
47
|
|
3
|
|
3
|
|
3
|
|
2
|
|
3
|
|
33
|
|
Operating
lease obligations
|
|
16
|
|
2
|
|
2
|
|
3
|
|
3
|
|
3
|
|
3
|
|
Drilling
and rig obligations
|
|
49
|
|
11
|
|
28
|
|
2
|
|
2
|
|
6
|
|
|
|
Firm
natural gas
transportation contracts
|
|
132
|
|
15
|
|
20
|
|
17
|
|
16
|
|
15
|
|
49
|
|
Total
|
|
$
|
1,478
|
|
$
|
83
|
|
$
|
122
|
|
$
|
360
|
|
$
|
86
|
|
$
|
512
|
|
$
|
315
|
|
Operating
leases
The
Company leases corporate and field offices in California, Colorado and Texas.
Rent expense with respect to its lease commitments was $0.5 million for both
the three months ended March 31, 2010 and 2009. In 2006, the Company
purchased an airplane for business travel which was subsequently sold and
contracted under a ten year operating lease beginning December 2006.
Drilling obligations
The Company amended and restated its Utah Lake Canyon
agreement in December 2009 and has a 14 gross well drilling commitment
over the amended term (December 2009 to December 2014). The Companys minimum obligation under this
exploration and development agreement is $14.7 million as of March 31,
2010. Also included in the table above
are the Companys contractual obligations on its Piceance assets in
Colorado. The Company must spud 120 wells by February 2011 to avoid
penalties of $0.2 million per well. The Company expects to meet all
obligations but its ability to meet this commitment depends on the capital
resources available to the Company to fund its activities to develop these
assets.
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 March 31,
2010 and 2009, the Company incurred $1.0 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 is $0.5 million and $0.3 million
for the three months ended March 31, 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.
17
Table of Contents
Berry
Petroleum Company
Notes
to Unaudited Financial Statements
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 2,427 Bbl/D in the first quarter of 2010.
In December 2008,
Flying J, Inc., and its wholly owned subsidiary Big West Oil and its
wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter 11
of the United States Bankruptcy Code.
Also in December 2008, BWOC informed the Company that it was unable
to receive the Companys California production.
Included in the allowance for doubtful accounts is $38.5 million due
from BWOC. Of the $38.5 million due from BWOC, $11.8 million represents 20 days
of the Companys December 2008 crude oil sales, an administrative claim
under the bankruptcy proceedings, and $26.7 million represents November 2008
and the balance of December 2008 crude oil sales which would have the same
priority as other general unsecured claims.
BWOC will also be liable to the Company for damages under this
contract. The Company has guarantees
from Big West Oil and from Flying J, Inc. in the amount of $75 million
each, in the event that the claim is not fully collectible from BWOC. While the
Company believes that it may recover some or all of the amounts due from BWOC,
the data received from the bankruptcy proceedings to date has not provided the
Company with adequate data from which to make a conclusion that any amounts
will be collected.
The Company has no
material accrued environmental liabilities for its sites, including sites in
which governmental agencies have designated the Company as a potentially
responsible party, because it is not probable that a loss will be incurred and
the minimum cost and/or amount of loss cannot be reasonably estimated. However,
because of the uncertainties associated with environmental assessment and
remediation activities, future expense to remediate the currently identified
sites, and sites identified in the future, if any, could be incurred.
Management believes, based upon current site assessments, that the ultimate
resolution of any matters will not result in substantial costs incurred. The
Company is involved in various other lawsuits, claims and inquiries, most of
which are routine to the nature of its business. In the opinion of management,
the resolution of these matters will not have a material effect on its
financial position, or on the results of operations or liquidity.
Certain of the Companys
royalty payment calculations are being disputed. The Company believes that its royalty
calculations are in accordance with applicable leases and other
agreements. However, the disputed
amounts that it may be required to pay are up to approximately $6 million.
In July 2009, the Company received a notice of proposed civil
penalty from the Bureau of Land Management (BLM) related to the Companys
alleged non-compliance during 2007 with regulations relating to the operation
and position of certain valves in its Uinta basin operations. The proposed civil penalty was $69.6 million
and reflects the theoretical maximum penalty amount under applicable
regulations, absent mitigating factors.
In 2007 the Company immediately remediated the instances of non-compliance,
cooperated fully with the BLMs investigation and the Company believes no
production was lost, all royalties were paid and there was no harm to the
environment. Due to the above mitigating factors, among others, the Company
believes this matter will be resolved by the payment of a penalty that will not
exceed $2.1 million and accrued such amount in the second quarter of 2009.
During the
California energy crisis in 2000 and 2001, the Company had electricity sales
contracts with various utilities and a portion of the electricity prices paid
to the Company under such contracts from December 2000 to March 27,
2001 has been under a degree of legal challenge since that time. It
is possible that the Company may have a liability pending the final outcome of
the 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.
