UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
x Quarterly Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
quarterly period ended June 30, 2008
oTransition Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
transition period from __to
___
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
|
DELAWARE
|
|
77-0079387
|
|
|
(State
of incorporation or organization)
|
|
(I.R.S.
Employer Identification Number)
|
|
1999
Broadway, Suite 3700
Denver,
Colorado 80202
(Address
of principal executive offices, including zip code)
Registrant's telephone number,
including area
code: (303) 999-4400
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. YES x NO o
Indicate
by check mark whether the registrant 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 filerx Accelerated
filero Non-accelerated
filero Smaller
reporting companyo
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES o NO x
As of
July 14, 2008, the registrant had 42,716,259 shares of Class A Common Stock
($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class
B Stock ($.01 par value) outstanding on July 14, 2008 all of which is held by an
affiliate of the registrant.
BERRY PETROLEUM
COMPANY
SECOND
QUARTER 2008 FORM 10-Q
TABLE
OF CONTENTS
PART I.
FINANCIAL
INFORMATION
|
|
Page
|
|
|
|
|
Item
1. Financial Statements
|
|
|
|
|
|
Unaudited
Condensed Balance Sheets at June 30, 2008 and December 31,
2007
|
3
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended June 30,
2008 and 2007
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Six Month Periods Ended June 30,
2008 and 2007
|
5
|
|
|
|
|
Unaudited
Condensed Statements of Cash Flows for the Six Month Periods Ended June
30, 2008 and 2007
|
6
|
|
|
|
|
Notes
to Unaudited Condensed Financial Statements
|
7
|
|
|
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
12
|
|
|
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
22
|
|
|
|
|
Item
4. Controls and Procedures
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
PART
II.
OTHER
INFORMATION
|
|
|
|
|
|
|
Item
1. Legal Proceedings
|
25
|
|
|
|
|
Item
1A. Risk Factors
|
25
|
|
|
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
25
|
|
|
|
|
Item
3. Defaults Upon Senior Securities
|
25
|
|
|
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
25
|
|
|
|
|
Item
5. Other Information
|
25
|
|
|
|
|
Item
6. Exhibits
|
26
|
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
|
June
30, 2008
|
|
|
December
31, 2007
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
5,583
|
|
$
|
316
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
143,423
|
|
|
117,038
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
-
|
|
|
2,109
|
|
|
|
|
|
|
|
|
|
Prepaid expenses and other
|
|
|
|
|
|
|
|
Total
current assets
|
|
|
270,871
|
|
|
161,019
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,405,560
|
|
|
1,275,091
|
|
Other
assets
|
|
|
73,885
|
|
|
15,996
|
|
|
|
$
|
1,750,316
|
|
$
|
1,452,106
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
134,872
|
|
$
|
90,354
|
|
Revenue and royalties payable
|
|
|
|
|
|
|
|
Accrued
liabilities
|
|
|
21,443
|
|
|
21,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
301,776
|
|
|
95,290
|
|
Total current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
87,858
|
|
|
128,824
|
|
|
|
|
|
|
|
|
|
Abandonment
obligation
|
|
|
40,051
|
|
|
36,426
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
Fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
966,327
|
|
|
720,763
|
|
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
|
-
|
|
Capital stock, $.01 par value:
|
|
|
|
|
|
|
|
Class
A Common Stock, 100,000,000 shares authorized; 42,716,259 shares issued
and outstanding (42,583,002 in 2007)
|
|
|
426
|
|
|
425
|
|
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares
issued and outstanding (liquidation preference of $899) (1,797,784 in
2007)
|
|
|
|
|
|
|
|
Capital
in excess of par value
|
|
|
75,075
|
|
|
66,590
|
|
Accumulated
other comprehensive loss
|
|
|
(386,637
|
)
|
|
(120,704
|
)
|
|
|
|
|
|
|
|
|
Total
shareholders' equity
|
|
|
287,995
|
|
|
459,974
|
|
|
|
$
|
1,750,316
|
|
$
|
1,452,106
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Three
Month Periods Ended June 30, 2008 and 2007
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
|
Three
months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215,406
|
|
|
179,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
55,185
|
|
|
35,725
|
|
|
Operating costs - electricity generation
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
|
|
|
7,481
|
|
|
4,139
|
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
29,073
|
|
|
23,397
|
|
|
Depreciation, depletion & amortization - electricity
generation
|
|
|
|
|
|
|
|
|
|
|
|
Gas
marketing
|
|
|
|
|
|
11,071
|
|
|
-
|
|
|
General
and administrative
|
|
|
|
|
|
11,160
|
|
|
9,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
|
|
|
|
59
|
|
|
-
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
3,464
|
|
|
3,519
|
|
|
|
|
|
|
|
|
137,611
|
|
|
93,451
|
|
|
Income
before income taxes
|
|
|
|
|
|
77,795
|
|
|
85,778
|
|
|
Provision
for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
1,003
|
|
|
751
|
|
|
Director deferred compensation
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Condensed Statements of Comprehensive (Loss)
Income
|
|
|
Three
Month Periods Ended June 30, 2008 and 2007
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gains (losses) on derivatives, net of income tax benefits of ($162,792)
and ($4,395), respectively
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of realized gains (losses) on derivatives included in net income, net of
income taxes (benefit) of $21,898 and ($697), respectively
|
|
|
|
|
|
37,268
|
|
|
(1,045
|
)
|
|
Comprehensive
(loss) income
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Six
Month Periods Ended June 30, 2008 and 2007
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
|
Six
months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
400,802
|
|
|
296,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
96,814
|
|
|
69,335
|
|
|
Operating costs - electricity generation
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
|
|
|
13,448
|
|
|
7,954
|
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
56,148
|
|
|
42,122
|
|
|
Depreciation, depletion & amortization - electricity
generation
|
|
|
|
|
|
|
|
|
|
|
|
Gas
marketing
|
|
|
|
|
|
14,053
|
|
|
-
|
|
|
General
and administrative
|
|
|
|
|
|
22,543
|
|
|
19,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
|
|
|
|
767
|
|
|
-
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
7,590
|
|
|
4,168
|
|
|
|
|
|
|
|
|
252,311
|
|
|
179,781
|
|
|
Income
before income taxes
|
|
|
|
|
|
148,491
|
|
|
116,927
|
|
|
Provision
for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
924
|
|
|
668
|
|
|
Director deferred compensation
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Condensed Statements of Comprehensive (Loss)
Income
|
|
|
Six
Month Periods Ended June 30, 2008 and 2007
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gains (losses) on derivatives, net of income tax benefits of ($203,141)
and ($12,457), respectively
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of realized gains (losses) on derivatives included in net income, net of
income taxes (benefit) of $33,596 and ($882), respectively
|
|
|
|
|
|
54,815
|
|
|
(1,323
|
)
|
|
Comprehensive
(loss) income
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Six
Month Periods Ended June 30, 2008 and 2007
(In
Thousands)
|
|
|
|
|
|
Six
months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
Dry
hole and impairment
|
|
|
|
|
|
5,332
|
|
|
3,547
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
|
|
|
39,030
|
|
|
39,695
|
|
Unrealized
loss on ineffective hedges
|
|
|
|
|
|
751
|
|
|
-
|
|
Gain
on sale of oil and gas properties
|
|
|
|
|
|
(414
|
)
|
|
(50,398
|
)
|
Other,
net
|
|
|
|
|
|
689
|
|
|
415
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for abandonment
|
|
|
|
|
|
|
|
|
|
|
Increase in current assets other than cash and cash
equivalents
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in current liabilities other than book overdraft, line of
credit and fair value of derivatives
|
|
|
|
|
|
12,952
|
|
|
(14,635
|
)
|
Net
cash provided by operating activities
|
|
|
|
|
|
193,814
|
|
|
87,984
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Exploration and development of oil and gas
properties
|
|
|
|
|
|
|
|
|
|
|
Property
acquisitions
|
|
|
|
|
|
(380
|
)
|
|
(56,106
|
)
|
Additions to vehicles, drilling rigs and other fixed
assets
|
|
|
|
|
|
|
|
|
|
|
Deposit on potential acquisition
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuances on line of credit
|
|
|
|
|
|
187,100
|
|
|
203,800
|
|
Payments
on line of credit
|
|
|
|
|
|
(201,400
|
)
|
|
(210,300
|
)
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
286,300
|
|
|
179,300
|
|
Payments on long-term debt
|
|
|
|
|
|
|
|
|
|
|
Dividends
paid
|
|
|
|
|
|
(6,705
|
)
|
|
(6,678
|
)
|
Proceeds from stock option exercises
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefit and other
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
316
|
|
|
416
|
|
Cash
and cash equivalents at end of period
|
|
|
|
|
$
|
5,583
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
All
adjustments which are, in the opinion of management, necessary for a fair
statement of Berry Petroleum Company’s (the “Company”) financial position at
June 30, 2008 and December 31, 2007 and results of operations and
comprehensive (loss) income and cash flows for the three month and six month
periods ended June 30, 2008 and 2007 have been included. All such adjustments,
except as described below, are of a normal recurring nature. The results of
operations and cash flows are not necessarily indicative of the results for a
full year.
