UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x
Annual
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
fiscal year ended
December 31, 2005
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
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DELAWARE
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77-0079387
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(State
of incorporation or organization)
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(I.R.S.
Employer Identification Number)
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5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code: (661)
616-3900
Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Class
A Common Stock, $.01 par value
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New
York Stock Exchange
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(including
associated stock purchase rights)
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Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
YES
x
NO
o
Indicate
by check mark if the registrant is not required to file reports pursuant
to
Section 13 or Section 15(d) of the Act.
YES
o
NO
x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. YES
x
NO
o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment
to this
Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filerx Accelerated
filero Non-accelerated
filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES
o
NO
x
As
of
June 30, 2005, the aggregate market value of the voting and non-voting common
stock held by non-affiliates was $962,312,197. As of February 10, 2006, the
registrant had 21,077,915 shares of Class A Common Stock outstanding. The
registrant also had 898,892 shares of Class B Stock outstanding on February
10,
2006 all of which is held by an affiliate of the registrant.
DOCUMENTS
INCORPORATED BY REFERENCE
Part
III
is incorporated by reference from the registrant's definitive Proxy Statement
for its Annual Meeting of Shareholders to be filed, pursuant to Regulation
14A,
no later than 120 days after the close of the registrant's fiscal
year.
BERRY
PETROLEUM COMPANY
PART
I
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Page
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Business
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3
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General
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3
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Crude
Oil and Natural Gas Marketing
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4
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Steaming
Operations
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6
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Electricity
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7
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Competition
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8
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Employees
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8
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Oil
and Gas Properties
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8
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Capital
Expenditures
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12
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Production
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13
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Acreage
and Wells
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13
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Drilling
Activity
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14
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Environmental
and Other Regulations
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14
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Forward
Looking Statements
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15
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Risk
Factors
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16
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Unresolved
Staff Comments
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21
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Properties
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21
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Legal
Proceedings
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21
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Submission
of Matters to a Vote of Security Holders
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21
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Executive
Officers
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21
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PART
II
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Market
for the Registrant's Common Equity and Related Shareholder Matters
and
Issuer Purchases of Equity Securities
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22
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Selected
Financial Data
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24
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Management's
Discussion and Analysis of Financial Condition and Results of
Operations
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26
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Quantitative
and Qualitative Disclosures About Market Risk
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39
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Financial
Statements and Supplementary Data
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41
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
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67
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Controls
and Procedures
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67
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Other
Information
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68
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PART
III
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Directors
and Executive Officers of the Registrant
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69
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Executive
Compensation
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69
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
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69
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Certain
Relationships and Related Transactions
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69
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Principal
Accounting Fees and Services
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69
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PART
IV
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Exhibits,
Financial Statement Schedules
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69
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PART
I
General. Berry
Petroleum Company, (Berry or Company), is an independent energy company engaged
in the production, development, acquisition, exploitation and exploration
of
crude oil and natural gas. While the Company was incorporated in Delaware
in
1985 and has been a publicly traded company since 1987, it can trace its
roots
in California oil production back to 1909. Currently, Berry's principal reserves
and producing properties are located in California, Utah and Colorado. The
Company has its corporate headquarters in Bakersfield, California and a regional
office in Denver, Colorado. The Company is increasing office space in both
locations to accommodate growth. Information contained in this report on
Form
10-K reflects the business of the Company during the year ended December
31,
2005 unless noted otherwise.
The
Company’s website is located at http://www.bry.com.
The
website can be used to access recent news releases and Securities and Exchange
Commission (SEC) filings, crude oil price postings, the Company’s Annual Report,
Proxy Statement, Board committee charters, code of business conduct and ethics,
the code of ethics for senior financial officers, and other items of interest.
SEC filings, including supplemental schedules and exhibits, can also be accessed
free of charge through the SEC website at http://www.sec.gov.
Corporate
Strategy.
Berry
Petroleum Company’s mission is to increase shareholder value, primarily through
increasing the net asset value, and maximizing the cash flow and earnings
of the
Company's assets. The strategies to accomplish these goals include:
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Growing
production and reserves from existing assets while managing
expenses
-
The Company intends to increase production and reserves annually
and
increase both net income and cash flow in total and per share.
The Company
will continue to focus on the further development of its properties
through developmental drilling, down-spacing, well completions,
remedial
work and by application of enhanced oil recovery (EOR) methods,
and
optimization technologies, as applicable. With respect to the California
heavy oil reserves, the Company owns three cogeneration facilities
which
are intended to provide an efficient and secure long-term supply
of steam
necessary for the economic production of heavy oil.
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Acquiring
more light oil and natural gas assets with significant growth potential
in
the Rocky Mountain and Mid-Continent region -
The Company will compete to acquire oil and gas properties with
proved
reserves, probable reserves and/or sizeable acreage positions that
the
Company believes contain substantial reserves which can be developed
at
reasonable costs. As part of its resource diversification strategy,
Berry
desires to add natural gas production and reserves to complement
its
significant crude oil resource base. The Company has identified
the Rocky
Mountain and Mid-Continent region as its primary areas of interest
for
diversification.
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Appraising
the Company’s exploitation and exploration projects in an expedient manner
- The
Company has been successful in adding significant acreage positions
in the
last two years with the intent of drilling exploration wells to
test the
potential of the acreage for the economic production of hydrocarbons.
Its
goal is to appraise this potential as quickly as is prudently
possible.
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Investing
the Company’s capital in an efficient, disciplined manner
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Investing the Company’s capital prudently is of paramount importance in
achieving long-term success. The oil and gas business is very capital
intensive so managing the business with a focus on utilizing the
available
capital on projects where it is likely to have success in increasing
production and/or reserves at attractive returns to shareholders.
A
portion of the Company’s capital will be directed to higher risk projects
that have the potential for higher
reward.
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Utilizing
joint ventures with respected partners to enter new basins -
The
Company believes that it is beneficial to utilize the skills and
knowledge
of other industry participants upon entering new basins or areas
of
operations as it can reduce the risk and improve the success in
the
area.
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Berry
has
the industry talent, experience, organization and motivation to accomplish
the
above strategies to fulfill its mission of increasing shareholder value.
Berry
also has the financial capacity and skill sets to accomplish these strategies.
In addition to internally generated funds, it has a $500 million unsecured
credit facility with a current borrowing base of $350 million which may be
utilized in adding prospective acreage, reserves and/or production through
acquisitions.
Proved
Reserves and Revenues. As
of
December 31, 2005, the Company's estimated proved reserves were 126 million
barrels of oil equivalent, (BOE), of which 74% are heavy crude oil, 8% light
crude oil and 18% natural gas. Nearly 40% of reserves are owned in fee.
Geographically, 74% of the Company’s reserves are located in California and 26%
in the Rocky Mountain and Mid-Continent region. Proved undeveloped reserves
make
up 28% of the Company's proved total. The projected capital to develop these
proved undeveloped reserves is $201million, at an estimated cost of
approximately $5.54 per BOE. Approximately 77% of the capital to develop
these
reserves is expected to be expended in the next five years. Production in
2005
was 8.4 million BOE, up 12% from production of 7.5 million BOE in 2004. The
Company’s reserves-to-production ratio was unchanged at 14.6 years at year-end
2005, compared to year-end 2004.