18
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 unaudited Condensed Financial Statements. You should read this in conjunction with the
discussion under Managements Discussion and Analysis of Financial Conditions
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 unaudited 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.
Notable
First Quarter Items.
·
Achieved production averaging 29,391 BOE/D supported
by a 500 BOE/D increase in oil
·
Generated discretionary cash flow of $70 million (a)
·
Increased diatomite net production to an average of
3,570 BOE/D, up 34% from the first quarter of 2009
·
Closed on the acquisition of 6,900 net acres and 11
MMBOE of proved reserves, primarily in the Wolfberry trend in W. Texas for
approximately $132 million
·
Completed our first horizontal Haynesville well with
an initial potential of approximately 10.3 MMcf/D gross production and 30-day
average production of 9.0 MMcf/D
·
Issued 8 million shares of Class A Common Stock
for net proceeds of $224 million to fund the Wolfberry Acquisition and reduce
debt
Notable Items and Expectations for the Second Quarter and Full Year
2010.
·
Acquired a 90 acre lease from Chevron U.S.A. Inc.
increasing diatomite acreage by 20%
·
Closed on the acquisition of an additional 3,200 acres
and 2 MMBOE of proved reserves in the Wolfberry trend for $14 million
·
Expecting 2010 development capital expenditures
between $250 million and $290 million to be fully funded from operating cash
flow
·
Anticipating average production between 32,250 and
33,000 BOE/D, an 8% to 10% increase over 2009
(a) 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.
Overview of the First Quarter of 2010.
We had net income from
continuing operations of $17.7 million, or $0.34 per diluted share, and net
cash from operations was $63.5 million in the first quarter of 2010. Net income
from continuing operations includes a $0.9 million gain on purchase of oil and
natural gas properties related to the Wolfberry Acquisition offset by $1.3
million of acquisition-related expenses.
Also included in net income is a $0.9 million loss on derivatives as a
result of amortization of frozen fair values and non-cash changes in fair
values and $0.8 million of dry hole costs resulting from mechanical failure on
one well in the Piceance basin. We drilled 59 gross wells and capital
expenditures, excluding property acquisitions, totaled $48 million. We achieved average production of 29,391
BOE/D in the first quarter of 2010, up 1% and down 3% from an average of 29,149
BOE/D and 30,231 BOE/D in the fourth quarter of 2009 and the first quarter of
2009, respectively.
19
Table of Contents
Acquisitions.
During the first quarter of 2010, we acquired
certain properties primarily in the Wolfberry trend in W. Texas from a private
seller for total consideration of $
132 million, including an initial purchase price of
$126 million, and normal post-closing adjustments of $6 million. The properties included total proved reserves
of 11.2 MMBOE, of which 85% were crude oil and 23% were proved developed. We have identified over 130 drilling
locations on forty acre spacing in the Wolfberry trend targeting the Spraberry,
Dean, Wolfcamp and Strawn formations. We
plan to test twenty acre down spacing in late 2010, which would provide an
additional 150 drilling locations. We
operate approximately 70% of, and have an average 68.5% working interest (54.1%
net revenue interest) in, the properties acquired in the Wolfberry trend.
Revenues
.
Approximately
88% 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 6% 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. The remaining 6% of our revenues are primarily derived from
gas marketing sales which represent our excess capacity on the Rockies Express
pipeline which we used to market natural gas for our working interest partners.
The
following results from continuing operations are in millions (except per share
data) for the three months ended:
|
|
March 31,
2010
(1Q10)
|
|
March 31,
2009
(1Q09)
|
|
1Q10 to
1Q09
Change
|
|
December
31, 2009
(4Q09)
|
|
1Q10 to
4Q09
Change
|
|
Sales
of oil (1)
|
|
$
|
122
|
|
$
|
99
|
|
23%
|
|
$
|
109
|
|
12%
|
|
Sales
of gas
|
|
26
|
|
29
|
|
(10)%
|
|
24
|
|
8%
|
|
Total
sales of oil and gas
|
|
$
|
148
|
|
$
|
128
|
|
16%
|
|
$
|
133
|
|
11%
|
|
Sales
of electricity
|
|
10
|
|
10
|
|
|
|
10
|
|
|
|
Gas
marketing
|
|
8
|
|
8
|
|
|
|
5
|
|
60%
|
|
Realized
and unrealized gain on derivatives, net
|
|
2
|
|
37
|
|
(95)%
|
|
|
|
|
|
Total
revenues and other income
|
|
$
|
168
|
|
$
|
183
|
|
(8)%
|
|
$
|
148
|
|
14%
|
|
Net
income from continuing operations
|
|
$
|
18
|
|
$
|
42
|
|
(57)%
|
|
$
|
13
|
|
38%
|
|
Diluted
earnings per share from continuing operations
|
|
$
|
0.34
|
|
$
|
0.92
|
|
(63)%
|
|
$
|
0.28
|
|
21%
|
|
(1) Included in the fourth
quarter of 2009 are adjustments to correct the prior accounting for royalties
in the amount of $3 million, which resulted in decreasing our sales of oil and
gas and increasing our royalties payable.