The
accompanying unaudited condensed financial statements have been prepared on a
basis consistent with the accounting principles and policies reflected in the
December 31, 2007 financial statements. The December 31, 2007 Form 10-K/A
should be read in conjunction herewith. The year-end condensed Balance Sheet was
derived from audited financial statements, but does not include all disclosures
required by accounting principles generally accepted in the United States of
America.
Our cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at June 30, 2008 and
December 31, 2007 is $20.8 million and $7.8 million, respectively, representing
outstanding checks in excess of the bank balance (book overdraft).
Certain
reclassifications have been made to prior period financial statements to conform
them to the current year presentation. Specifically, the change in book
overdraft line in the Statements of Cash Flows is classified as an operating
activity to reflect the use of these funds in operations, rather than their
prior year classification as a financing activity.
In March
2008, we determined there was an error in computing royalties payable in prior
years, accumulating to $10.5 million as of December 31, 2007. We concluded the
error was not material to any individual prior interim or annual period (or to
the projected earnings for 2008) and, therefore, the error was corrected during
the first quarter of 2008, with the effect of increasing our sales of oil and
gas and accounts receivable by $10.5 million and $2.4 million, respectively, and
reducing our royalties payable by $8.1 million.
In
December 2007, we entered into a second long-term (ten year) firm transportation
contract for our Colorado natural gas production. This contract is for 25,000
MMBtu/D on the Rockies Express (REX) pipeline for gas production in the Piceance
basin. We have a total of 35,000 MMBtu/D contracted on the REX pipeline. We
pay a demand charge for this capacity and our own production did not fill that
capacity. To maximize the utilization of our firm transportation, we bought our
partners’ share of the gas produced in the Piceance basin at the market rate for
that area and used our excess transportation to move this gas to the sales
point. The net of our gas marketing revenue and our gas marketing expense
in the Statements of Income is $.7 million for the six month period ended June
30, 2008.
In
addition, Berry has signed a binding precedent agreement with El Paso
Corporation for an average of 35,000 MMBtu/d of firm transportation on the
proposed Ruby Pipeline from Opal, WY to Malin, OR. While it is not
certain that this new line will be constructed, the expectation is that the
project will proceed and be in service by 2011. As part of this
agreement, we also secured firm transportation from the Piceance basin to
Opal.
In the
first six months of 2008, we recorded a total of $7.6 million in dry hole,
abandonment, impairment and exploration expense. Charges of $2.7
million and $2.6 million were recorded during the first and second quarters of
2008, respectively, for technical difficulties that were encountered on four
wells in the Piceance basin before reaching total depth. These
holes were abandoned in favor of drilling to the same bottom hole location by
drilling new wells. In addition, $2.3 million of exploration expense
was recorded for exploration activities which were primarily 3-D seismic
activity in the DJ basin.
The price sensitive royalty that burdens our Formax property in the South Midway
Sunset field has changed. We previously paid a royalty equal to 75%
of the amount of the heavy oil posted above a price of $16.11. This
price escalates at 2% annually. Effective January 1, 2008, the
royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam
injection level, which we expect to meet, that reduces over
time. Current net production from this property is approximately
2,300 Bbl/D.
During
the second quarter of 2008, Berry signed a Purchase and Sale Agreement for the
acquisition of certain interests in natural gas producing properties on 4,500
net acres in Limestone and Harrison Counties of East Texas for an initial
purchase price of $622 million, subject to normal closing
adjustments. Berry paid $59 million to the seller upon signing the
agreement as a deposit on the purchase price which is included with Other Assets
in the Balance Sheet as of June 30, 2008. See the discussion of the
acquisition closing in Footnote 9 of these financial statements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
Proceeds
from the first quarter 2008 sale of our Prairie Star assets were $1.8 million
and are reflected in the Statements of Cash Flows. The gain from that
sale is $.4 million and is reflected in the Statements of Income for the six
month period ended June 30, 2008.
2.
|
Recent Accounting
Developments
|
In
December 2007, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standard (SFAS) No. 160, Noncontrolling Interests in
Consolidated Financial Statements. SFAS 160 was issued to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary (formerly called minority interests) and for the deconsolidation of a
subsidiary. We do not expect the adoption of SFAS 160 to have a material effect
on our financial statements and related disclosures. The effective date of this
Statement is the same as that of the related Statement 141(R).
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which
expands the information that a reporting entity provides in its financial
reports about a business combination and its effects. This Statement establishes
principles and requirements for how the acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree, recognizes and measures the
goodwill acquired in the business combination or a gain from a bargain purchase,
and determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination. This Statement applies prospectively to business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. An entity may not
apply the principle before that date. We may experience a financial statement
impact depending on the nature and extent of any new business combinations
entered into after the effective date of SFAS No. 141(R).
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Expanded disclosures are required to provide information
about (a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
application encouraged. This Statement will require us to provide the additional
disclosures described above.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles (GAAP) in
the United States of America (the GAAP hierarchy). This Statement is
effective 60 days following the SEC’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles. We
do not expect the adoption of SFAS 162 to have a material effect on our
financial statements or related disclosures.
3.
|
Fair
Value Measurement
|
In
September 2006, SFAS No. 157, Fair Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
We adopted this Statement as of January 1, 2008.
Determination
of fair value
We have
established and documented a process for determining fair values. Fair value is
based upon quoted market prices, where available. We have various controls in
place to ensure that valuations are appropriate. These controls
include: identification of the inputs to the fair value methodology through
review of counterparty statements and other supporting documentation,
determination of the validity of the source of the inputs, corroboration of the
original source of inputs through access to multiple quotes, if available, or
other information and monitoring changes in valuation methods and assumptions.
The methods described above may produce a fair value calculation that may not be
indicative of future fair values. Furthermore, while we believe these valuation
methods are appropriate and consistent with that used by other market
participants, the use of different methodologies, or assumptions, to determine
the fair value of certain financial instruments could result in a different
estimate of fair value.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
3.
|
Fair
Value Measurement (Cont’d)
|
Valuation
hierarchy
SFAS 157
establishes a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy is based upon the transparency of inputs
to the valuation of an asset or liability as of the measurement date. The three
levels are defined as follows.
• Level
1 - inputs to the valuation methodology that are quoted prices (unadjusted) for
identical assets or liabilities in active markets.
• Level
2 - inputs to the valuation methodology that include quoted prices for similar
assets and liabilities in active markets, and inputs that are observable for the
asset or liability, either directly or indirectly, for substantially the full
term of the financial instrument.
• Level
3 - inputs to the valuation methodology that are unobservable and significant to
the fair value measurement.
A
financial instrument's categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement.
Our oil
swaps, natural gas swaps and interest rate swaps are valued using the
counterparties’ mark-to-market statements which are validated by our internally
developed models and are classified within Level 2 of the valuation hierarchy.
The observable inputs include underlying commodity and interest rate levels and
quoted prices of these instruments on actively traded
markets. Derivatives that are valued based upon models with
significant unobservable market inputs (primarily volatility), and
that are normally traded less actively are classified within Level 3 of the
valuation hierarchy. Level 3 derivatives include oil collars, natural gas
collars and natural gas basis swaps.
Assets
and liabilities measured at fair value on a recurring basis
June
30, 2008 (in millions)
|
Total
carrying value on the condensed Balance Sheet
|
Level
2
|
Level
3
|
|
|
|
|
Commodity
derivatives
|
$619.5
|
$49.9
|
$569.6
|
Interest
rate swaps
|
4.8
|
4.8
|
-
|
Total
liabilities at fair value
|
$624.3
|
$54.7
|
$569.6
|
Changes
in Level 3 fair value measurements
The table below includes a rollforward
of the Balance Sheet amounts (including the change in fair value) for financial
instruments classified by us within Level 3 of the valuation hierarchy. When a
determination is made to classify a financial instrument within Level 3 of the
valuation hierarchy, the determination is based upon the significance of the
unobservable factors to the overall fair value measurement. Level 3 financial
instruments typically include, in addition to the unobservable or Level 3
components, observable components (that is, components that are actively quoted
and can be validated to external sources).
(in
millions)
|
Three
months ended June 30, 2008
|
|
Six
months ended June 30, 2008
|
|
|
|
|
Fair
value, beginning of period
|
$243.9
|
|
$
194.3
|
Total
realized and unrealized gains and (losses) included in sales of oil and
gas
|
326.1
|
|
401.6
|
Purchases,
sales and settlements, net
|
(.4)
|
|
(26.3)
|
Transfers
in and/or out of Level 3
|
-
|
|
-
|
Fair
value, June 30, 2008
|
$569.6
|
|
$569.6
|
|
|
|
|
Total
unrealized gains and (losses) included in income related to financial
assets and liabilities still on the condensed balance sheet at June 30,
2008
|
$
-
|
|
$-
|
In
February of 2007, the FASB issued SFAS 159, which is effective for fiscal years
beginning after November 15, 2007. SFAS 159 provides an option to elect
fair value as an alternative measurement for selected financial assets and
financial liabilities not previously carried at fair value. We adopted this
statement at January 1, 2008, but did not elect fair value as an alternative for
any financial assets or liabilities.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
The
related cash flow impact of all of our hedges is reflected in cash flows from
operating activities. At June 30, 2008, our net fair
value of
derivatives liability was $624.3 million as compared to $201.6 million at
December 31, 2007 which reflects increases in commodity prices in the period.