The
following table depicts all of the Company’s producing assets as of December 31,
2005. Berry operates all of the assets, except Wyoming:
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State
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Name
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Type
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Daily
Production (BOE/D)
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%
of Daily Production
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Proved
Reserves (BOE) in thousands
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%
of Proved Reserves
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Oil
& Gas Revenues before hedging (in millions)
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%
of Oil & Gas Revenues
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CA
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Midway-Sunset
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Heavy
oil
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12,214
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53%
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68,071
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54%
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$
199
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50%
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UT
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Brundage
Canyon
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Light
oil/Natural gas
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5,079
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22
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15,116
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12
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98
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25
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CA
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Placerita
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Heavy
oil
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2,654
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12
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16,592
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13
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48
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12
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CO
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Tri-State
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Natural
gas
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1,600
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7
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17,442
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14
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26
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7
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CA
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Montalvo
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Heavy
oil
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728
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3
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6,869
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5
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12
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3
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CA
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Poso
Creek
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Heavy
oil
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544
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2
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2,046
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2
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10
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3
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WY/CA
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Various
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Various
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196
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1
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149
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-
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2
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-
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Totals
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23,015
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100%
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126,285
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100%
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$
395
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100%
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The
Company continued to engage DeGolyer and MacNaughton (D&M) to appraise the
extent and value of its proved oil and gas reserves and the future net revenues
to be derived from properties of the Company for the year ended December
31,
2005. D&M is an independent oil and gas consulting firm located in Dallas,
Texas. In preparing their reports, D&M reviewed and examined geologic,
economic, engineering and other data considered applicable to properly determine
the reserves of the Company. They also examined the reasonableness of certain
economic assumptions regarding forecasted operating and development costs
and
recovery rates in light of the economic environment on December 31, 2005.
See
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
for the Company's oil and gas reserve disclosures.
Acquisitions.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
Operations.
In
California, Berry operates all of its principal oil and gas producing
properties. The Midway-Sunset, Placerita and Poso Creek fields contain
predominantly heavy crude oil which requires heat, supplied in the form of
steam, injected into the oil producing formations to reduce the oil viscosity
which allows the oil to flow to the wellbore for production. Berry utilizes
cyclic steam and/or steam flood recovery methods in all of these fields in
addition to primary recovery methods at its Montalvo field. Berry is able
to
produce its heavy oil at its Montalvo field without steam since the majority
of
the producing reservoir is at a depth in excess of 11,000 feet and the reservoir
temperature is high enough to produce the oil without the assistance of
additional heat from steam. Field operations related to oil production include
the initial recovery of the crude oil and its transport through treating
facilities into storage tanks. After the treating process is completed, which
includes removal of water and solids by mechanical, thermal and chemical
processes, the crude oil is metered through automatic custody transfer units
or
gauged before sale and subsequently transferred into crude oil pipelines
owned by other companies or transported via truck.
In
the
Rocky Mountain and Mid-Continent region, crude oil produced from the Brundage
Canyon field is transported by truck, while its gas production, net of field
usage, is transported by gathering or distribution systems to the Questar
Pipeline. Natural gas produced from the eastern Colorado Niobrara gas assets
is
transported by Company and third party gathering lines to one of two main
pipelines. The Company has a pipeline gathering system and gas compression
facilities for delivery into these two interstate gas lines in this
region.
Crude
Oil and Natural Gas Marketing
Economy.
The
global and California crude oil markets continue to remain strong. Product
prices continued to exhibit an overall-strengthening trend through 2005.
The
range of West Texas Intermediate (WTI) crude prices for 2005, based upon
NYMEX
settlements, was a low of $42.12 and a high of $69.81. The Company expects
that
crude prices will continue to be volatile in 2006.
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2005
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2004
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2003
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Average
NYMEX settlement price for WTI
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$
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56.70
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$
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41.47
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$
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30.99
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Average
posted price for Berry’s:
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Utah
light crude oil
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53.03
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38.60
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27.63
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California
13 degree API heavy crude oil
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44.36
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32.84
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25.33
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Average
crude price differential between WTI and Berry’s:
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Utah
light crude oil
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3.67
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2.87
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3.36
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California
13 degree API heavy crude oil
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12.34
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8.63
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5.66
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The
above
posting prices and differentials are not necessarily amounts paid or received
by
the Company due to the contracts discussed below. While the crude oil price
differential between WTI and California’s heavy crude was fairly consistent with
historical averages in 2003 at just under $6.00 per barrel, the
differential widened dramatically during 2004 and 2005. On December 31, 2005
the
differential was $11.61 and ranged from a low of $10.27 to a high of $14.83
per
barrel during the year. Crude oil price differentials between WTI and Utah’s
light crude oil were fairly consistent during 2003, 2004 and 2005 and were
between $3 and $5 per barrel. On December 31, 2005 the differential was $4.67
and ranged from a low of $3.73 to a high of $4.77 per barrel during the year.
Oil
Contracts. Berry
markets its crude oil production to competing buyers including independent
and
major oil refining companies. Because of the Company’s ability to deliver
significant volumes of crude oil over a multi-year period, the Company secured
a
three-year sales agreement, beginning in late 2002, with a major oil company
whereby the Company sold over 90% of its California production under a
negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing
in this agreement was based upon the higher of the average of the local field
posted prices plus a fixed premium, or WTI minus a fixed differential near
$6.00
per barrel. This contract allowed the Company to improve its California revenues
over the posted price by approximately $41 million and $13 million in 2005
and
2004, respectively.
On
November 21, 2005, the Company entered into a new crude oil sales contract
for
its California production for deliveries beginning February 1, 2006 and ending
January 31, 2010. The per barrel price, calculated on a monthly basis and
blended across the various producing locations, is the higher of 1) the WTI
NYMEX crude oil price less a fixed differential approximating $8.15, or 2)
heavy
oil field postings plus a premium of approximately $1.35. The initial term
of
the contract is for four years with a one-year renewal at the Company’s option.
The agreement effectively eliminates the Company’s exposure to the risk of a
widening WTI to California heavy crude price differential over the next four
years and allows the Company to effectively hedge its production based on
WTI
pricing similar to the previous contract. If this contract had been in place
during 2005, it would have allowed the Company to improve its California
revenues over the posted prices by approximately $25 million in 2005, but
$16
million below what was actually received by the Company under the contract
in
place in 2005.
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. The Company believes the differential
has
widened by several dollars per barrel. The majority of this crude oil, while
light, is a “paraffinic” crude, and can be processed efficiently by only a
limited number of stranded inland refineries. The production of this type
crude is increasing regionally and beginning to strain the capacity of these
refineries. Other new crude sources from the region are pressuring pricing.
If
these refineries limit the volumes of this parraffinic crude oil they are
willing to process, it could impact the marketability of this type of crude
which, for Berry, represents approximately 3,500 Bbl/D of production or
approximately 15% of total current production. The Company is investigating
its
market opportunities for this crude oil. If market prices continue to
deteriorate,
the
Company may allocate its capital expenditures to projects which produce natural
gas and crude oils with lower paraffinic content until the refinery constraint
is resolved.
Natural
Gas Marketing. Berry
markets produced natural gas from Colorado, Utah, Wyoming and
California. Generally, natural gas is sold at monthly index related prices
plus an adjustment for transportation. Certain volumes are sold at a daily
spot
related price.
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2005
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2004
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2003
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Annual
average closing price per MMBtu for:
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NYMEX
Henry Hub (HH) prompt month natural gas contract
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$
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9.01
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$
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6.18
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$
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5.84
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Rocky
Mountain Questar first-of-month indices (Brundage Canyon
sales)
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6.73
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5.05
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4.00
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Rocky
Mountain CIG first-of-month indices (Tri-State sales)
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6.95
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5.17
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4.04
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Average
natural gas price per MMBtu differential between NYMEX HH
and:
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||||||||||
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Questar
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2.28
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1.13
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1.84
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CIG
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2.06
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1.01
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1.80
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The
Company has physical access to interstate gas pipelines to move gas to or
from
market. To assure delivery of gas, the Company has entered into several
long-term gas transportation contracts as follows:
Firm
Transportation Summary
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Name
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From
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To
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Quantity
(Avg. MMBtu/D)
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Term
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2005
base costs per MMBtu
|
Remaining
contractual obligation (in thousands)
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|||||||||||||
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Kern
River Pipeline
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Opal,
WY
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Kern
County, CA
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12,000
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5/2003
to 4/2013
|
$
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.6425
|
$
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20,640
|
|||||||||||
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Questar
Pipeline
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Brundage
Canyon
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Salt
Lake City, UT
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2,500
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9/2003
to 4/2007
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.1739
|
211
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|||||||||||||
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Questar
Pipeline
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Brundage
Canyon
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Salt
Lake City, UT
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2,800
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9/2003
to 9/2007
|
.1739
|
317
|
|||||||||||||
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KMIGT
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Yuma
County, CO
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Grant,
KS
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2,500
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1/2005
to 10/2013
|
.2270
|
1,624
|
|||||||||||||
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Cheyenne
Plains Gas Pipeline
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Tri-State,
CO
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Panhandle
Eastern Pipeline
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11,000
|
(Est.)