Management concluded the impact was immaterial to the fourth quarter of
2009 and prior periods.
20
Table of Contents
Operating data
. The following table is for the three months ended:
|
|
March 31,
2010
|
|
%
|
|
March 31,
2009
|
|
%
|
|
December 31,
2009
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
17,752
|
|
61
|
|
16,436
|
|
50
|
|
17,280
|
|
60
|
|
Light
Oil Production (Bbl/D)
|
|
2,754
|
|
9
|
|
3,066
|
|
9
|
|
2,719
|
|
9
|
|
Total
Oil Production (Bbl/D)
|
|
20,506
|
|
70
|
|
19,502
|
|
59
|
|
19,999
|
|
69
|
|
Natural
Gas Production (Mcf/D)
|
|
53,309
|
|
30
|
|
82,979
|
|
41
|
|
54,899
|
|
31
|
|
Total
operations (BOE/D)
|
|
29,391
|
|
100
|
|
33,332
|
|
100
|
|
29,149
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ
Basin Production (BOE/D)
|
|
|
|
|
|
3,101
|
|
|
|
|
|
|
|
Production
- Continuing Operations (BOE/D)
|
|
29,391
|
|
|
|
30,231
|
|
|
|
29,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas BOE for continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
57.06
|
|
|
|
$
|
29.36
|
|
|
|
$
|
50.76
|
|
|
|
Average
sales price after hedging
|
|
55.99
|
|
|
|
47.11
|
|
|
|
48.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl, for continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
78.88
|
|
|
|
$
|
43.24
|
|
|
|
$
|
76.13
|
|
|
|
Price
sensitive royalties
|
|
(3.04
|
)
|
|
|
(1.02
|
)
|
|
|
(2.64
|
)
|
|
|
Quality
differential and other
|
|
(8.12
|
)
|
|
|
(9.53
|
)
|
|
|
(9.63
|
)
|
|
|
Crude
oil hedges reported with Sales of oil and gas
|
|
(1.72
|
)
|
(a)
|
|
23.79
|
|
(b)
|
|
(3.96
|
)
|
(b)
|
|
Correction
to royalties payable (c)
|
|
|
|
|
|
|
|
|
|
(1.78
|
)
|
|
|
Average
oil sales price after hedging
|
|
$
|
66.00
|
|
|
|
$
|
56.48
|
|
|
|
$
|
58.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price for continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
5.30
|
|
|
|
$
|
4.90
|
|
|
|
$
|
4.17
|
|
|
|
Conversion
to Mcf
|
|
0.27
|
|
|
|
0.25
|
|
|
|
0.21
|
|
|
|
Natural
gas hedges reported with Sales of oil and gas
|
|
0.07
|
|
(a)
|
|
1.14
|
|
(b)
|
|
0.40
|
|
(b)
|
|
Location,
quality differentials and other
|
|
(0.15
|
)
|
|
|
(1.27
|
)
|
|
|
(0.13
|
)
|
|
|
Average
gas sales price after hedging per Mcf
|
|
$
|
5.49
|
|
|
|
$
|
5.02
|
|
|
|
$
|
4.65
|
|
|
|
(a)
Includes
non-cash amortization of frozen December 31, 2009 fair values resulting from January 1, 2010
discontinuing of hedge accounting
(b)
Includes
cash settlements on derivatives for which we had elected hedge accounting
(c)
Included in the fourth quarter of
2009 is a correction to one of our royalties in the amount of $3 million, which
resulted in decreasing our sales of oil and gas and increasing our royalties
payable.
Sales of Oil and Gas:
Oil
and gas revenue increased 16% to $148 million in the first quarter of 2010
compared to $128 million in the first quarter of 2009. The increase is primarily due to an increase
in the average sales price after hedging to $55.99 per BOE in the first quarter
of 2010 from $47.11 per BOE in the first quarter of 2009. Oil and gas revenue increased 11% in the
first quarter of 2010 compared to the fourth quarter of 2009. The increase is primarily due to an increase
in the average sales price after hedging to $55.99 per BOE in the first quarter
of 2010 from $48.77 per BOE in the fourth quarter of 2009. Approximately 70% of our oil and gas sales
volumes in the first quarter of 2010 were crude oil, with 87% 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.
21
Table of Contents
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 first quarter of 2010, we reclassified $2.8 million
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 contracts are recorded at fair value each quarter with fair value
gains and losses recognized immediately in earnings as Realized and unrealized
gain 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 on derivatives, net. See Realized and unrealized gain on
derivatives, net below.
The
average sales price received for oil sales during the first quarter of 2010 was
$66.00 per BOE, an increase of 17% or $9.52 per BOE compared to the first
quarter of 2009. The range of NYMEX
light sweet crude prices for the first quarter of 2010, based upon settlements,
was from a low of $71.19 to a high of $83.76.