Based on NYMEX strip pricing as of June 30, 2008, we expect to make hedge
payments under the existing derivatives of $303.9 million during the next twelve
months. At June 30, 2008, Accumulated Other Comprehensive Loss consisted of
$386.6 million, net of tax, of unrealized losses from our crude oil and natural
gas swaps and collars that qualified for
hedge
accounting treatment at June 30, 2008. Deferred net losses recorded in
Accumulated Other Comprehensive Loss at June 30, 2008 and subsequent
mark-to-market changes in the underlying hedging contracts are expected to be
reclassified to earnings over the life of these contracts.
We
entered into the following natural gas hedges during the three months ended
March 31, 2008:
·
|
Swaps
on 15,400 MMBtu/D at $8.50 for the full year of 2009 and basis swaps on
the same volumes for average prices of $1.17, $1.12, $.97, and $1.05 for
each of the four quarters of 2009,
respectively.
|
These
hedges have been designated as cash flow hedges in accordance with SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities. These swaps were not highly effective
at inception, so we subsequently entered into basis swaps and established
effectiveness at that time. We did not enter into any hedges during
the three months ended June 30, 2008. In 2007, we entered into
natural gas swap contracts that were not highly effective. We
recognized an unrealized net loss of approximately $.1 million and $.8 million
on the income statement under the caption “Commodity derivatives” in the three
and six months ended June 30, 2008, respectively.
5.
|
Asset Retirement
Obligations
|
Inherent
in the fair value calculation of the asset retirement obligation (ARO) are
numerous assumptions and judgments including the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political environments. To
the extent future revisions to these assumptions impact the fair value of the
existing ARO liability, a corresponding adjustment is made to the oil and gas
property balance.
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the six months ended June 30, 2008 (in thousands):
Beginning
balance at January 1
|
|
$
|
36,426
|
|
Liabilities
incurred
|
|
|
2,102
|
|
Liabilities
settled
|
|
|
(2,127
|
)
|
Revisions
in estimated liabilities
|
|
|
|
|
|
|
|
|
|
Ending
balance at June 30
|
|
|
|
|
The
effective tax rate was 37% for the second quarter of 2008 compared to 39%
for the first quarter of 2008 and 39% for the second quarter of 2007. The lower
rate in the second quarter reflects changes in our state income apportionment
which includes the projected income from our East Texas
acquisition. Our rate differs from the combined federal and state
statutory tax rate (net of the federal benefit), primarily due to certain
business incentives.
As of
June 30, 2008, we had a gross liability for uncertain tax benefits of
$12.9 million of which $10.5 million, if recognized, would affect the
effective tax rate. There were no significant changes to the calculation since
year end 2007.
Due to
the uncertainty about the periods in which examinations will be completed and
limited information related to current audits, we are not able to make
reasonably reliable estimates of the periods in which cash settlements will
occur with taxing authorities for the noncurrent liabilities.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
7.
|
Long-term
and Short-term Debt Obligations
|
Short-term
debt
In 2005,
we completed an unsecured uncommitted money market line of credit (Line of
Credit). Borrowings under the Line of Credit may be up to $30 million for a
maximum of 30 days. The Line of Credit may be terminated at any time
upon written notice by either us or the lender. At June 30, 2008 the outstanding
balance under this Line of Credit was zero. Interest on amounts borrowed is
charged at LIBOR plus a margin of approximately 1%. The weighted average
interest rate on outstanding borrowings on the Line of Credit at June 30, 2008
was 3.4%.
Long-term
debt
In 2006,
we issued in a public offering $200 million of 8.25% senior subordinated notes
due 2016 (the Notes). The deferred costs of approximately $5 million associated
with the issuance of this debt are being amortized over the ten year life of the
Notes.
We have a
senior unsecured bank credit facility agreement (the Agreement) with a banking
syndicate through June 30, 2011. The Agreement is a revolving credit facility
for up to $750 million. In 2007, we increased our borrowing base to $550 million
and in the second quarter of 2008, we increased our annual borrowing base to
$650 million with a funding commitment from our banking
syndicate
to $600 million. The outstanding Line of Credit reduces our borrowing
capacity available under the Agreement. We amended this facility in
July 2008 (see footnote 9 Subsequent Events in these financial
statements).
The total
outstanding debt at June 30, 2008 under the credit facility and the short-term
Line of Credit was $311 million and zero, respectively, leaving $339 million in
borrowing capacity available. Interest on amounts borrowed under this debt is
charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with margins
on the various rate options based on the ratio of credit outstanding to the
borrowing base. We are required under the Agreement to pay an annual commitment
fee of .25% to .375% on the unused portion of the credit facility.
The
maximum amount available is subject to an annual redetermination of the
borrowing base in accordance with the lender's customary procedures and
practices. Both we and the banks have bilateral rights to one additional
redetermination each year.
The
Agreement contains restrictive covenants which, among other things, require us
to maintain a certain debt to EBITDA ratio and a minimum current ratio, as
defined. The $200 million Notes are subordinated to our credit facility
indebtedness. As long as the interest coverage ratio (as defined) is met, we may
incur additional debt. We were in compliance with all covenants as of June 30,
2008. The weighted average interest rate on total outstanding borrowings at
June 30, 2008 was 5.6%.
Additionally,
in 2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility for five years. These interest rate swaps have been designated
as cash flow hedges.
8.
|
Contingencies
and Commitments
|
We have
no accrued environmental liabilities for our sites, including sites in which
governmental agencies have designated us as a potentially responsible party,
because it is not probable that a loss will be incurred and the minimum cost
and/or amount of loss cannot be reasonably estimated. However, because of the
uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be incurred. Management believes,
based upon current site assessments, that the ultimate resolution of any matters
will not result in substantial costs incurred. We are involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of our
business. In the opinion of management, the resolution of these matters will not
have a material effect on our financial position, or on the results of
operations or liquidity.
In February 2007, we entered into a
multi-staged crude oil sales contract with a refiner for our Uinta basin light
crude oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D in July
2007. The refiner has increased its total purchase volume capacity to 5,000
Bbl/D as provided in our contract. The differential under the
contract, which includes transportation and gravity adjustments, is linked to
WTI and would range from $20 to $30 per barrel at WTI prices between $80 and
$120 per barrel. Gross oil production averaged approximately 4,000
BOE/D in the quarter ended June 30, 2008.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
On July 15, 2008, we
closed on the previously announced acquisition of certain interests in natural
gas producing properties on 4,500 net acres in Limestone and Harrison Counties
of East Texas. The acquisition adds approximately 32 million cubic feet
equivalent per day to our production from approximately 100 producing wells. The
adjusted purchase price is $653 million, including closing adjustments of $32
million based on the effective date of February 1, 2008. The
acquisition was initially financed by bank borrowings under the Company’s
amended and restated credit agreement.
Also, on
July 15, 2008, we entered into a five-year amended and restated credit agreement
(the “Credit Agreement”) with Wells Fargo Bank, N.A as administrative agent and
a syndicate of other lenders. The secured revolving credit facility
amends and restates our previous credit agreement dated as of April 28, 2006, as
amended. The Credit Agreement is a $1.5 billion revolving facility with an
initial borrowing base of $1 billion. Interest on amounts borrowed
under this debt is charged at either LIBOR plus a margin of 1.125% to 1.875% or
the prime rate plus a margin with margins on the various rate options based on
the ratio of credit outstanding to the borrowing base. Additionally,
an annual commitment fee of .25% to .375% is charged on the unused portion of
the credit facility. Borrowings under the Credit Agreement are
secured by various of our assets and the Credit Agreement and related documents
contain customary covenants similar to our previous credit facility and
restrictions on the secured assets. The Credit Agreement matures on
July 15, 2013. In conjunction with securing our credit facility we also secured
our Line of Credit.
On July
15, 2008, we borrowed approximately $594 million under the Credit Agreement to
pay the remaining consideration due for the East Texas acquisition. As of July
15, 2008, we had approximately $75 million available to be drawn under our
$1 billion credit facility.
Additionally,
we entered into a commitment letter with certain lenders to execute a $100
million senior unsecured revolving credit facility. The execution of
definitive documentation of the unsecured credit facility is subject to
completion of due diligence by the Lenders and is expected to occur no later
than July 31, 2008. The unsecured credit facility is expected to
mature on December 31, 2008 and will have usual and customary conditions,
representations and warranties.
Item 2. Management’s Discussion and
Analysis of Financial Condition and Results of Operations
General. The
following discussion provides information on the results of operations for the
three and six month periods ended June 30, 2008 and 2007 and our financial
condition, liquidity and capital resources as of June 30, 2008. The financial
statements and the notes thereto contain detailed information that should be
referred to in conjunction with this discussion.
The
profitability of our operations in any particular accounting period will be
directly related to the realized prices of oil, gas and electricity sold, the
type and volume of oil and gas produced and electricity generated and the
results of development, exploitation, acquisition, exploration and hedging
activities. The realized prices for natural gas and electricity will fluctuate
from one period to another due to regional market conditions and other factors,
while oil prices will be predominantly influenced by global supply and demand.