Q4 2006 to Q4 2016
|
.3400
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13,662
|
|||||||||||||
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Total
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30,800
|
$
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36,454
|
||||||||||||||||
Royalties.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Concentration
of Credit Risk. See
Note
4 to the financial statements.
Steaming
Operations
Cogeneration
Steam Supply. As
of
December 31, 2005, approximately 74% of the Company's proved reserves, or
93
million barrels, consisted of heavy crude oil produced from depths of less
than
2,000 feet. The Company, in pursuing its goal of being a cost-efficient heavy
oil producer in California, has remained focused on minimizing its steam
cost.
One of the main methods of keeping steam costs low is through the ownership
and
efficient operation of cogeneration facilities. Two of these cogeneration
facilities, a 38 megawatt (MW) and an 18 MW facility are located in the
Company’s Midway-Sunset field. The Company also owns a 42 MW cogeneration
facility which is located in the Placerita field. Steam generation from these
cogeneration facilities is more efficient than conventional steam generation
as
both steam and electricity are concurrently produced from a common fuel stream.
By maintaining a correlation between electricity and natural gas prices,
the
Company is able to better control its cost of producing steam.
Conventional
Steam Generation. In
addition to these cogeneration plants, the Company owns 16 conventional boilers.
The quantity of boilers operated at any point in time is dependent on 1)
the
steam volume required for the Company to achieve its targeted production
and 2)
the price of natural gas compared to the price of crude oil sold.
Total
barrels of steam per day (BSPD) capacity as of December 31, 2005 is as
follows:
|
Total
steam generation capacity of Cogeneration plants
|
38,000
|
|||
|
Additional
steam purchased under contract with third party
|
2,000
|
|||
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Total
steam generation capacity of conventional boilers
|
43,000
|
|||
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Total
steam capacity
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83,000
|
The
average volume of steam injected for the years ended December 31, 2005 and
2004
was 70,032 and 69,200 BSPD, respectively.
Ownership
of these varied steam generation facilities and sources allows for maximum
operational control over the steam supply, location, and to some extent control
over the aggregated cost of steam generation. The Company’s steam supply and
flexibility are crucial for the maximization of California thermally enhanced
heavy oil production, cost control and ultimate reserve recovery.
The
Company believes that it may become necessary to add additional steam capacity
for its future development projects at Midway-Sunset and Poso Creek to allow
for
full development of its properties. The Company regularly reviews its most
economical source for obtaining additional steam to achieve its growth
objectives.
Most
of
the Company’s conventional steam generators operated in 2005 to achieve the
Company’s goal of increasing heavy oil production to record levels.
Approximately 70% of the volume of natural gas purchased to generate steam
and
electricity is based upon SoCal Border indices. While there are no
transportation charges for gas purchased at the SoCal Border location, all
locations except the central portion of the Midway-Sunset field pay
distribution/transportation charges to either SoCal Gas or Pacific Gas &
Electric
(PG&E) to have the gas delivered to the field. The remaining 30% of supply
volume is purchased in Wyoming and moved to the Midway-Sunset field using
the
Company’s firm transport on the Kern River Pipeline. This gas is purchased based
upon the Rocky Mountain Northwest Pipeline (NWPL) index.
|
|
|
2005
|
|
2004
|
|
2003
|
|||
|
Average
SoCal Border Monthly Index Price per MMBtu
|
|
$
|
7.37
|
|
$
|
5.60
|
$
|
5.00
|
|
|
Average
Rocky Mountain NWPL Monthly Index Price per MMBtu (*contract began
May
2003)
|
6.96
|
5.24
|
4.34*
|
||||||
The
Company historically was a net purchaser of natural gas and thus its net
income
was negatively impacted when natural gas prices rose higher than its oil
equivalent. In 2005, due to its eastern Colorado Niobrara gas acquisition,
the
Company on a gas balance basis achieved parity. Thus, going forward, the
Company
is a net seller of gas and operationally should benefit when gas prices are
higher. The balance between natural gas (MMBtu/D) consumed and produced during
the month of December 2005 was approximately as follows:
|
Natural
gas consumed in:
|
|||
|
Cogeneration
operations
|
27,000
|
||
|
Conventional
boilers
|
11,000
|
||
|
Total
natural gas consumed
|
38,000
|
||
|
Less:
Company’s estimate of approximate natural gas consumed to produce
electricity (1)
|
(20,000)
|
||
|
Total
approximate natural gas volumes consumed to produce steam
|
18,000
|
||
|
Natural
gas produced:
|
|||
|
Tri-State
(Niobrara)
|
11,900
|
||
|
Brundage
Canyon (associated gas)
|
11,400
|
||
|
Other
|
1,700
|
||
|
Total
natural gas volumes produced in operations
|
25,000
|
(1)
The Company estimates this volume based on electricity revenues divided by
the
purchase price, including transportation, per MMBtu for the respective
period.
Electricity.
Generation.
The
total
annual average electrical generation of the Company’s three cogeneration
facilities is approximately 93 megawatts (MW), of which the Company consumes
approximately 8 MW for use in its operations. Each facility is centrally
located
on an oil producing property such that the steam generated by the facility
is
capable of being delivered to the wells that require steam for the enhanced
oil
recovery process. The Company’s investment in its cogeneration facilities has
been for the express purpose of lowering the steam costs in its heavy oil
operations and securing operating control of the respective steam generation.
Expenses of operating the cogeneration plants are analyzed regularly to
determine whether they are advantageous versus conventional steam boilers.
Cogeneration costs are allocated between electricity generation and oil and
gas
operations based on the conversion efficiency (of fuel to electricity and
steam)
of each cogeneration facility and certain direct costs to produce steam.
Cogeneration costs allocated to electricity will vary based on, among other
factors, the thermal efficiency of the Company's cogeneration plants, the
price
of natural gas used for fuel in generating electricity and steam, and the
terms
of the Company's power contracts. The Company views any profit or loss from
the
generation of electricity as a decrease or increase, respectively, to its
total
cost of producing its heavy oil in California. DD&A related to the Company's
cogeneration facilities is allocated between electricity operations and oil
and
gas operations using a similar allocation method.
Sales
Contracts. Historically,
the Company has sold electricity produced by its cogeneration facilities
to two
California public utilities, Southern California Edison Company (Edison)
and
PG&E, under long-term contracts. These contracts are referred to as Standard
Offer (SO) contracts under which the Company is paid an energy payment that
reflects the utility’s Short Run Avoided Cost (SRAC) plus a capacity payment
that reflects a recovery of capital expenditures that would otherwise have
been
made by the utility. An SO2 contract is more beneficial as it receives a
higher
capacity payment than an SO1 contract. The SRAC energy price is currently
determined by a formula that reflects the utility’s marginal fuel cost and a
conversion efficiency that represents a hypothetical resource to generate
electricity in the absence of the cogenerator. During most periods natural
gas
is the marginal fuel for California utilities so this formula provides a
hedge
against the Company’s cost of gas to produce electricity and steam in its
cogeneration facilities. A proceeding is now underway at the California Public
Utilities Commission (CPUC) to review and revise the methodology used to
determine SRAC energy prices. This proceeding is currently scheduled to be
completed by the third quarter of 2006. There is no assurance that any new
methodology will continue to provide a hedge against the Company’s fuel cost or
that a revised pricing mechanism will be as beneficial as the current contract
pricing.
The
original SO contract for Placerita Unit 1 continues in effect through March
2009, which makes up approximately 17% of total approximate barrels of steam
per
day. The modified SRAC pricing terms of this contract reflect a fixed energy
price of 5.37 cents/kilowatt hour (KWh) through June 2006, at which time
the
energy price reverts to the SRAC pricing methodology. The Company will be
paid a
reduced capacity payment that is fixed through the term of the contract.