NYMEX light sweet crude prices for the first quarter of 2009, based upon
settlements, was a low of $33.98 and a high of $54.34. In California the differential on March 31,
2010 was $8.31 and ranged from a low of $6.82 to a high of $8.32 per barrel
during the first quarter of 2010. The California differential ranged from a low
of $5.20 to a high of $14.02 per barrel during the first quarter of 2009. 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 the our crude oil.
The
average sales price received for gas sales during the first quarter of 2010 was
$5.49 per Mcf, an increase of 9% or $0.47 per Mcf compared to the first quarter
of 2009. We sell our produced natural gas at various indices. Henry Hub (HH) natural gas averaged $5.30 in
the first quarter of 2010 and $4.90 in the first quarter of 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 $0.21 above HH for the first quarter of
2010. The Piceance basin natural gas was
sold in the first quarter of 2009 based upon a mid-continent index such as
PEPL, which averaged $1.51 below HH.
Correspondingly, most of the Uinta basin natural gas is sold based on a
Questar index which averaged $0.28 below HH for the first quarter of 2010 and
$1.72 below HH for the first quarter of 2009.
The E. Texas natural gas production was generally sold during the first
quarter of 2010 at the Florida Zone 1 index which was $0.01 below HH for the
first quarter of 2010. The E. Texas
natural gas production was sold during the first quarter of 2009 at the Texas
Eastern - East Texas index, which averaged $0.78 below HH for the first quarter
of 2009.
Sales
of Electricity:
Electricity revenues
remained relatively unchanged and operating costs increased in the first
quarter of 2010 compared to the fourth quarter of 2009 as a result of flat
electricity prices and 27% higher natural gas prices. Electricity revenues decreased and operating
costs increased in the first quarter of 2010 compared to the first quarter of
2009 due to 5% lower electricity prices and 8% higher natural gas prices.
We purchased
approximately 28 MMBtu/D and 27 MMBtu/D of natural gas as fuel for use in our
cogeneration facilities for the three months ended March 31, 2010 and December 31,
2009, respectively.
The following table is
for the three months ended:
|
|
March 31,
2010
|
|
March 31,
2009
|
|
December 31,
2009
|
|
Electricity
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
9.9
|
|
$
|
10.3
|
|
$
|
10.0
|
|
Operating
costs (in millions)
|
|
$
|
9.7
|
|
$
|
8.8
|
|
$
|
9.3
|
|
Electric
power produced - MWh/D
|
|
2,154
|
|
2,068
|
|
2,141
|
|
Electric
power sold - MWh/D
|
|
1,979
|
|
1,939
|
|
1,942
|
|
Average
sales price/MWh
|
|
$
|
56.17
|
|
$
|
58.85
|
|
$
|
56.17
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
5.39
|
|
$
|
4.01
|
|
$
|
4.57
|
|
22
Table of Contents
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 is $0.5 million and $0.3 million
in the three months ended March 31, 2010 and 2009, respectively. Firm transportation costs related to all of
our Rockies Express volumes is reflected in Operating costs - oil and gas
production and total $3.2 million and $2.9 million for the three months ended March 31,
2010 and 2009, respectively.
Realized and unrealized g
ain on derivatives, net
Realized and unrealized g
ain on derivatives, net is primarily
related to 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 on derivatives,
net in the condensed statements of income. Similarly, changes in the fair value
of the derivative instruments are recorded as unrealized gains or losses in the
Condensed Statements of Income. 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 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
all of our derivative contracts are recorded at fair value each quarter with
fair value gains and losses 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
on derivatives, net.
During
the three months ended March 31, 2010, we recorded a $1.6 million gain
under the caption Realized and unrealized gain on derivatives, net resulting from
a gain for the change in fair value of $3.3 million, net of a loss on cash
settlements of $1.7 million.
During the three months ended March 31, 2009,
we recorded a $37.2 million gain under the caption Realized and unrealized gain on derivatives, net. In conjunction with the sale of the DJ basin
assets, during the first quarter of 2009, we concluded that the forecasted
transaction in certain of our hedging relationships was not probable of
occurring. As such, we reclassified a
gain of $14.3 million from AOCL to the Condensed Statements of Income under the
caption Realized and unrealized gain
on derivatives, net.
We also recognized an unrealized net gain
of $22.9 million on the Condensed Statements of Income under the caption Realized and
unrealized gain on derivatives, net for the three months ended March 31,
2009, respectively, as a result of ineffectiveness related to sales prices that
were not perfectly correlated with our hedges.
We recorded an unrealized net
loss of $0.5 million on the Condensed Statements of Income under the caption
Loss from discontinued operations, net of taxes during the first quarter of 2009 related to natural gas derivatives
entered into on behalf of the purchaser of our DJ assets for which we did not
elect hedge accounting.