The aggregate amount of oil and gas produced may fluctuate based on the success
of development and exploitation of oil and gas reserves pursuant to current
reservoir management. The cost of natural gas used in our steaming operations
and electrical generation, production rates, labor, equipment costs, maintenance
expenses, and production taxes are expected to be the principal influences on
operating costs. Accordingly, our results of operations may fluctuate from
period to period based on the foregoing principal factors, among
others.
Overview. We
seek to increase shareholder value through consistent growth in our production
and reserves, both through the drill bit and acquisitions. We strive to operate
our properties in an efficient manner to maximize the cash flow and earnings of
our assets. The strategies to accomplish these goals include:
·
|
Developing
our existing resource base
|
·
|
Acquiring
additional assets with significant growth
potential
|
·
|
Utilizing
joint ventures with respected partners to enter new
basins
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
Notable
Second Quarter Items.
·
|
Achieved
record production averaging 29,000 BOE/D, up 7% from the second quarter of
2007 and up 3% from the first quarter of
2008
|
·
|
Increased
Piceance net average production to 20.8 MMcf/D in the month of June, up
24% from the first quarter of 2008
|
·
|
Increased
Diatomite net production to an average of 1,700 BOE/D, up 24% from the
first quarter of 2008
|
·
|
Production
at Poso Creek averaged 3,200 Bbl/D, up 19% from the first quarter of
2008
|
·
|
Achieved
a production exit rate of 30,000
BOE/D
|
·
|
Completed
relocation of our corporate headquarters from Bakersfield, California to
Denver, Colorado
|
·
|
Announced
that David D. Wolf would join the Company as Executive Vice President and
Chief Financial Officer
|
Notable
Items and Expectations for the Third Quarter of 2008.
·
|
Closed
on the acquisition of 4,500 acres in Limestone and Harrison Counties of
East Texas on July 15, 2008, adding an estimated 32 MMcf/D to
production
|
·
|
Increased
our 2008 capital budget by $75 million to $370 million to fund the
development of our East Texas
acquisition
|
·
|
Entered
into an amended and restated secured credit facility with a $1 billion
borrowing base
|
·
|
Targeting
a production average of approximately 35,000 BOE/D in the third quarter
and a 2008 exit rate of between 39,000 and 40,000
BOE/D
|
Overview of the
Second Quarter of 2008. We had net income of $49 million, or $1.08 per
diluted share and net cash from operations was $107 million. We drilled 120
gross wells and capital expenditures, excluding property acquisitions, totaled
$95 million. We achieved average production of 29,000 BOE/D in the second
quarter of 2008, up 3% from an average of 28,066 BOE/D in the first quarter of
2008.
Results of
Operations. The following
companywide results are in millions (except per share data) for the three months
ended:
|
|
June
30, 2008
(2Q08)
|
|
June
30, 2007
(2Q07)
|
2Q08
to 2Q07 Change
|
March
31, 2008
(1Q08)
|
2Q08
to 1Q08
Change
|
Sales
of oil
|
|
$
|
146
|
|
$
|
94
|
55%
|
$
|
131
|
11%
|
Sales
of gas
|
|
|
39
|
|
|
19
|
105%
|
|
33
|
19%
|
Total
sales of oil and gas
|
|
$
|
185
|
|
$
|
113
|
64%
|
$
|
164
|
13%
|
Sales
of electricity
|
|
|
17
|
|
|
14
|
21%
|
|
16
|
6%
|
Gain
on sale of assets
|
|
|
-
|
|
|
50
|
-%
|
|
-
|
-%
|
Other
revenues
|
|
|
13
|
|
|
2
|
550%
|
|
5
|
160%
|
Total
revenues and other income
|
|
$
|
215
|
|
$
|
179
|
20%
|
$
|
185
|
16%
|
Net
income
|
|
$
|
49
|
|
$
|
52
|
(6%)
|
$
|
43
|
14%
|
Earnings
per share (diluted)
|
|
$
|
1.08
|
|
$
|
1.16
|
(7%)
|
$
|
.95
|
14%
|
Our
revenues may vary significantly from period to period as a result of changes in
commodity prices and/or production volumes. Crude oil sales in the
three months ended June 30, 2008 were 11% higher than the three months ended
March 31, 2008 resulting from price increases of 6% and sales volume increases
of 5%. Gas sales in the three months ended June 30, 2008 were 19% higher than
the three months ended March 31, 2008 resulting from production increases of
3% and a price increase of 16%. Net income decreased 6% from the
second quarter of 2007 to the second quarter of 2008 in part due to the $50.4
million pretax gain on the sale of assets during the second quarter of
2007.
In the
first quarter of 2008, we determined there was an error in computing royalties
payable in prior years, accumulating to $10.5 million as of December 31, 2007.
We concluded the error was not material to any individual prior interim or
annual period (or to the projected earnings for 2008) and, therefore, this error
was corrected during the first quarter of 2008, with the effect of increasing
our sales of oil and gas by $10.5 million and reducing our royalties
payable.
Operating
data. The following table is for the three months ended:
|
|
|
June
30, 2008
|
%
|
|
June
30, 2007
|
%
|
|
March
31, 2008
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,888
|
58
|
|
16,129
|
59
|
|
16,375
|
58
|
Light
Oil Production (Bbl/D)
|
|
|
3,723
|
13
|
|
4,034
|
15
|
|
3,510
|
13
|
Total
Oil Production (Bbl/D)
|
|
|
20,611
|
71
|
|
20,163
|
74
|
|
19,885
|
71
|
Natural
Gas Production (Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
Total
(BOE/D)
|
|
|
29,000
|
100
|
|
27,195
|
100
|
|
28,066
|
100
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas, per BOE:
|
|
|
|
|
|
|
|
|
|
|
Average sales price before hedging
|
|
|
|
|
|
|
|
|
|
|
Average
sales price after hedging
|
|
|
69.77
|
|
|
45.43
|
|
|
60.43
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
123.80
|
|
$
|
65.02
|
|
$
|
97.82
|
|
Price
sensitive royalties
|
|
|
(5.92
|
)
|
|
(4.20
|
)
|
|
(4.47
|
)
|
Quality
differential and other
|
|
|
(11.52
|
)
|
|
(9.24
|
)
|
|
(10.78
|
)
|
Crude
oil hedges
|
|
|
(29.37
|
)
|
|
(.52
|
)
|
|
(15.60
|
)
|
Correction
to royalties payable
|
|
|
-
|
|
|
-
|
|
|
5.85
|
|
Average
oil sales price after hedging
|
|
$
|
76.99
|
|
$
|
51.06
|
|
$
|
72.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
10.93
|
|
$
|
7.55
|
|
$
|
8.05
|
|
Conversion
to Mcf
|
|
|
.55
|
|
|
.38
|
|
|
.40
|
|
Natural
gas hedges
|
|
|
(.69
|
)
|
|
.71
|
|
|
(.12
|
)
|
Location,
quality differentials and other
|
|
|
(2.15
|
)
|
|
(3.53
|
)
|
|
(.90
|
)
|
Average
gas sales price after hedging
|
|
$
|
8.64
|
|
$
|
5.11
|
|
$
|
7.43
|
|
Operating
data. The following table is for the six months ended:
|
|
|
|
June
30, 2008
|
%
|
|
June
30, 2007
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,631
|
58
|
|
16,112
|
61
|
|
|
Light
Oil Production (Bbl/D)
|
|
|
3,617
|
13
|
|
3,643
|
14
|
|
|
Total
Oil Production (Bbl/D)
|
|
|
20,248
|
71
|
|
19,755
|
75
|
|
|
Natural
Gas Production (Mcf/D)
|
|
|
|
|
|
|
|
|
|
Total
(BOE/D)
|
|
|
28,534
|
100
|
|
26,332
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas, per BOE:
|
|
|
|
|
|
|
|
|
|
Average sales price before hedging
|
|
|
|
|
|
|
|
|
|
Average
sales price after hedging
|
|
|
67.23
|
|
|
44.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
111.12
|
|
$
|
61.68
|
|
|
|
Price
sensitive royalties
|
|
|
(5.21
|
)
|
|
(3.97
|
)
|
|
|
Quality
differential and other
|
|
|
(11.15
|
)
|
|
(9.01
|
)
|
|
|
Crude
oil hedges
|
|
|
(22.66
|
)
|
|
(.24
|
)
|
|
|
Correction
to royalties payable
|
|
|
2.85
|
|
|
-
|
|
|
|
Average
oil sales price after hedging
|
|
$
|
74.95
|
|
$
|
48.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
9.49
|
|
$
|
7.16
|
|
|
|
Conversion
to Mcf
|
|
|
.47
|
|
|
.36
|
|
|
|
Natural
gas hedges
|
|
|
(.41
|
)
|
|
.44
|
|
|
|
Location,
quality differentials and other
|
|
|
(1.50
|
)
|
|
(2.12
|
)
|
|
|
Average
gas sales price after hedging
|
|
$
|
8.05
|
|
$
|
5.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Basis
Differential. The basis differential between Henry Hub
(HH) and Colorado Interstate Gas (CIG) index narrowed due to the increased
take away capacity added by the start up of the Rockies Express Pipeline
(REX) in January. However, the differential widened again in
the second quarter. In the first quarter of 2008, the CIG basis
differential per MMBtu, based upon first-of-month values, averaged $1.07
below HH and ranged from $.91 to $1.19 below HH. For the
second quarter, the differential averaged $2.46 with the range going from
$1.78 at the start of the quarter to $3.24 below HH at the end of the
quarter. We have contracted a total of 35,000 MMBtu/D on the REX pipeline
under two separate transactions to provide firm transportion for our
Piceance basin gas production. After the REX startup in 2008,
all of the Piceance basin gas was sold at mid-continent (ANR, NGPL or
PEPL) indexes which averaged approximately $.70 above the CIG index
pricing before the cost of transportation.
|
Gas from
the Uinta basin sold for approximately $.03 below CIG pricing before deducting
the cost of pipeline transport. A portion of the Uinta gas is priced
on the Questar index while the remainder is based upon the CIG or NWPL
index.