In
December 2004, the Company executed a five-year SO contract with Edison for
the
Placerita Unit 2 facility, and five-year SO contracts with PG&E for the
Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant
to
these contracts, the Company is paid the purchasing utility’s SRAC energy price
and a capacity payment that is subject to adjustment from time to time by
the
CPUC. Edison and PG&E challenged, in the California Court of Appeals, the
legality of the CPUC decision that ordered the utilities to enter into these
five-year SO contracts, and similar one-year SO contracts that were ordered
for
2004. The Court ruled that the CPUC had the right to order the utilities
to
execute these contracts. The Court also ruled that the CPUC was obligated
to
review the prices paid under the contracts and to retroactively adjust the
prices to the extent it was later determined that such prices did not comply
with the requirements of the Public Utilities Regulatory Policy Act of 1978,
as
amended (PURPA).
The
Company believes that Qualifying Facilities (QF), such as the Company's
facilities, provide an important source of distributive power generation
into
California's electricity grid, and as such, that the Company's facilities
will
be economic to operate for at least the current five-year contract term.
Based
on the current pricing mechanism for its electricity under the contracts
(which
includes electricity purchased for internal use), the Company expects that
its
electricity revenues will be in the $50 million to $60 million range for
2006.
Facility
and Contract Summary
|
Location
and Facility
|
Type
of Contract
|
Purchaser
|
Contract
Expiration
|
Approximate
Megawatts Available for Sale
|
Approximate
Megawatts Consumed in Operations
|
Approximate
Barrels of Steam Per Day
|
|
Placerita
|
|
|
|
|
|
|
|
Placerita
Unit 1
|
SO2
|
Edison
|
Jun-06
(1)
|
20
|
-
|
6,600
|
|
Placerita
Unit 2
|
SO1
|
Edison
|
Dec-09
|
16
|
4
|
6,700
|
|
|
|
|
|
|
|
|
|
Midway-Sunset
|
|
|
|
|
|
|
|
Cogen
18
|
SO1
|
PG&E
|
Dec-09
|
12
|
4
|
6,600
|
|
Cogen
38
|
SO1
|
PG&E
|
Dec-09
|
37
|
-
|
18,000
|
(1)
After expiration at June 2006, the contract will convert to SO1 through its
expiration at March 2009.
Competition. The
oil
and gas industry is highly competitive. As an independent producer, the Company
does not own any refining or retail outlets and, therefore, it has little
control over the price it receives for its crude oil. As such, higher costs,
fees and taxes assessed at the producer level cannot necessarily be passed
on to
the Company's customers. In acquisition activities, significant competition
exists as integrated and independent companies and individual producers are
active bidders for desirable oil and gas properties and prospective acreage.
Although many of these competitors have greater financial and other resources
than the Company, Management believes that Berry is in a position to compete
effectively due to its efficient operating cost structure, transaction
flexibility, strong financial position, experience and
determination.
Employees. On
December 31, 2005, the Company had 209 full-time employees, up from 156
full-time employees on December 31, 2004.
Berry’s
Net Oil and Gas Producing Properties at December 31,
2005.
|
Name
|
%
Average Working Interest
|
Total
Net Acres
|
Proved
Reserves (BOE) in thousands
|
Proved
Developed Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Proved
Undeveloped Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Average
Depth of Producing Reservoir (feet)
|
|
Midway-Sunset,
CA
|
99
|
4,836
|
68,071
|
60,627
|
48%
|
7,443
|
6%
|
1,200
|
|
Brundage
Canyon, UT
|
100
|
45,420
|
15,116
|
8,554
|
7
|
6,561
|
5
|
6,000
|
|
Placerita,
CA
|
100
|
965
|
16,592
|
7,462
|
6
|
9,130
|
7
|
1,800
|
|
Tri-State,
CO/KS/NE
|
50
|
315,473
|
17,442
|
8,411
|
7
|
9,031
|
7
|
2,600
|
|
Montalvo,
CA
|
100
|
8,563
|
6,869
|
2,811
|
2
|
4,059
|
3
|
11,500
|
|
Poso
Creek, CA
|
100
|
680
|
2,046
|
2,046
|
2
|
-
|
-
|
1,200
|
|
Various
|
15
|
815
|
149
|
150
|
-
|
-
|
-
|
various
|
|
Totals
|
376,752
|
126,285
|
90,061
|
72%
|
36,224
|
28%
|
San
Joaquin Valley Basin
Midway-Sunset,
California
- Berry
owns and operates working interests in 38 properties, including 23 owned
in fee,
in the Midway-Sunset field. Production from this field relies on thermal
enhanced oil recovery (EOR) methods, primarily cyclic steaming.
2005
-
Development activities at Midway-Sunset continued to be focused on horizontal
drilling to improve ultimate recovery of original oil-in-place, reduce the
development and operating costs of properties and to accelerate production.
2006
-
Capital of $40 million ($15 million for development and $25 million for
exploration/appraisal) is directed to 1) development - maximizing the recovery
from horizontal wells, improving steam efficiency and expanding two steam
flood
projects and 2) exploration/appraisal - expanding of the Diatomite project
which
includes up to 50 wells and related facilities.
Poso
Creek, California
- Berry
acquired these properties beginning in 2003 and is evaluating the potential
for
thermal EOR.
2005
-
The Company initiated a steam flood on the property.
2006
-
Capital of $5 million is directed at drilling infill wells and, upon success,
expanding the steam flood area.
Los
Angeles Basin
Placerita,
California -
Berry
owns and operates working interests in 13 properties, including 9 leases
and 4
fee properties, in the Placerita field. Production relies on thermal recovery
methods, primarily steam flooding.
2005
-
Began
major recompletion effort in mature steam flood and drilled 10 wells on northern
acreage.
2006
-
Capital of $8 million is directed at converting northern leases to steam
flood,
expanding another steam flood project and focusing on utilizing optimization
technology to improve recovery.
Ventura
Basin
Montalvo,
California -
Berry
owns 6 leases in the Ventura Basin comprising the entire Montalvo field.
The
State of California is the lessor for 2 of these leases. The wells produce
heavy
oil and due to the depth of the reservoir, steam injection is not necessary.
2005
-
Berry
performed several well recompletions.
2006
-
Capital of $8 million is directed at testing the western Sespe reservoir
through
additional drilling and adding production in the Colonia zone.
Uinta
Basin
Brundage
Canyon, Utah - The
Brundage Canyon leasehold in Duchesne County, northeastern Utah consists
of
federal, tribal and private leases.
2005
-
The
Company continued its focus on development of the Brundage Canyon property,
drilling 53 wells including 33 infill wells to validate 40-acre spacing.
2006
-
Capital of $58 million is directed at continuing the development of the Green
River formation, including testing 20-acre infills.
Lake
Canyon Prospect, Utah -
The
Company holds, with an industry partner, a 169,000 gross acre block which
is
located immediately west of the Company’s Brundage Canyon producing properties.
The Company will drill and operate the shallow wells which target light oil
and
natural gas in the Green River formation and retain up to a 75% working
interest. The Company's partner will drill and operate the deep wells which
target natural gas in the Mesaverde and Wasatch formations. Berry will hold
up
to a 25% working interest in these deep wells. The Ute Tribe has the option
to
participate in each well and obtain a 25% working interest which would reduce
the Company’s and its partner’s participation. The Ute Tribe did participate in
the first two shallow Green River wells.
2005
-
The
Company drilled 2 shallow Green River oil and gas wells and participated
in a 57
square mile 3-D seismic survey. In October 2005, the Company’s partner began
drilling a deep Mesaverde gas test well that reached targeted depth of 14,500
feet in December. This deep well is being evaluated. In January 2006, the
Company announced that its 2 shallow wells have commercial quantities of
oil and
gas.