23
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)
|
|
|
|
March 31,
2010
|
|
March 31,
2009
|
|
December 31,
2009
|
|
March 31,
2010
|
|
March 31,
2009
|
|
December 31,
2009
|
|
Operating
costs oil and gas production
|
|
$
|
17.78
|
|
$
|
13.74
|
|
$
|
16.89
|
|
$
|
47,036
|
|
$
|
37,384
|
|
$
|
45,295
|
|
Production
taxes
|
|
1.97
|
|
2.08
|
|
1.39
|
|
5,204
|
|
5,652
|
|
3,733
|
|
DD&A
oil and gas production
|
|
13.57
|
|
13.38
|
|
13.29
|
|
35,907
|
|
36,398
|
|
35,648
|
|
G&A
|
|
5.23
|
|
4.89
|
|
4.51
|
|
13,835
|
|
13,294
|
|
12,094
|
|
Interest
expense
|
|
6.60
|
|
3.69
|
|
5.49
|
|
17,447
|
|
10,050
|
|
14,722
|
|
Total
|
|
$
|
45.15
|
|
$
|
37.78
|
|
$
|
41.57
|
|
$
|
119,429
|
|
$
|
102,778
|
|
$
|
111,492
|
|
·
Operating costs in the first quarter of
2010 were $47.0 million or $17.78 per BOE, compared to $37.4 million or $13.74
per BOE in the first quarter of 2009 and $45.3 million or $16.89 per BOE in the
fourth quarter of 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:
|
|
March 31,
2010
(1Q10)
|
|
March 31,
2009
(1Q09)
|
|
1Q10
to 1Q09
Change
|
|
December 31,
2009
(4Q09)
|
|
1Q10 to
4Q09
Change
|
|
Average
volume of steam injected (Bbl/D)
|
|
118,733
|
|
103,342
|
|
15
|
%
|
115,864
|
|
2
|
%
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
5.39
|
|
$
|
4.01
|
|
34
|
%
|
$
|
4.57
|
|
18
|
%
|
Approximate
net fuel gas volume consumed in steam generation (MMBtu/D)
|
|
36,699
|
|
26,427
|
|
39
|
%
|
33,830
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
·
The increase in operating costs compared
to the first quarter of 2009 is due to a $9.1 million increase in steam
costs. The increase in steam costs is
due to a 34% increase in fuel gas costs as a result of increased natural gas
prices and a 39% increase in fuel gas volume consumed in steam generation. The increase in operating costs compared to
the fourth quarter of 2009 is due to a $3.1 million increase in steam
costs. The increase in steam costs is
due to an 18% increase in fuel gas costs as a result of increased natural gas
prices and an 8% increase in fuel gas volume consumed in steam generation. Operating costs in the fourth quarter of 2009
included $1.2 million of operating costs associated with 50,000 barrels of oil
inventory sold in October 2009.
·
Production taxes in the first quarter of
2010 were $5.2 million or $1.97 per BOE, compared to $5.7 million or $2.08 per
BOE in the first quarter of 2009 and $3.7 million or $1.39 per BOE in the
fourth quarter of 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 first quarter of 2009 is due to a
decrease in the assessed ad valorem tax values attributed to our California
properties. The increase in production
taxes compared to the fourth quarter of 2009 is primarily related to increased
oil and natural gas prices.
·
Depreciation, depletion and amortization
(DD&A) in the first quarter of 2010 was $35.9 million or $13.57 per BOE,
compared to $36.4 million or $13.38 per BOE in the first quarter of 2009 and
$35.6 million or $13.29 per BOE in the fourth quarter of 2009. On a per barrel basis DD&A remained
consistent in the first quarter of 2010 compared to both the first quarter of
2009 and the fourth quarter of 2009.
·
General and administrative expense
(G&A) in the first quarter of 2010 was $13.8 million or $5.23 per BOE,
compared to $13.3 million or $4.89 in the first quarter of 2009 and $12.1
million or $4.51 per BOE in the fourth quarter of 2009. G&A in the first quarter of 2010 is consistent
with the prior quarters with the exception of additional headcount due to
staffing of the Permian asset team.
Approximately 65% of our G&A is related to compensation.
24
Table of Contents
·
Interest expense in the first quarter of
2010 was $17.4 million or $6.60 per BOE, compared to $10.1 million or $3.69 per
BOE in the first quarter of 2009 and $14.7 million or $5.49 per BOE in the
fourth quarter 2009. The increase in interest
expense compared to the first quarter of 2009 was due to the issuance of our
10.25% senior notes due 2014, subsequent to the first quarter of 2009. The amortization of the net discount and
deferred loan costs attributable to the senior notes is also included in
interest expense. Interest expense
increased compared to the fourth quarter of 2009 due primarily to a decrease in
interest costs capitalized in the first quarter of 2010 as a result of our
development activities. Interest cost is capitalized as a component of property
cost for significant exploration and development activity projects. Additionally, in the first quarter of 2010,
we reclassified $2.7 million, or $1.02 per BOE of non-cash derivative losses
relating to de-designated interest rate hedges from AOCL into earnings.