DJ Basin
gas is priced using one of two indices. Approximately two-thirds of our volume
from our DJ natural gas properties is tied to the Panhandle Eastern Pipeline
(PEPL) index for pricing and the remaining volume to CIG pricing. For that
portion of the production with firm transportation on either the Cheyenne Plains
Pipeline or the KMIGT pipeline, pricing is based upon the PEPL index which
averaged approximately $1.84 below the HH index during the second quarter,
before the cost of transportation. The remainder of the DJ Basin gas is sold
slightly above the CIG index price.
Gas Marketing.
In December 2007, we entered into a second long-term (ten year) firm
transportation contract for our Colorado natural gas production. This contract
is for 25,000 MMBtu/D on the REX pipeline for gas production in the Piceance
basin. We pay a demand charge for this capacity and our own production did
not fill that capacity. In order to maximize our firm transportation capacity,
we bought our partners’ share of the gas produced in the Piceance at the market
rate for that area. We then used our excess transportation to move this gas
to where it was eventually sold. The net of our gas marketing revenue and
our gas marketing expense in the Statements of Income is $.7 million in the six
month period ended June 30, 2008. We expect our production will reach our firm
transportation contract volume during 2009.
Oil Contracts.
Utah - In February 2007, we entered into a multi-staged crude oil sales
contract with a refiner for our Uinta basin light crude oil. Under the
agreement, the refiner began purchasing 3,200 Bbl/D in July 2007. The refiner
has increased its total capacity to 5,000 Bbl/D as provided in our contract. As
operator we deliver all produced volumes under our sales contracts, although our
working interest partners or royalty owners may take their respective volumes in
kind and market their own volumes. Gross oil production averaged
approximately 4,000 BOE/D in the quarter ended June 30, 2008. The differential
under the contract, which includes transportation and gravity adjustments, is
linked to WTI and would range from $20 to $30 per barrel at WTI prices between
$80 and $120. This contract provides us an outlet to sell all of our current oil
production in the Uinta basin.
Hedging.
See Note 4 to the unaudited condensed financial statements and Item 3.
Quantitative and Qualitative Disclosures about Market Risk.
Electricity. We
consume natural gas as fuel to operate our three cogeneration facilities which
are intended to provide an efficient and secure long-term supply of steam
necessary for the cost-effective production of heavy oil in California. We sell
our electricity to utilities under standard offer contracts based on "avoided
cost" or SRAC pricing approved by the California Public Utilities Commission
(CPUC) and under which our revenues are currently linked to the cost of natural
gas. Natural gas index prices are the primary determinant of our electricity
sales price based on the current pricing formula under these contracts. The
correlation between electricity sales and natural gas prices allows us to manage
our cost of producing steam more effectively.
In 2007,
our electricity operations improved partially from the lower cost of our firm
transportation natural gas compared to California prices which are used to
determine our electricity payment. We purchase and transport 12,000 MMBtu/D on
the Kern River Pipeline under our firm transportation contract and use this
gas to produce conventional and cogeneration steam in the Midway-Sunset field.
The differential between Rocky Mountain gas prices and Southern California
Border prices increased during 2007 allowing us to purchase a portion of our gas
at a discount to the Southern California Border price. As our electricity
revenue is linked to Southern California Border prices, the fuel we purchased at
lower Rocky Mountain prices was the primary contributor to the increase in our
electricity margin in 2007. We purchased approximately 38,000 MMBtu/D as fuel
for use in our cogeneration facilities in the year ended December 31, 2007.
Rockies natural gas differentials have stabilized near their historical levels
and we do not expect to have significant positive electricity margins in 2008.
We expect to have small gains or losses on electricity on a quarterly basis
which depends on seasonality as we receive improved pricing during the summer
months. On September 20, 2007, the CPUC issued a decision (SRAC Decision) that
changes the way SRAC energy prices will be determined for existing and new
Standard Offer (SO) contracts and revises the capacity prices paid under current
SO1 contracts. Based on our preliminary analysis, we do not believe that the
proposed pricing changes will materially affect us in 2008.
The
following table is for the three months ended:
|
|
|
June
30, 2008
|
|
|
June
30, 2007
|
|
|
March
31, 2008
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
17.0
|
|
$
|
13.9
|
|
$
|
15.9
|
|
Operating
costs (in millions)
|
|
|
15.5
|
|
|
11.1
|
|
|
16.4
|
|
Electric
power produced - MWh/D
|
|
|
1,919
|
|
|
2,060
|
|
|
2,152
|
|
Electric
power sold - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
10.01
|
|
$
|
6.46
|
|
$
|
7.94
|
|
Oil and Gas
Operating, Production Taxes, G&A and Interest Expenses.
The following table presents information about our operating expenses for
each of the three month periods ended:
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
|
|
June
30, 2008
|
|
June
30, 2007
|
|
March
31, 2008
|
|
June
30, 2008
|
|
June
30, 2007
|
|
March
31, 2008
|
|
Operating
costs – oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
4.23
|
|
|
3.90
|
|
|
4.46
|
|
|
11,160
|
|
|
9,651
|
|
|
11,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
40.49
|
|
$
|
31.47
|
|
$
|
35.16
|
|
$
|
106,850
|
|
$
|
77,888
|
|
$
|
89,793
|
|
Our total
operating costs, production taxes, DD&A, G&A and interest expenses for
the three months ended June 30, 2008, stated on a unit-of-production basis,
increased 29% over the three months ended June 30, 2007 and increased
15% as compared to the three months ended March 31, 2008. The changes
were primarily related to the following items:
|
·
|
Operating
costs: The majority of the increase in our operating costs was due to
higher steam costs resulting from higher fuel costs. The following table
presents steam information:
|
|
June
30, 2008
(2Q08)
|
June
30, 2007
(2Q07)
|
2Q08
to 2Q07
Change
|
March
31, 2008
(1Q08)
|
2Q08
to 1Q08
Change
|
Average
volume of steam injected (Bbl/D)
|
97,853
|
84,032
|
16%
|
91,326
|
7%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
10.01
|
$
6.46
|
55%
|
$
7.94
|
26%
|
Approximate
net fuel gas volume consumed in steam
generation
(MMBtu/D)
|
27,382
|
22,559
|
21%
|
21,634
|
27%
|
Our total
cost to purchase fuel for our steam operations increased by $2.07 per MMBtu or
26% in the three months ended June 2008 compared to the three months ended March
2008 as the SoCal border natural gas price increased over this time
period. We consumed an additional 5,750 MMBtu/D in the second quarter
of 2008 when compared to the first quarter of 2008 primarily related to
increased conventional steam generation consumption and seasonal changes in the
price received for our electricity which is used to allocate our cogeneration
fuel gas volumes between electricity costs and steam costs. The
increase in natural gas prices and our overall consumption accounted for
approximately $10 million of the $13.6 million increase in operating costs
between the first and second quarters of 2008. We plan to increase
our fuel gas consumption by 4,000 MMBtu/D in the fourth quarter of 2008 as we
add additional steam generation capacity at Poso Creek and the
Diatomite.
During
2008, we generally expect a small change in our net income due to a change in
natural gas prices as an increase in our steam costs is offset by revenue from
our gas production and payments under our hedges. However, our gas
long position can be impacted by volatility in the differential between the
SoCal border price where we purchase the majority of our natural gas for steam
generation and the Rockies prices at which we sell our produced
volumes. Our realized price from the sale of natural gas increased
$1.21/Mcf from the first quarter of 2008 as compared to the second quarter of
2008 while the cost of fuel purchased to generate steam and electricity
increased $2.07/MMBtu over the same period.
·
|
Production
taxes: Our production taxes have increased compared to the second quarter
of 2007 and the first quarter of 2008 as commodity prices and thus the
values of our oil and natural gas has increased. Severance taxes paid in
Utah and Colorado, 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. We expect production taxes to track oil and
gas prices generally.