2006
-
Capital of $4 million is directed at an additional 4 shallow wells and
participation in deep Mesaverde tests. Upon further success with the shallow
wells, the Company will accelerate development and capital on this
project.
Coyote
Flats Prospect, Utah -
In
December 2004, the Company entered into a development agreement with an industry
partner to develop their Coyote Flats prospect. The property is located
approximately 45 miles southwest of the Company’s Brundage Canyon property. The
Company is obligated to drill four test wells into the Ferron sand to a depth
of
approximately 7,500 feet and also drill a five well Emery coalbed methane
(CBM)
pilot, found at approximately 4,500 feet. Upon the completion of this total
nine
well drilling program, the Company will earn a 50% working interest in the
approximately 69,250 gross (33,500 net) acres. The Company expects to complete
this nine well drilling program in 2006.
2005
-
The
Company has drilled 3 Ferron sand test wells in 2005, one of which was a
dry
hole. The Company began its CBM development with 1 well drilled.
2006
-
Capital of $5 million is directed at fulfilling Berry’s obligation wells, which
consists of four CBM wells and one Ferron well. A gas pipeline is also planned
to tie in gas production for sale in mid-summer.
Big
Wash Unit, Utah
- The
Company, and an industry partner, owns working interest in 3 acreage blocks,
the
largest being the Big Wash Unit, which is located one mile southeast of Brundage
Canyon.
2005
-
Participated in one deep Mesaverde test in 2005, and the well (net working
interest to Berry of 16%) is an economic producer.
2006
-
Capital of $2 million is directed at participating in one exploratory gas
well
in the deep Mesaverde and one exploratory oil well in the shallow Green River
formation.
Denver-Julesburg
Basin
Tri-State
Area (includes eastern Colorado producing assets) -
This
area is comprised of the following three acquisitions during 2005 totaling
approximately 315,000 net acres, including approximately 100,000 net acres
of
producing acreage:
| · |
Niobrara
gas producing assets in Yuma County in northeastern Colorado in
which the
Company has approximately 52% working interest.
|
| · |
Eastern
Colorado, western Kansas and southwestern Nebraska in which the
Company
has approximately 50% working interest. The Company’s joint venture (JV)
will apply seismic technologies to explore and, if successful,
develop the
Niobrara formation for gas and Sharon Springs shale gas, which
lies at
less than 2,000 feet, and apply seismic technologies to evaluate
oil
potential in the Pennsylvanian formations at depths of 4,000 feet
to 4,800
feet.
|
| · |
Colorado’s
Phillips and Sedgwick Counties in which the Company has approximately
50%
working interest. This Niobrara leasehold position is adjacent
to and
immediately north of Berry’s producing natural gas assets in Yuma County.
|
2005
-
In 2005,
the Company drilled approximately 103 gross wells as part of its ongoing
development program and the initiation of the 40-acre infill program from
the
existing 80-acre development. The JV’s initial exploratory wells at Prairie Star
Sherman County, Kansas are commercial. Additionally, the JV drilled 7 gross
wells (4 net) in 2005 at Prairie Star.
2006
-
Capital of $25 million ($17 million development and $8 million exploration)
is
directed at drilling over 160 wells to add production from both proved
undeveloped and probable reserves and over 30 exploratory wells, based on
various seismic data and interpretation. The Company will also participate
in at
least five 3-D seismic surveys covering in excess of 250 square
miles.
Williston
Basin
Bakken
Play, North Dakota -
In 2005,
the Company completed several transactions and Berry now has total working
interests of 50% in 186,000 gross acres (46,000 net) located in the Williston
Basin in North Dakota. These acquisitions, totaling approximately $9 million,
provide the Company an entry into the emerging Bakken oil play in the Williston
Basin. The acreage covers several contiguous blocks located primarily on
the
eastern flank of the Nesson Anticline. Development activity in the Middle
Bakken
play is generally expanding to the area surrounding the Nesson Anticline.
2005
-
The
Company participated in one exploratory well which is undergoing
evaluation.
2006
-
Capital of $4 million is directed at participating in at least four exploratory
horizontal wells. Berry does not anticipate being the operator of any of
these
wells.
Piceance
Basin
Grand
Valley, Colorado -
On
January 27, 2006 the Company announced that it had entered into an agreement
with a private seller to acquire a 50% working interest in natural gas assets
(6,314 gross acres) in the Piceance Basin of western Colorado for approximately
$150 million. Berry internally estimates 26 billion cubic feet (Bcf) of proved
reserves. Berry has identified over 600 drilling locations based on 10-acre
development. Berry will be targeting gas in the Williams Fork section of
the
Mesaverde formation. The Company increased its 2006 capital budget by an
additional $48 million to $208 million to develop this resource. There are
two
drilling rigs dedicated to this project and based on the productivity of
this
acreage and surrounding producing operations, Berry is seeking to add additional
drilling rigs to accelerate development. Estimated production, net to Berry’s
interests as of March 1, 2006 is 1 million cubic feet per day. The transaction
closed on February 28, 2006.
2006
-
Capital of $48 million is directed at beginning the extensive development
of the
acreage. The Company intends to drill over 30 wells in 2006 and, depending
on
rig availability and commodity prices, may increase its capital committed
to the
project.
The
following is a summary of the Company's capital expenditures incurred during
2005 and 2004 and budgeted capital expenditures for 2006:
CAPITAL
EXPENDITURES SUMMARY
(in
thousands)
|
|
2006
|
2005
|
|
2004
|
|
||||
|
|
(Budgeted)
(1)
|
|
|
|
|
|
|||
|
CALIFORNIA
|
|
|
|
|
|
|
|||
|
Midway-Sunset
field
|
|
|
|
|
|
|
|||
|
New
wells
|
$
|
23,380
|
|
$
|
17,369
|
|
$
|
11,376
|
|
|
Remedials/workovers
|
|
1,145
|
|
|
1,079
|
|
|
1,415
|
|
|
Facilities
- oil & gas
|
|
14,493
|
|
|
7,879
|
|
|
4,045
|
|
|
Facilities
- cogeneration
|
|
543
|
|
|
3,053
|
|
|
1,055
|
|
|
General
|
|
540
|
|
|
1,271
|
|
|
2,144
|
|
|
|
|
40,101
|
|
|
30,651
|
|
|
20,035
|
|
|
Other
California fields
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
|
10,647
|
|
|
6,965
|
|
|
426
|
|
|
Remedials/workovers
|
|
2,650
|
|
|
5,303
|
|
|
1,589
|
|
|
Facilities
- oil & gas
|
|
7,202
|
|
|
3,677
|
|
|
3,416
|
|
|
Facilities
- cogeneration
|
|
400
|
|
|
1,446
|
|
|
555
|
|
|
General
|
110
|
46
|
-
|
||||||
|
|
|
21,009
|
|
|
17,437
|
|
|
5,986
|
|
|
Total
California
|
|
61,110
|
|
|
48,088
|
|
|
26,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCKY
MOUNTAIN AND MID-CONTINENT
|
|
|
|
|
|
|
|
|
|
|
Uinta
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
|
64,100
|
|
|
50,354
|
|
|
39,467
|
|
|
Remedials/workovers
|
|
1,496
|
|
|
3,415
|
|
|
4,597
|
|
|
Facilities
|
|
2,500
|
|
|
1,860
|
|
|
1,979
|
|
|
General
|
552
|
4
|
-
|
||||||
|
|
|
68,648
|
|
|
55,633
|
|
|
46,043
|
|
|
Piceance
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells
|
47,615
|
-
|
-
|
||||||
|
|
|
47,615
|
|
|
-
|
|
|
-
|
|
|
DJ
Basin
|
|
|
|
|
|
|
|
|
|
|
New
wells/workovers
|
|
14,819
|
|
|
11,257
|
|
|
-
|
|
|
Remedials/workovers
|
275
|
693
|
-
|
||||||
|
Facilities
|
|
5,215
|
|
|
2,569
|
|
|
-
|
|
|
General
|
4,838
|
387
|
-
|
||||||
|
Land
and seismic
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
25,147
|
|
|
14,906
|
|
|
-
|
|
|
Williston
Basin - New wells
|
|
4,400
|
|
|
-
|
|
|
161
|
|
|
Total
Rocky Mountain and
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
145,810
|
|
|
70,539
|
|
|
46,204
|
|
|
Other
Fixed Assets
|
|
770
|
|
|
647
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
$
|
207,690
|
|
$
|
119,274
|
|
$
|
72,225
|
|
(1) Budgeted
capital expenditures may be adjusted for numerous reasons including, but
not
limited to, oil, and natural gas price levels and equipment availability,
permitting and regulatory issues. See Item
7 Management's Discussion and Analysis of Financial Condition and Results
of
Operations.