Interest expense in the first quarter of 2010 was $5.58 per BOE, excluding the
non-cash derivative losses.
2010 Guidance:
For 2010 the Company is
issuing the following guidance:
|
|
Anticipated Range per BOE in 2010 ($/BOE)
|
|
|
|
$60 WTI/$4 HH
|
|
$60 WTI/$5 HH
|
|
$75 WTI/$6 HH
|
|
Operating
costs-oil and gas production
|
|
$
|
17.00 18.00
|
|
$
|
18.00 19.00
|
|
$
|
19.00 20.00
|
|
Production
taxes
|
|
|
1.75 2.25
|
|
|
1.75 2.25
|
|
|
2.00 2.50
|
|
DD&A
oil and gas production
|
|
|
|
|
|
12.00 14.00
|
|
|
|
|
G&A
|
|
|
|
|
|
4.00 4.50
|
|
|
|
|
Interest
expense
|
|
|
|
|
|
5.00 - 6.50
|
|
|
|
|
Total
|
|
|
|
|
$
|
40.75 46.25
|
|
|
|
|
Transaction
costs on acquisitions, net of gain:
In the first quarter of 2010 transaction
costs on acquisitions, net of gain was $0.7 million. We recorded $2.1 million of acquisition
related expenses for our acquisition of certain properties, primarily in the Wolfberry trend
in W. Texas, from a private seller in the first quarter of 2010. This acquisition resulted in a $1.4 million
gain on purchase of oil and natural gas properties. The gain resulted from the changes in
oil and natural gas prices used to value the reserves.
Dry
hole, abandonment, impairment and exploration:
In the
first quarter of 2010 we incurred dry hole, abandonment, impairment and
exploration expense of $1.4 million, 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.
In the first quarter of 2009 we had dry hole, abandonment, impairment
and exploration charges of $0.1 million.
In the fourth quarter of 2009 we had dry hole, abandonment, impairment
and exploration charges of $5.2 million primarily due to a $4.2 million
impairment charge related to the write-down of a rig to its fair market value.
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 for the three months ended March 31,
2009.
Income
Tax Expense:
The
effective tax rate for the first quarters of March 31, 2010 and 2009 was
36.9% and 33.9%, respectively. In
comparison with prior quarters, the increase in rate for the first quarter of
2010 is primarily due to one-time reductions in deferred state taxes in
previous quarters. Reductions in the
rate during prior quarters was the result of acquisitions in more tax favorable
jurisdictions reducing future state tax obligations in addition to 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 9 to the Condensed Financial
Statements.
25
Table of Contents
Drilling
Activity.
The
following table sets forth certain information regarding drilling activities
(including operated and non-operated wells):
|
|
Three months ended
March 31, 2010
|
|
Asset Team
|
|
Gross Wells
|
|
Net Wells
|
|
S.
Midway
|
|
27
|
|
27
|
|
N.
Midway
|
|
14
|
|
14
|
|
Permian
|
|
1
|
|
1
|
|
Uinta
|
|
12
|
|
12
|
|
E.
Texas
|
|
2
|
|
2
|
|
Piceance
|
|
3
|
|
2
|
|
Totals
|
|
59
|
|
58
|
|
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 Formax and Ethel D, as well as our Poso Creek property. In the first quarter of 2010 we drilled 27
wells, almost all of which were focused on the redevelopment of Ethel D. All of these wells are currently on
production and are performing in line with expectations. Average daily production in the first quarter
of 2010 from all S. Midway assets was approximately 11,690 BOE/D, a 4% increase
from the fourth quarter of 2009.
N. Midway
Our N. Midway asset team includes
our diatomite, Placerita and McKittrick assets and several N. Midway-Sunset
leases. In the first quarter of 2010 we
drilled 2 diatomite wells and 12 non-diatomite wells. We are currently waiting for permits to
cyclically steam new diatomite wells and our diatomite development plan has
shifted from the second quarter to the third quarter of 2010. We expect to run
a two rig drilling program in the second half of 2010. Production in the first quarter of 2010 was
3,568 Bbl/D. In the first quarter of
2010, we initiated injection on a four pattern steam flood pilot on our
recently acquired McKittrick property, which we will be monitoring over the
course of the year. Average daily
production in the first quarter of 2010 from all N. Midway assets was
approximately 6,059 BOE/D.
Permian
Our Permian asset team is executing a one rig drilling program in 2010
and we plan to increase production over the course of the year. Taking
into account both of our recent Permian acquisitions, we now have identified over 170 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. We operate approximately 70% of our acquired
properties, and have an average 68.5% working interest (54.1% net revenue
interest).