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE by 17% and 4%
in the second quarter of 2008 as compared to the second quarter of 2007
and as compared to the first quarter of 2008, respectively, due to an
increase in the contribution of our development properties with higher
drilling and leasehold acquisition costs, which is in line with our
expectations.
|
·
|
General
and administrative: Approximately 70% of our G&A is related to
compensation. The primary reason for the increase in G&A during the
second quarter of 2008 as compared to the second quarter of 2007 was
primarily due to an increase in the number of employees from 243 as of
June 30, 2007 to 274 as of June 30,
2008.
|
·
|
Interest
expense: Our total outstanding borrowings were approximately
$511 million at June 30, 2008 compared to $475 million and $455
million at June 30, 2007 and March 31, 2008, respectively. For the three
months ended June 30, 2008, $4 million of interest cost has been
capitalized and we expect to capitalize approximately $20 million of
interest cost during the full year of
2008.
|
Estimated 2008
and Actual Six Months Ended June 30, 2008 and 2007 Oil and Gas
Operating, G&A and
Interest Expenses.
We estimate our average 2008 production volume will range between 32,500 BOE/D
and 33,500 BOE/D. Based on actual first six months and the remainder of 2008 at
NYMEX WTI crude oil price of $100 per barrel and NYMEX HH natural gas price of
$10.00 per MMBtu, we expect our expenses to be within the following
ranges:
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2008
per
BOE
|
|
Six
months ended
June
30, 2008
|
|
Six
months ended
June
30, 2007
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
18.50
to 20.50
|
|
$
|
18.64
|
|
$
|
14.55
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
4.00
to 4.50
|
|
|
4.34
|
|
|
4.19
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
36.20
to 40.70
|
|
$
|
37.86
|
|
$
|
31.19
|
|
(1)
We expect operating costs to increase in 2008 as compared to 2007 due to higher
projected natural gas costs.
Our total
operating costs, production taxes, DD&A, G&A and interest expenses for
the six months ended June 30, 2008, stated on a unit-of-production basis,
increased 21% over the six months ended June 30, 2007. The changes were
primarily related to the following items:
|
·
|
Operating
costs: The majority of the increase in our operating costs was due to
higher steam costs resulting from higher fuel costs. The following table
presents steam information:
|
|
Six
months ended
June
30, 2008
|
|
Six
months ended
June
30, 2007
|
Change
|
Average
volume of steam injected (Bbl/D)
|
94,589
|
|
85,076
|
11%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
8.98
|
|
$
6.58
|
37%
|
Approximate
net fuel gas volume consumed in
steam
generation (MMBtu/D)
|
24,536
|
|
21,022
|
17%
|
Our total
cost to purchase fuel for our steam operations increased by $2.40 per MMBtu or
37% in the six months ended June 2008 compared to the six months ended June 2007
as the SoCal border natural gas price increased over this time
period. We consumed an additional 3,510 MMBtus per day in the first
six months of 2008 when compared to the first six months of 2007 primarily
related to increased conventional steam generation consumption and seasonal
changes in the price received for our electricity which is used to allocate our
cogeneration fuel gas volumes.
·
|
Production
taxes: Production taxes per BOE in the six months ended June 30, 2008 were
55% higher than the comparable period in 2007 as commodity prices and thus
the values of our oil and natural gas has increased. Severance taxes paid
in Utah and Colorado, 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. We expect production taxes to track oil and
gas prices generally.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE were 22% higher in the six
months ended June 30, 2008 compared to the same period in the prior year
due to an increase in the contribution of our development properties with
higher drilling and leasehold acquisition costs, which is in line with our
expectations.
|
·
|
General
and administrative: G&A per BOE increased by 4% in the six months
ended June 30, 2007 compared to the same period in the prior year due to
additional staffing and higher overall compensation costs associated with
our growth activities.
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured money
market line of credit and senior subordinated notes, was approximately
$511 million at June 30, 2008 compared to approximately
$475 million at June 30, 2007. For the six months ended June 30,
2008, $8 million of interest cost has been
capitalized.
|
Royalties. The
price sensitive royalty that burdens our Formax property in the South Midway
Sunset field has changed. We previously paid a royalty equal to 75%
of the amount of the heavy oil posted above a price of $16.11. This
price escalates at 2% annually. Effective January 1, 2008, the
royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam
injection level, which we expect to meet, that reduces over
time. Current net production from this property is approximately
2,300 Bbl/.
Dry Hole,
Abandonment, impairment and exploration. In the first six
months of 2008, we recorded a total of $7.6 million in dry hole, abandonment,
impairment and exploration expense. Charges of $2.7 million and $2.6
million were recorded during the first and second quarters of 2008, respectively
for technical difficulties that were encountered on four wells in the Piceance
basin before reaching total depth. These holes were abandoned
in favor of drilling to the same bottom hole location by drilling new
wells. In addition, $2.3 million of exploration expense
was recorded for exploration activities which were primarily 3-D seismic
activity in the DJ basin.
Income
Taxes. We experienced an effective tax rate of 37% and 39% in the
three months ended June 30, 2008 and June 30, 2007, respectively. The
lower rate in the second quarter of 2008 when compared to the same period in the
prior year reflects changes in our state income apportionment which includes the
projected income from our East Texas acquisition. Our rate differs from the
combined federal and state statutory tax rate (net of the federal benefit),
primarily due to certain business incentives. See Note 6 to the unaudited
condensed financial statements.
Development, Exploitation and
Exploration
Activity. We drilled 120 gross (112 net) wells during the second quarter
of 2008. As of June 30, 2008, we have 4 rigs drilling on our properties under
long-term contracts and 4 more under short term contracts.
Drilling
Activity. The following table sets
forth certain information regarding drilling activities (including operated and
non-operated wells):
|
|
|
|
Six months ended
June
30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S.
Cal
|
|
4
|
|
4
|
|
25
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties
We have
six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset
including diatomite (N. Midway), Southern California including Poso Creek and
Placerita (S. Cal), Piceance, Uinta and DJ.
S.
Midway – During the three months ended June 30, 2008, production averaged
approximately 9,100 Bbl/D compared to approximately 9,700 Bbl/D and 9,200 Bbl/D
during the three month periods ended June 30, 2007 and March 31, 2008,
respectively. We will invest $31 million on our S. Midway properties in 2008 to
drill additional deeper horizontal wells along the cold, unswept flanks of the
reservoir. Additional vertical wells will also be drilled to provide steam
support for these horizontal wells. Sixteen horizontal wells plus the vertical
steam support wells have been drilled and are performing as expected. We plan to
drill the remaining six horizontal wells during the last half of the
year. In 2008, we also began developing the Monarch reservoir on our
Ethel D property. We drilled 24 wells in the Monarch in the first six
months of the year and production averaged 900 Bbl/D using cyclic steam
injection. We believe that production can be further enhanced through
a steamflood and we will be expanding the pilot we began in 2007 later this
year.
N.
Midway – During the three months ended June 30, 2008, production from the
area averaged approximately 2,600 Bbl/D compared to approximately 2,100 Bbl/D
and 2,400 Bbl/D during the three month periods ended June 30, 2007 and March 31,
2008, respectively. In October 2007, we embarked on a full-scale, continuous
development program of the Diatomite and we expect to drill non-stop over the
next four years. Over 83 new producers have been drilled since October 2007. We
are bringing these wells on production as the necessary infrastructure is
installed to steam and produce these wells. We will nearly triple our producing
well count this year from 80 wells at the end of 2007 to approximately 240 wells
by year end 2008 and increase our steam generation capacity from 10,000 BSPD at
the end of 2007 to 25,000 BSPD by the end of 2008. The additional wells, steam
and supporting infrastructure should enable us to increase production of the
Diatomite which averaged 1,700 BOE/D during the second quarter of 2008 to over
3,000 BOE/D by year end 2008. Additionally, we have drilled 6 delineation wells
on the northern portion of our property and have identified significant
additional resource potential that we will be evaluating during the remainder of
the year.
S. Cal –
During the three months ended June 30, 2008, production averaged approximately
5,300 Bbl/D compared to approximately 4,100 Bbl/D and 4,800 Bbl/D during the
three month periods ended June 30, 2007 and March 31, 2008, respectively. This
year’s plans at Poso Creek call for further expansion including the addition of
a fourth steam generator, which we brought on line in February, drilling 28
producers and expanding the steam flood. As of June 2008, all 28 planned
producers have been drilled and Poso Creek production is currently over 3,300
BOE/D. During the remainder of 2008, additional steam injectors will be drilled
and a fifth steam generator will be installed to further increase our production
from this asset.
Piceance – During the
three months ended June 30, 2008, production from the Piceance basin averaged
16.6 MMcf/D. Of the Berry operated wells, we drilled 18 gross wells (12 net)
during the second quarter of 2008. We are currently drilling our 36th well of
the year and the 108th well since we acquired our original Piceance basin
acreage in early 2006. We continue to operate four drilling rigs and see further
efficiencies with repeated drilling times of 12 to 15 days for a mesa well. Late
in the second quarter of 2008, we began realizing increased production as we
moved into the summer completion season with current production now over 22
MMcf/D. Initial production rates from these wells have been in line
with our expectations.