Production. The
following table sets forth certain information regarding production for the
years ended December 31, as indicated:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Net
annual production: (1)
|
|
|
|
|
|
|
|
|||
|
Oil
(Mbbl)
|
|
|
7,081
|
|
|
7,044
|
|
|
5,827
|
|
|
Gas
(MMcf)
|
|
|
7,919
|
|
|
2,839
|
|
|
1,277
|
|
|
Total
equivalent barrels (MBOE) (2)
|
|
|
8,401
|
|
|
7,517
|
|
|
6,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) before hedging
|
|
$
|
47.04
|
|
$
|
33.43
|
|
$
|
24.41
|
|
|
Oil
(per Bbl) after hedging
|
|
|
40.83
|
|
|
29.89
|
|
|
22.37
|
|
|
Gas
(per Mcf) before hedging
|
|
|
7.88
|
|
|
6.13
|
|
|
4.40
|
|
|
Gas
(per Mcf) after hedging
|
|
|
7.73
|
|
|
6.12
|
|
|
4.43
|
|
|
Per
BOE before hedging
|
|
|
47.01
|
|
|
33.64
|
|
|
24.48
|
|
|
Per
BOE after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
Average
operating cost - oil and gas production (per BOE)
|
|
|
11.79
|
|
|
10.09
|
|
|
9.57
|
|
Mbbl
-
Thousands of barrels
MMcf
-
Million cubic feet
BOE
-
Barrels of oil equivalent
MBOE
-
Thousand barrels of oil equivalent
(1)
Net production represents that owned by Berry and produced to its
interests.
(2)
Equivalent oil and gas information is at a ratio of 6 thousand cubic feet
(Mcf)
of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to
42
U.S. gallons
Acreage
and Wells. As
of
December 31, 2005, the Company's properties accounted for the following
developed and undeveloped acres:
|
|
|
Developed
Acres
|
|
Undeveloped
Acres
|
|
Total
|
|
||||||||||||
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||
|
California
|
|
|
8,007
|
8,007
|
7,038
|
7,038
|
15,045
|
15,045
|
|
||||||||||
|
Colorado
|
79,910
|
67,302
|
162,966
|
77,029
|
242,876
|
144,331
|
|||||||||||||
|
Illinois
|
|
|
-
|
-
|
35,481
|
33,249
|
35,481
|
33,249
|
|
||||||||||
|
Kansas
|
|
|
-
|
-
|
424,885
|
275,494
|
424,885
|
275,494
|
|
||||||||||
|
Nebraska
|
-
|
-
|
124,025
|
57,756
|
124,025
|
57,756
|
|||||||||||||
|
North
Dakota
|
-
|
-
|
185,976
|
46,252
|
185,976
|
46,252
|
|||||||||||||
|
Utah
(1) (2)
|
|
|
9,520
|
9,360
|
99,033
|
66,686
|
108,553
|
76,046
|
|
||||||||||
|
Wyoming
|
|
3,800
|
750
|
3,146
|
1,130
|
6,946
|
1,880
|
|
|||||||||||
|
Other
|
|
|
80
|
19
|
-
|
-
|
80
|
19
|
|
||||||||||
|
|
|
|
101,317
|
85,438
|
1,042,550
|
564,634
|
1,143,867
|
650,072
|
|
||||||||||
(1)
Includes 44,583 gross undeveloped acres (22,292 net) where the Company has
an
interest in 75% of the deep rights and 25% of the shallow
rights.
(2)
Does not include 125,000 gross (70,000 net) acres, 125,000 gross (23,000
net)
acres and 69,000 gross (34,000 net) acres at Lake Canyon (shallow), Lake
Canyon
(deep) and Coyote Flats, respectively, which the Company can earn upon
fulfilling specific drilling obligations.
Gross
acres represent acres in which Berry has a working interest; net acres represent
Berry's aggregate working interests in the gross acres.
As
of
December 31, 2005, the Company has 2,035 gross oil wells (1,951 net) and
976
gross gas wells (419 net). Gross wells represent the total number of wells
in
which Berry has a working interest. Net wells represent the number of gross
wells multiplied by the percentages of the working interests owned by Berry.
One
or more completions in the same bore hole are counted as one well. Any well
in
which one of the multiple completions is an oil completion is classified
as an
oil well.
Drilling
Activity. The
following table sets forth certain information regarding Berry's drilling
activities for the periods indicated:
|
|
|
2005
|
|
2004
|
|
2003
|
|
||||||||||||
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||
|
Exploratory
wells drilled (2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
|
|
13
|
6
|
|
|
5
|
|
|
5
|
|
|
-
|
|
|
-
|
|
||
|
Dry
(1)
|
|
|
1
|
1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
||
|
Development
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Productive
|
|
|
213
|
176
|
|
|
123
|
|
|
111
|
|
|
121
|
|
|
119
|
|
||
|
Dry
(1)
|
|
|
7
|
5
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
||
|
Total
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Productive
|
|
|
226
|
182
|
|
|
128
|
|
|
116
|
|
|
121
|
|
|
119
|
|
||
|
Dry
(1)
|
|
|
8
|
6
|
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
||
(1)
A
dry well is a well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
(2)
Does not include one gross well drilled by the Company’s industry partner that
is being evaluated at December 31, 2005.
|
|
|
2005
|
||||
|
|
|
Gross
|
|
Net
|
||
|
Total
productive wells drilled:
|
|
|
||||
|
Oil
|
|
|
113
|
111
|
||
|
Gas
|
|
|
113
|
71
|
||
Dry
hole, abandonment and impairment.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
California
Drilling Rig.
The
Company entered into a three-year drilling contract for the services of an
automated drilling rig. This rig provides a means for Berry to meet at least
half of its California new well drilling needs for the next three years,
with
the other half being met by conventional drilling rigs. The three-year drilling
contract begins upon commissioning of the rig which is expected in the second
quarter of 2006.
Rocky
Mountain and Mid-Continent Region Drilling Rigs.
During
2005, the Company purchased two drilling rigs. The first rig is leased to
a
drilling company under a three year contract, while the second rig is currently
being refurbished in preparation for leasing under a similar drilling contract.
Owning these rigs allows the Company to successfully meet a portion of its
drilling needs in the Uinta Basin over the next several years, while both
rigs
carry purchase options available to the drilling company.
Other.
At
year-end, the Company had no subsidiaries, no special purpose entities and
no
off-balance sheet debt. The Company did not enter into any significant related
party transactions in 2005. See Note 17 to the financial statements for
discussion regarding Canyon Drilling, LLC.
Environmental
and Other Regulations. Berry
Petroleum Company is committed to responsible management of the environment,
health and safety, as these areas relate to the Company’s operations. The
Company strives to achieve the long-term goal of sustainable development
within
the framework of sound environmental, health and safety practices and standards.
Berry makes environmental, health and safety protection an integral part
of all
business activities, from the acquisition and management of its resources
through the decommissioning and reclamation of its wells and
facilities.
All
facets of the Company's operations are affected by a myriad of federal, state,
regional and local laws, rules and regulations. Berry is further affected
by
changes in such laws and by constantly changing administrative regulations.
Furthermore, government agencies may impose substantial liabilities if the
Company fails to comply with such regulations or for any contamination resulting
from the Company's operations. Therefore, Berry has programs in place to
identify and manage known risks, to train employees in the proper performance
of
their duties and to incorporate viable new technologies into its operations.