Uinta
In the first quarter of 2010,
production from our Uinta basin assets averaged 4,261 BOE/D. We drilled 12 wells targeting higher oil
potential areas of Brundage Canyon. We
are currently operating two drilling rigs and expect to begin drilling in both
our Lake Canyon and Ashley Forest acreage in the second quarter of 2010 once
winter restrictions have passed. The
Ashley Forest Development EIS continues to progress with the draft EIS now
released for public comment. Approval of
the final EIS is anticipated later this year.
The Environmental Protection Agency approvals were received in the first
quarter of 2010 for three additional injectors in the initial waterflood pilot
at Brundage Canyon and we are currently finalizing our permit submittal for a
second waterflood pilot that is expected to be initiated later this year.
E. Texas
In the first quarter of 2010,
production from our E. Texas assets averaged 20.6 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 first quarter
of 2010, we successfully drilled our first two horizontal wells achieving
lateral lengths of 4,257 feet and 4,590 feet, respectively, and have recently
reached total depth on our third horizontal well. Late in the first quarter of 2010, we
successfully completed our first Haynesville well with a 13-stage fracture
stimulation treatment. That well yielded
an initial potential of 10.3 MMcf/D gross production, with the first 30 days of
production averaging 9.0 MMcf/D, which surpassed our expectations.
26
Table of
Contents
Piceance
In the first quarter of 2010,
production from the Piceance basin averaged 21.9 MMcfe/D. We resumed drilling with a one rig program,
focusing on remaining lease earning obligations. We drilled three wells in the first quarter
and continued to test improved completions techniques with two new well
completions and 10 uphole recompletions in the first quarter. Results from these completions continue to meet
expectations.
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 private and public 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 March 31, 2010 we have
approximately 75% and 40% of our expected 2010 and 2011 oil production hedged
with derivative instruments in the form of swaps and collars and we have
approximately 30% and 10% of our 2010 and 2011 expected natural gas production
hedged with derivative instruments in the form of swaps and collars. This level
of derivatives will 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 $664 million of
available borrowing capacity. At March 31,
2010, we had $270 million in borrowings and $4 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. See Note 8 to the Condensed Financial
Statements.
The public and private capital markets
have served as our primary source of financing to fund large acquisitions and
other exceptional 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 Wolfberry 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 8 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 $18.4 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 $55.4 million in the first quarter of 2010 compared to
the first quarter of 2009 is primarily due to higher realized commodity sales
prices in the first quarter of 2010 compared to the first quarter 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. The increase in net cash used in investing
activities of $144.3 million in the first quarter of 2010 compared to the first
quarter of 2009 is due to the Wolfberry Acquisition in the first quarter of
2010.
27
Table of
Contents
Financing Activities -
Net cash provided by financing activities
in the first quarter of 2010 included proceeds from the issuance of stock of
$224.3 million, the net repayment of the senior secured revolving credit
facility of $102 million and dividends paid of $4.0 million. Net cash provided by financing activities in
the first quarter of 2009 included the net borrowing of the senior secured
revolving credit facility and the money market line of credit of $42.3 million,
debt issuance costs of $4.5 million and dividends paid of $3.4 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 have a capital program of approximately $285 million, and we
expect to fully fund this program from operating cash flow. Our capital expenditures for the first
quarter of 2010 totaled $48.0 million for development and capitalized interest
of $6.0 million compared to total capital expenditures for the first quarter of
2009 of $50.2 million for development and capitalized interest of $5.3 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.
28
Table of Contents
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 3
to the Condensed Financial Statements.
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.
29
Table of
Contents
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 March 31, 2010
|
|
Net
cash provided by operating activities
|
|
$
|
63.5
|
|
Add
back: Net increase in current assets
|
|
14.2
|
|
Add
back: Net increase in current liabilities including book overdraft
|
|
(7.3
|
)
|
Discretionary
cash flow
|
|
$
|
70.4
|
|
30
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. The
collar strike prices allow us to protect our cash flow if oil prices decline
below our floor prices which range from $55.00 to $100.00 per barrel while
still participating in any oil price increase up to the ceiling prices which
range from $68.00 to $161.10 per barrel on the volumes indicated below. In total, we have approximately 75% and 40% of
our expected 2010 and 2011 oil production, respectively, hedged in the form of
swaps and collars. Our natural gas
collars have a floor from $6.00 to $6.50 per MMBtu and ceilings ranging from
$7.25 to $8.90 per MMBtu. In total, we
have approximately 30% and 10% 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 $13 million. A one dollar change in natural gas prices
impacts annual operating cash flow by approximately $3 million.