Uinta –
Average daily production during the three months ended June 30, 2008 from
all Uinta basin assets was approximately 6,100 net BOE/D. During the three
months ended June 30, 2008, we accelerated our drilling program with an
additional rig but plan to return to a one rig program for the remainder of
2008. The development at Brundage Canyon continues to be focused on
drilling high potential areas in the core of the field where we drilled 20 wells
in the second quarter of 2008. Evaluating the waterflood feasibility
at Brundage Canyon has progressed and we have begun the permitting process, with
first injection expected by year end 2008. Late in the second quarter of 2008,
we further delineated the Ashley Forest by drilling two wells under our current
environmental approvals and we anticipate drilling four to six additional wells
during the last half of 2008. We continue to optimize and pace our
Uinta drilling program while the Ashley Forest Development EIS progresses
towards its anticipated approval in early 2009.
DJ – During the three
months ended June 30, 2008, we drilled 8 successful gross Niobrara development
wells in Yuma County, Colorado, with a 100% success rate. Average daily
production in the DJ basin for the three months ended June 30, 2008 was 19.6 net
MMcf/D and we had $.3 million of exploration expense in the second quarter
related to our seismic surveys. During the second quarter we completed the
interpretation of an additional 75 square miles of 3-D seismic that we acquired
over the winter and expect to replenish our low risk repeatable drilling
inventory.
Financial
Condition, Liquidity and Capital Resources. Substantial capital is
required to replace and grow reserves. We achieve reserve replacement and growth
primarily through successful development and exploration drilling and the
acquisition of properties. Fluctuations in commodity prices, production rates
and operating expenses have been the primary reason for changes in our cash flow
from operating activities.
We had a
senior unsecured revolving bank credit facility agreement (the Agreement) with a
banking syndicate through June 30, 2011. The Agreement was a revolving
credit facility for up to $750 million with a borrowing base as of June 30, 2008
of $600 million. As of June 30, 2008, we had total borrowings under
the Agreement and Line of Credit of $311 million and $200 million under our
senior subordinated ten year notes.
On July
15, 2008, we entered into a five-year amended and restated credit agreement with
Wells Fargo Bank, N.A as administrative agent and other lenders. The
secured revolving credit facility amends and restates the Company’s previous
credit agreement dated as of April 28, 2006, as amended. The
Credit Agreement is a $1.5 billion revolving facility with an initial borrowing
base of $1 billion. On July 15, 2008, we borrowed approximately $594 million
under the Credit Agreement to pay the remaining consideration due in the East
Texas acquisition. As of July 15, 2008, we had approximately $75 million
available to be drawn under our $1 billion credit facility. This
agreement matures on July 15, 2013. In conjunction with securing our credit
facility we also secured our Line of Credit.
Additionally,
we entered into a commitment letter with certain lenders to execute a $100
million senior unsecured revolving credit facility. The execution of
definitive documentation of the unsecured credit facility is subject to
completion of due diligence by the Lenders and is expected to occur no later
than July 31, 2008. The unsecured credit facility is expected to
mature on December 31, 2008 and will have usual and customary conditions,
representations and warranties.
Capital
Expenditures. We establish a capital
budget for each calendar year based on our development opportunities and the
expected cash flow from operations for that year. Acquisitions are typically
debt financed. We may revise our capital budget during the year as a result of
acquisitions and/or drilling outcomes or significant changes in cash
flows.
In 2008,
we had an original capital program of approximately $295 million, excluding
acquisitions. The capital development program was increased by $75 million
during the second quarter of 2008 in conjunction with our Texas acquisition to a
total of $370 million. We may revise our capital budget during the
year as a result of acquisitions and/or drilling outcomes or significant changes
in cash flows. Excess cash generated from operations is expected to be
applied toward acquisitions, debt reduction or other corporate
purposes.
Our 2008
expenditures will be directed toward developing reserves, increasing oil and gas
production and exploration opportunities. For 2008, we plan to invest
approximately $118 million, or 32%, in our heavy crude oil assets, $175 million,
in our base natural gas and light oil assets and $75 million in the development
of our East Texas acquisition. Capital expenditures, excluding property
acquisitions, totaled $95 million and $172 million during the three and six
months ended June 30, 2008, respectively.
Working Capital
and Cash Flows. Cash flow from
operations is dependent upon the price of crude oil and natural gas and our
ability to increase production and manage costs. Crude oil and gas sales in the
three months ended June 30, 2008 were 13% higher than the three months ended
March 31, 2008 resulting from a 6% increase in oil prices (see graphs on page
14) and a 16% increase in gas prices (see graphs on page 14) and production
increases in oil and natural gas. Proceeds from the sale of our Prairie
Star assets are $1.8 million in the Statements of Cash Flows and the gain from
that sale is $.4 million in the Statements of Income in the six months ended
June 30, 2008.
Our
working capital balance fluctuates as a result of the amount of borrowings and
the timing of repayments under our credit arrangements. We use our long-term
borrowings under our credit facility primarily to fund property acquisitions.
Generally, we use excess cash to pay down borrowings under our credit
arrangement. As a result, we often have a working capital deficit or a
relatively small amount of positive working capital.
The table
below compares financial condition, liquidity and capital resources changes for
the three month periods ended (in millions, except for production and average
prices):
|
June
30, 2008
(2Q08)
|
June
30, 2007
(2Q07)
|
2Q08
to 2Q07 Change
|
March
31, 2008
(1Q08)
|
2Q08
to 1Q08 Change
|
Average
production (BOE/D)
|
29,000
|
27,195
|
7%
|
28,066
|
3%
|
Average
oil and gas sales prices, per BOE after hedging
|
$
69.77
|
$
45.43
|
54%
|
$
60.43
|
15%
|
Net
cash provided by operating activities (1)
|
$107
|
$
81
|
32%
|
$
87
|
23%
|
Working
capital
|
$
(225)
|
$
(39)
|
(464)%
|
$
(123)
|
(79)%
|
Sales
of oil and gas
|
$185
|
$113
|
64%
|
$ 164
|
13%
|
Total
debt
|
$511
|
$475
|
8%
|
$
455
|
12%
|
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
$154
|
$131
|
18%
|
$
77
|
100%
|
Dividends
paid
|
$3.4
|
$
3.4
|
-%
|
$
3.3
|
3%
|
(1)
|
The
change in the book overdraft line in the Statements of Cash Flows is
classified as an operating activity to reflect the use of these funds in
operations, rather than their prior year classification as a financing
activity.
|
Contractual
Obligations. Our contractual
obligations as of June 30, 2008 are as follows (in millions):
|
|
|
Total
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Thereafter
|
Total
debt and interest
|
|
$
|
687.4
|
$
|
14.3
|
$
|
28.5
|
$
|
28.6
|
$
|
333.5
|
$
|
16.5
|
$
|
266.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
lease obligations
|
|
|
17.0
|
|
1.2
|
|
2.2
|
|
2.1
|
|
2.1
|
|
2.1
|
|
7.3
|
Drilling
and rig obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
966.0
|
$
|
36.7
|
$
|
67.9
|
$
|
59.0
|
$
|
376.0
|
$
|
39.2
|
$
|
387.2
|
Drilling obligations
- Under our June 2006 joint venture agreement in the Piceance basin we are
required to have 120 wells drilled by February 2011 to avoid penalties of $.2
million per well or a maximum of $24 million. As of June 30, 2008 we have
drilled 23 of these wells and we expect to meet our obligation to have the
remaining wells drilled by February 2011.
Other Obligations -
We
adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of June 30, 2008, we had a gross
liability for uncertain tax benefits of $12.9 million of which $10.5 million, if
recognized, would affect the effective tax rate.
In
February 2007, we entered into a multi-staged crude oil sales contract with a
refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D in July 2007, as provided in our
contract. The refiner has increased its total purchase capacity to
5,000 Bbl/D as provided in our contract. The differential under the contract,
which includes transportation and gravity adjustments, is linked to WTI and
would range from $20 to $30 per barrel at WTI prices between $80 and
$120. Gross oil production averaged approximately 4,000 BOE/D in the
quarter ended June 30, 2008.
Item
3.
Quantitative
and Qualitative Disclosures About Market
Risk
|
As
discussed in Note 4 to the unaudited condensed financial statements, to minimize
the effect of a downturn in oil and gas prices and protect our profitability and
the economics of our development plans, we enter into crude oil and natural gas
hedge contracts from time to time. The terms of contracts depend on various
factors, including management's view of future crude oil and natural gas prices,
acquisition economics on purchased assets and our future financial commitments.
This price hedging program is designed to moderate the effects of a severe crude
oil and natural gas price downturn while allowing us to participate in some
commodity price increases. In California, we benefit from lower natural gas
pricing as we are a consumer of natural gas in our operations and elsewhere, we
benefit from higher natural gas pricing. We have hedged, and may hedge in the
future, both natural gas purchases and sales as determined appropriate by
management. Management regularly monitors the crude oil and natural gas markets
and our financial commitments to determine if, when, and at what level some form
of crude oil and/or natural gas hedging and/or basis adjustments or other price
protection is appropriate in accordance with policy established by our board of
directors.
Currently,
our hedges are in the form of swaps and collars. However, we may use a variety
of hedge instruments in the future to hedge WTI or the index gas price. We have
crude oil sales contracts in place which are priced based on a correlation to
WTI. Natural gas (for cogeneration and conventional steaming operations) is
purchased at the SoCal border price and we sell our produced gas in Colorado and
Utah at various index prices.