The
costs incurred to ensure
compliance
with environmental, health and safety laws and other regulations are normal
operating expenses and are not material to the Company’s operating cost. There
can be no assurances, however, that changes in, or additions to, laws and
regulations regarding the protection of the environment will not have an
impact
in the future. Berry maintains insurance coverage that it believes is customary
in the industry although it is not fully insured against all environmental
or
other risks.
Regulation
of Oil and Gas. The
oil
and gas industry, including the Company’s operations, is extensively regulated
by numerous federal, state and local authorities, and with respect to tribal
lands, and one Native American tribe.
These
types of regulation include requiring permits for the drilling of wells,
drilling bonds and reports concerning operations. Regulations may also govern
the location of wells, the method of drilling and casing wells, the rates
of
production or "allowables," the surface use and restoration of properties
upon
which wells are drilled, the plugging and abandoning of wells, and notice
to surface owners and other third parties. Certain laws and regulations may
limit the amount of oil and natural gas the Company can produce from its
wells
or limit the number of wells or the locations at which it can drill. The
Company
is also subject to various laws and regulations pertaining to Native American
tribal surface ownership, Native American oil and gas leases and other
exploration agreements, fees, taxes, and other burdens, obligations and issues
unique to oil and gas ownership and operations within Native American
reservations.
Federal
Energy Regulation. The
enactment of PURPA, as amended, and the adoption of regulations thereunder
by
the Federal Energy Regulation Commission (FERC) provided incentives for the
development of cogeneration facilities such as those owned by the Company.
A
domestic electricity generating project must be a QF under FERC regulations
in
order to take advantage of certain rate and regulatory incentives provided
by
PURPA.
PURPA
provides two primary benefits to QFs. First, QFs generally are relieved of
compliance with extensive federal and state regulations that control the
financial structure of an electricity generating plant and the prices and
terms
on which electricity may be sold by the plant. Second, FERC’s regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility’s avoided cost, and
that the utility sell back-up power to the QF on a non-discriminatory basis.
The
term "avoided cost" is defined as the incremental cost to an electric utility
of
electric energy or capacity, or both, which, but for the purchase from QFs,
such
utility would generate for itself or purchase from another source. The Energy
Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be
relieved of its obligation to enter into any new contracts with QFs if the
FERC
determines that a competitive electricity market is available to QFs in its
service territory. This amendment does not affect any of the Company’s current
SO contracts. FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases
of power at rates lower than the utilities’ avoided costs. In California, the
utility’s avoided cost is generally referred to as Short Run Avoided Cost or
SRAC.
In
order
to be a QF, a cogeneration facility must produce not only electricity, but
also
useful thermal energy for use in an industrial or commercial process for
heating
or cooling applications in certain proportions to the facility’s total energy
output, and must meet certain energy efficiency standards. Each of the Company’s
cogeneration facilities is a QF, pursuant to PURPA.
State
Energy Regulation. The
CPUC
has broad authority to regulate both the rates charged by, and the financial
activities of, electric utilities operating in this state and to promulgate
regulation for implementation of PURPA. Since a power sales agreement becomes
a
part of a utility’s cost structure (generally reflected in its retail rates),
power sales agreements with independent electricity producers, such as the
Company, are potentially under the regulatory purview of the CPUC and in
particular the process by which the utility has entered into the power sales
agreements. While the Company is not subject to regulation by the CPUC, the
CPUC's implementation of PURPA is important to the Company.
Forward
Looking Statements
"Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-K that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “will,” “might,”
“intend,” “continue,” “target(s),” “expect,” “achieve,” “strategy,” “future,”
“may,” “could,” “goal(s),” or other comparable words or phrases or the negative
of those words, and other words of similar meaning indicate forward-looking
statements and important factors which could affect actual results.
Forward-looking statements are made based on management’s current expectations
and beliefs concerning future developments and their potential effects upon
Berry Petroleum Company. These items are discussed at length in Part I, Item
1A
on page 16 of this Form 10-K filed with the Securities and Exchange Commission,
under the heading “Other Factors Affecting the Company's Business and Financial
Results" in the section titled "Management’s Discussion and Analysis of
Financial Condition and Results of Operations.”
Other
Factors Affecting the Company's Business and Financial
Results
Oil
and gas prices fluctuate widely, and low prices for an extended period of
time
are likely to have a material adverse impact on our
business.
Our
revenues, profitability and future growth and reserve calculations depend
substantially on reasonable prices for oil and gas. These prices also affect
the
amount of our cash flow available for capital expenditures and our ability
to
borrow and raise additional capital. The amount we can borrow under our credit
facility is subject to periodic asset redeterminations based in part on changing
expectations of future crude oil and natural gas prices. Lower prices may
also
reduce the amount of oil and gas that we can produce economically.
Among
the
factors that can cause fluctuations are:
| · |
domestic
and foreign supply of oil and natural
gas;
|
| · |
price
and availability of alternative
fuels;
|
| · |
weather
conditions;
|
| · |
level
of consumer demand;
|
| · |
price
of foreign imports;
|
| · |
world-wide
economic conditions;
|
| · |
political
conditions in oil and gas producing regions;
and
|
| · |
domestic
and foreign governmental
regulations.
|
The
Company has crude oil hedges on 10,000 Bbl/D for 4 years beginning in 2006.
We
have an oil collar in place based on WTI pricing with a $47.50 floor and
a $70
ceiling.
Our
heavy crude in California is less economic than lighter crude oil and natural
gas. As
of
December 31, 2005, approximately 74% of our proved reserves or 93 million
barrels, consisted of heavy oil, light crude oil represented 8% and natural
gas
represented 18% of our oil and gas reserves. Our objective is to diversify
our
predominantly heavy crude oil base with light crude oil and natural gas.
In
November 2005, the Company entered into a new crude oil sales contract for
its
California production for deliveries beginning February 1, 2006 and ending
January 31, 2010. The per barrel price, calculated on a monthly basis and
blended across the various producing locations, is the higher of 1) the WTI
NYMEX crude oil price less a fixed differential approximating $8.15, or 2)
heavy
oil field postings plus a premium of approximately $1.35.
A
widening of commodity differentials may adversely impact our revenues and
per
barrel economics. Both
our
produced crude oil and natural gas are subject to pricing in the local markets
where the production occurs. It is customary that such products are priced
based
on local or regional supply and demand factors. California heavy crude sells
at
a discount to WTI, the U.S. benchmark crude oil, primarily due to the additional
cost to refine gasoline or light product out of a barrel of heavy crude.
Our
Utah light crude also is currently priced at $2.00 below WTI. Natural gas
field
prices are normally priced off of Henry Hub NYMEX price, the benchmark for
U.S.
natural gas. While we attempt to contract for the best possible price in
each of
our producing locations, there is no assurance that past price differentials
will continue into the future. Numerous factors may influence local pricing,
such as refinery capacity, particularly for black wax crude, pipeline capacity
and specifications, upsets in the mid-stream or downstream sectors of the
industry, trade restrictions, governmental regulations, etc. We may be adversely
impacted by a widening differential on the products sold.
Market
conditions or operational impediments may hinder our access to crude oil
and
natural gas markets or delay our production. Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas
markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand
for
and supply of oil and natural gas and the proximity of reserves to pipelines
and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines,
processing facilities and refineries owned and operated by third parties.
Our
failure to obtain such services on acceptable terms could materially harm
our
business. We may be required to shut in wells for a lack of a market or because
of inadequacy or unavailability of natural gas pipeline, gathering system
capacity, processing facilities or refineries. If that were to occur, then
we
would be unable to realize revenue from those wells until arrangements were
made
to deliver the production to market. See firm transportation summary schedule
at
Item 1 Business.