31
Table of
Contents
The following table summarizes our commodity derivative position as of March 31,
2010:
Term
|
|
Average
Barrels
Per Day
|
|
Average
Prices
|
|
Crude Oil Sales (NYMEX WTI) 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) 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
|
|
Term
|
|
Average
MMBtu
Per Day
|
|
Average
Price
|
|
Natural Gas Sales (NYMEX HH) Collars
|
Full
year 2010
|
|
2,000
|
|
$6.00/$8.60
|
|
Full
year 2010
|
|
3,000
|
|
$6.00/$8.65
|
|
Full
year 2010
|
|
1,000
|
|
$6.50/$8.75
|
|
Full
year 2010
|
|
1,000
|
|
$6.50/$8.85
|
|
Full
year 2010
|
|
2,000
|
|
$6.50/$8.90
|
|
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
|
|
$0.345
|
|
Full
year 2011
|
|
2,500
|
|
$0.325
|
|
Full
year 2012
|
|
2,500
|
|
$0.320
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH TO NGPL-Tex OK)
Basis Swaps
|
Full
year 2010
|
|
2,500
|
|
$0.415
|
|
Full
year 2011
|
|
2,500
|
|
$0.460
|
|
Full
year 2012
|
|
2,500
|
|
$0.440
|
|
|
|
|
|
|
|
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
|
|
$6.89
|
|
Full
year 2012
|
|
5,000
|
|
$7.16
|
|
32
Table of
Contents
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 March 31,
2010 (WTI $85.97; HH $5.12) 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:
|
|
March 31, 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)
|
|
$
|
85.97
|
|
$
|
51.58
|
|
$
|
68.77
|
|
$
|
103.16
|
|
$
|
120.35
|
|
Average
HH Futures Price (2010 2012)
|
|
5.12
|
|
3.07
|
|
4.09
|
|
6.14
|
|
7.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$
|
(85.2
|
)
|
$
|
194.7
|
|
$
|
44.2
|
|
$
|
(219.7
|
)
|
$
|
(335.2
|
)
|
Natural
Gas gain/(loss) (in millions)
|
|
10.3
|
|
39.5
|
|
27.1
|
|
5.9
|
|
(0.7
|
)
|
Total
|
|
$
|
(74.9
|
)
|
$
|
234.2
|
|
$
|
71.3
|
|
$
|
(213.8
|
)
|
$
|
(335.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pre-tax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
2010
(WTI $84.70; HH $4.26)
|
|
(23.4
|
)
|
132.7
|
|
50.7
|
|
(93.0
|
)
|
(145.6
|
)
|
2011
(WTI $86.08; HH $5.22)
|
|
(51.3
|
)
|
49.2
|
|
5.8
|
|
(112.7
|
)
|
(173.3
|
)
|
2012
(WTI $86.80; HH $5.65)
|
|
(0.2
|
)
|
52.3
|
|
14.8
|
|
(8.1
|
)
|
(17.0
|
)
|
Total
|
|
$
|
(74.9
|
)
|
$
|
234.2
|
|
$
|
71.3
|
|
$
|
(213.8
|
)
|
$
|
(335.9
|
)
|
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 March 31, 2010, total long-term debt
outstanding was $907 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 March 31, 2010 credit facility
borrowings, a 1% change in interest rates, including our interest rate
derivatives, would have an annualized $0.1 million after tax impact on our
Condensed Financial Statements.
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 March 31, 2010, as a result of our interest rate derivative
contracts, senior subordinated notes and senior notes, we have a total of $900
million of fixed rate positions averaging 7.8%.
33
Table of
Contents
Berry
Petroleum Company
Controls
and Procedures
Item
4. Controls and Procedures
As of March 31, 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 March 31, 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 March 31, 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 Form 10-K dated February 25,
2010, filed with the Securities and Exchange Commission, under the heading Risk
Factors and all material changes are updated in Part II, Item 1A within
this Form 10-Q.
34
Table of
Contents
Berry
Petroleum Company
Part II
Other Information
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
None.
Item
1A. Risk Factors
None.
Item
2. Unregistered Sales of Equity
Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Removed and Reserved
Item 5. Other Information
None.
35
Table of
Contents
Item 6. Exhibits
Exhibit No.
|
|
Description of Exhibit
|
|
|
|
10.1*
|
|
Award Grant under the
Performance Share Award Program to Robert H. Heinemann
(filed as Exhibit 10.1 to the
Registrants Current Report on Form 8-K on March 18, 2010, File
No. 1-9735)
|
10.2*
|
|
Award Grant under the
Performance Share Award Program to David D. Wolf
(filed as Exhibit 10.2 to the Registrants
Current Report on Form 8-K on March 18, 2010, File No. 1-9735)
|
10.3*
|
|
Award Grant under the
Performance Share Award Program to Michael Duginski
(filed as Exhibit 10.3 to the
Registrants Current Report on Form 8-K on March 18, 2010, File
No. 1-9735)
|
10.4*
|
|
Form of Award Grant
under the Performance Share Award Program for select officers of the Company
(filed as Exhibit 10.4 to the
Registrants Current Report on Form 8-K on March 18, 2010, File
No. 1-9735)
|
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
|
* Incorporated herein by reference
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: April 28, 2010
|
|
36
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