The
following table summarizes our hedge position as of June 30, 2008:
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Average
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Price
|
Crude
Oil Sales (NYMEX WTI) Collars
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO CIG) Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO PEPL) Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH)
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil Sales (NYMEX WTI) Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH)
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below our floor prices which
range from $47.50 to $80.00 per barrel while still participating in any oil
price increase up to the ceiling prices which range from $70.00 to $91.00 per
barrel on the volumes indicated above, and if 2) gas prices decline below
our floor prices which range from $7.50 to $8.00 per MMBtu while still
participating in any gas price increase up to the ceiling prices, which range
from $8.40 to $9.50 per MMBtu on the respective volumes. These hedges improve
our financial flexibility by locking in significant revenues and cash flow upon
a substantial decline in crude oil or natural gas prices, including certain
basis differentials. It also allows us to develop our long-lived assets and
pursue exploitation opportunities with greater confidence in the projected
economic outcomes and allows us to borrow a higher amount under our credit
facility.
While we
have designated our hedges as cash flow hedges in accordance with SFAS
No. 133, Accounting for
Derivative Instruments and Hedging Activities, it is possible that a
portion of the hedge related to the movement in the WTI to California heavy
crude oil price differential may be determined to be ineffective. Likewise, we
may have some ineffectiveness in our natural gas hedges due to the movement of
HH pricing as compared to actual sales points. If this occurs, the ineffective
portion will directly impact net income rather than being reported as Other
Comprehensive Income (Loss). If the differential were to change significantly,
it is possible that our hedges, when mark-to-market, could have a material
impact on earnings in any given quarter and, thus, add increased volatility to
our net income. The mark-to-market values reflect the liquidation values of such
hedges and not necessarily the values of the hedges if they are held to
maturity.
In November
2007 we entered into natural gas swaps at an index that did not correlate with
the index at which the gas is sold and therefore those 2008 gas hedges are not
highly effective. In January 2008 we entered into natural gas swaps which were
not highly effective at inception, so we subsequently entered into basis swaps
and established effectiveness at that time. Thus, we recognized unrealized net
losses of approximately $.1 million and $.8 million in the Statements of Income
under the caption “Commodity derivatives” for the three months ended June 30,
2008 and for the six months ended June 30, 2008,
respectively.
Additionally,
in 2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility. These interest rate swaps have been designated as cash flow
hedges.
The
related cash flow impact of all of our derivative activities are reflected as
cash flows from operating activities. Irrespective of the unrealized gains
reflected in Other Comprehensive Income (Loss), the ultimate impact to net
income over the life of the hedges will reflect the actual settlement values.
All of these hedges have historically been deemed to be cash flow hedges and are
booked at fair value.
Based on average NYMEX futures prices as of June 30, 2008 (WTI $139.01; HH $12.82) for the term of our hedges we would expect to make pretax future
cash payments or to receive payments over the remaining term of our crude oil
and natural gas hedges in place as follows:
|
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|
|
|
June
30, 2008
|
|
|
on
pretax future cash (payments) and receipts
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Futures Price (2008 – 2011)
|
|
$
|
139.01
|
|
$
|
111.21
|
|
$
|
125.11
|
|
$
|
152.91
|
|
$
|
166.82
|
|
Average
HH Futures Price (2008 – 2009)
|
|
|
12.82
|
|
|
10.26
|
|
|
11.55
|
|
|
14.11
|
|
|
15.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$
|
(604.8
|
)
|
$
|
(350.0
|
)
|
$
|
(477.4
|
)
|
$
|
(732.2
|
)
|
$
|
(859.6
|
)
|
Natural
Gas gain/(loss) (in millions)
|
|
|
(30.2
|
)
|
|
(10.1
|
)
|
|
(22.1
|
)
|
|
(46.1
|
)
|
|
(58.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
(WTI $140.73; HH $13.54)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
(WTI $140.88; HH $12.47)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181.9
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
2011
(WTI $136.79)
|
|
|
(4.6
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
|
|
)
|
Total
|
|
$
|
(635.0
|
)
|
$
|
|
)
|
$
|
|
)
|
$
|
|
)
|
$
|
|
)
|
Interest
Rates. Our
exposure to changes in interest rates results primarily from long-term debt. In
October 2006, we issued $200 million of 8.25% senior subordinated notes due 2016
in a public offering. Total long-term debt outstanding including our short-term
Line of Credit, at June 30, 2008 was $311 million. Interest on amounts
borrowed under our credit facility is charged at LIBOR plus 1.0% to 1.75%, with
the exception of the $100 million of principal for which we have hedged the
interest rate at approximately 5.5% plus the credit facility’s margin through
June 30, 2011. Based on June 30, 2008 credit facility borrowings, a 1% change in
interest rates would have an annual $1.3 million after tax impact
on our financial statements.
Item
4. Controls and
Procedures
|
As of
June 30, 2008, we have carried out an evaluation under the supervision of, and
with the participation of, our management, including our Chief Executive Officer
and Chief Financial Officer, of the effectiveness of the design and operation of
our disclosure controls and procedures pursuant to Rule 13a-15 under the
Securities Exchange Act of 1934, as amended.
Based on
their evaluation as of June 30, 2008, 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.
There was
no change in our internal control over financial reporting that occurred during
the three months ended June 30, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting. We may make changes in our internal control procedures from time to
time in the future.
Forward Looking
Statements
“Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-Q that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “plan,” “will,”
“intend,” “continue,” “target(s),” “expect,” “achieve,” “future,” “may,”
“could,” “goal(s),” “anticipate,” or other comparable words or phrases, or the
negative of those words, and other words of similar meaning indicate
forward-looking statements and important factors which could affect actual
results and will not complete such actions on the timetable indicated.
Forward-looking statements are made based on management’s current expectations
and beliefs concerning future developments and their potential effects upon
Berry Petroleum Company. These items are discussed at length in Part I, Item 1A
on page 14 of our Form 10-K/A 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.
PART II. OTHER
INFORMATION
|
Item
1. Legal
Proceedings
|
None.
None.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
None.
Item
3. Defaults Upon Senior
Securities
|
None.
Item 4. Submission of Matters to a Vote
of Security Holders
|
At the
annual meeting, which was held at the Four Points Sheraton Hotel, Bakersfield,
California, on May 14, 2008, ten incumbent directors were re-elected. The
results of voting as reported by the inspector of elections are noted
below:
1. There
were 44,408,401 shares of our capital stock issued, outstanding and generally
entitled to vote as of the record date, March 17, 2008.
2. There
were present at the meeting, in person or by proxy, the holders of 41,055,321
shares, representing 92.45% of the total number of shares outstanding and
entitled to vote at the meeting, such percentage representing a
quorum.
PROPOSAL
ONE: Election of ten Directors
|
|
|
|
|
NOMINEE
|
|
VOTES
CAST
FOR
|
PERCENTAGE
OF QUORUM VOTES CAST
|
AUTHORITY
WITHHELD
|
Joseph
H. Bryant
|
|
40,792,588
|
99.36%
|
262,733
|
Ralph
B. Busch, III
|
|
40,623,215
|
98.95%
|
432,106
|
William
E. Bush, Jr
|
|
40,615,502
|
98.93%
|
439,819
|
Stephen
L. Cropper
|
|
40,894,899
|
99.61%
|
160,422
|
J.
Herbert Gaul, Jr.
|
|
40,894,023
|
99.61%
|
161,298
|
Robert
F. Heinemann
|
|
40,610,077
|
98.92%
|
445,244
|
Thomas
J. Jamieson
|
|
40,615,672
|
98.93%
|
439,649
|
J.
Frank Keller
|
|
40,790,643
|
99.36%
|
264,678
|
Ronald
J. Robinson
|
|
40,793,243
|
99.36%
|
262,078
|
Martin
H. Young, Jr
|
|
40,901,003
|
99.62%
|
154,318
|
|
Percentages
are based on the shares represented and voting at the meeting in person or
by proxy.
PROPOSAL
TWO: Ratification of the appointment of PricewaterhouseCoopers LLP as the
Independent Registered Public Accounting Firm (Independent
Auditors).
|
|
For
|
Against
|
Abstentions
|
Broker
Non-Votes
|
Shares
|
40,705,860
|
348,595
|
866
|
-
|
Item
5. Other
Information
|
None.
Exhibit
No. Description of
Exhibit
10.1
Amended and Restated Credit Agreement, dated as of July 15, 2008 by
and between the Registrant and Wells
Fargo
Bank, N.A. and other financial institutions.
10.2
|
Purchase
and Sale Agreement Between O’Brien Resources, LLC, Sepco II, LLC, Liberty
Energy, LLC, Crow Horizons Company and O’Benco II LP collectively as
Seller and Berry Petroleum Company as Purchaser, dated as of June 10,
2008.
|
10.3
|
Overriding
Royalty Purchase Agreement between O’Brien Resources, LLC, as Seller, and
Berry Petroleum Company, as Purchaser, dated as of June 10,
2008.
|
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.
|
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
BERRY
PETROLEUM COMPANY
/s/ Shawn
M. Canaday
Shawn M.
Canaday
Vice
President and Controller
(Principal
Accounting Officer)
Date: July
25, 2008