Factors
that can cause price volatility for crude oil and natural gas
include:
| · |
availability
and capacity of refineries;
|
| · |
availability
of gathering systems with sufficient capacity to handle local
production;
|
| · |
seasonal
fluctuations in local demand for
production;
|
| · |
local
and national gas storage capacity;
|
| · |
interstate
pipeline capacity; and
|
| · |
availability
and cost of gas transportation facilities.
|
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. We believe the differential has widened
by
several dollars per barrel. The majority of this crude oil, while light,
is a
“paraffinic” crude, and can be processed efficiently by only a limited number
of stranded inland refineries. The production of this type crude is
increasing regionally and beginning to strain the capacity of these refineries.
Other new crude sources from the region are pressuring pricing. If these
refineries limit the volumes of this parraffinic crude oil they are willing
to
process, it could impact the marketability of this type of crude which, for
Berry, represents approximately 3,500 Bbl/D of production or approximately
15%
of total current production. We are investigating the market opportunities
for
this crude oil. If market prices continue to deteriorate,
we may
allocate capital expenditures to projects which produce natural gas and crude
oils with lower paraffinic content until the refinery constraint is
resolved.
We
may be subject to the risk of adding additional steam generation equipment
if
the electrical market deteriorates significantly.
We may
be subject to the risk of adding additional steam generation equipment if
the
electrical market deteriorates significantly. We are dependent on several
cogeneration facilities that provide over half of our steam requirement.
These
facilities are dependent on reasonable electrical contracts. If, for any
reason,
we were unable to enter into an electrical contract or were to lose an existing
contract, we may not be able to supply 100% of the steam requirements necessary
to maximize production from our heavy oil assets. An additional investment
in
various steam sources may be necessary to replace such steam, and there may
be
risks and delays in being able to install conventional steam equipment due
to
permitting requirements. The financial cost and timing of such investment
may
adversely affect our production, capital outlays and cash provided by operating
activities. We
have
electricity contracts covering most of our electricity generation which
contracts expire in 2009.
A
shortage of natural gas in California could adversely affect our business.
We
may be
subject to the risks associated with a shortage of natural gas and/or the
transportation of natural gas into and within California. We are highly
dependent on sufficient volumes of natural gas that we use for fuel in
generating steam in our heavy oil operations in California. If the required
volume of natural gas for use in our operations were to be unavailable or
too
highly priced to produce heavy oil economically, our production could be
adversely impacted. The
Company has firm transportation to move 12,000 MMBtu/D on the Kern River
Pipeline from the Rocky Mountains to Kern County, CA. This volume is
approximately one-third of the Company’s current requirement.
Our
use of oil and gas price hedging contracts involves credit risk and may limit
future revenues from price increases and result in significant fluctuations
in
net income.
We use
hedging transactions with respect to a portion of our oil and gas production
to
achieve more predictable cash flow and to reduce our exposure to a significant
decline in the price of crude oil. While the use of hedging transactions
limits
the downside risk of price declines, their use may also limit future revenues
from price increases. Hedging transactions also involve the risk that the
counterparty may be unable to satisfy its obligations. The Company utilizes
several counterparties for its hedging contracts.
Our
future success depends on our ability to find, develop and acquire oil and
gas
reserves. To
maintain production levels, we must locate and develop or acquire new oil
and
gas reserves to replace those depleted by production. Without successful
exploration, exploitation or acquisition activities, our reserves, production
and revenues will decline. We may not be able to find and develop or acquire
additional reserves at an acceptable cost. In addition, substantial capital
is
required to replace and grow reserves. If lower oil and gas prices or operating
difficulties result in our cash flow from operations being less than expected
or
limit our ability to borrow under credit arrangements, we may be unable to
expend the capital necessary to locate and develop or acquire new oil and
gas
reserves.
Actual
quantities of recoverable oil and gas reserves and future cash flows from
those
reserves ,
future production, oil and gas prices, revenues, taxes, development expenditures
and operating expenses most likely will vary from
estimates. Estimating
accumulations of oil and gas is complex. The process relies on interpretations
of available geologic, geophysical, engineering and production data. The
extent,
quality and reliability of this data can vary. The process also requires
certain
economic assumptions, such as oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds, some of
which
are mandated by the SEC. The accuracy of a reserve estimate is a function
of:
| · |
quality
and quantity of available data;
|
| · |
interpretation
of that data; and
|
| · |
accuracy
of various mandated economic
assumptions.
|
Any
significant variance could materially affect the quantities and present value
of
our reserves. In addition, we may adjust estimates of proved reserves to
reflect
production history, results of development and exploration and prevailing
oil
and gas prices.
In
accordance with SEC requirements, we base the estimated discounted future
net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the
prices
and costs as of the date of the estimate.
If
oil or gas prices decrease, we may be required to take writedowns.
We
may be
required to writedown the carrying value of our oil and gas properties when
oil
or gas prices are low, including basis differentials, or there are substantial
downward adjustments to our estimated proved reserves, increases in estimates
of
development costs or deterioration in exploration or production results.
We
capitalize costs to acquire, find and develop our oil and gas properties
under
the successful efforts accounting method. If net capitalized costs of our
oil
and gas properties exceed fair value, we must charge the amount of the excess
to
earnings. We review the carrying value of our properties annually and at
any
time when events or circumstances indicate a review is necessary, based on
prices in effect as of the end of the reporting period. The carrying value
of
oil and gas properties is computed on a field-by-field basis. Once incurred,
a
writedown of oil and gas properties is not reversible at a later date even
if
oil or gas prices increase. See Item 7A Quantitative and Qualitative Disclosures
About Market Risk for the Company’s hedge position on February 10,
2006.
Competitive
industry conditions may negatively affect our ability to conduct operations.
Competition
in the oil and gas industry is intense, particularly with respect to the
acquisition of producing properties and proved undeveloped acreage. Major
and
independent oil and gas companies actively bid for desirable oil and gas
properties, as well as for the equipment and labor required to operate and
develop their properties. Many of our competitors have financial resources
that
are substantially greater, which may adversely affect our ability to compete
within the industry.
Drilling
is a high-risk activity. Our
future success will partly depend on the success of our drilling program.
In
addition to the numerous operating risks described in more detail below,
these
drilling activities involve the risk that no commercially productive oil
or gas
reservoirs will be discovered. In addition, we are often uncertain as to
the
future cost or timing of drilling, completing and producing wells. Furthermore,
drilling operations may be curtailed, delayed or canceled as a result of
a
variety of factors, including:
| · |
obtaining
government and tribal required
permits;
|
| · |
unexpected
drilling conditions;
|
| · |
pressure
or irregularities in formations;
|
| · |
equipment
failures or accidents;
|
| · |
adverse
weather conditions;
|
| · |
compliance
with governmental or landowner requirements;
and
|
| · |
shortages
or delays in the availability of drilling rigs and the delivery
of
equipment and/or services.
|
The
oil and gas business involves many operating risks that can cause substantial
losses; insurance may not protect us against all of these risks. These risks
include:
| · |
fires;
|
| · |
explosions;
|
| · |
blow-outs;
|
| · |
uncontrollable
flows of oil, gas, formation water or drilling
fluids;
|
| · |
natural
disasters;
|
| · |
pipe
or cement failures;
|
| · |
casing
collapses;
|
| · |
embedded
oilfield drilling and service
tools;
|
| · |
abnormally
pressured formations;
|
| · |
major
equipment failures, including cogeneration facilities;
and
|
| · |
environmental
hazards such as oil spills, natural gas leaks, pipeline ruptures
and
discharges of toxic gases.
|
If
any of
these events occur, we could incur substantial losses as a result
of:
| · |
injury
or loss of life;
|
| · |
severe
damage or destruction of property, natural resources and
equipment;
|
| · |
pollution
and other environmental damage;
|
| · |
investigatory
and clean-up responsibilities;
|
| · |
regulatory
investigation and penalties;
|
| · |
suspension
of operations; and
|
| · |
repairs
to resume operations.
|
If
we
experience any of these problems, our ability to conduct operations could
be
adversely affected. If a significant accident or other event occurs and is
not
fully covered by insurance, it could adversely affect us. In accordance with
customary industry practices, we maintain insurance coverage against some,
but
not all, potential losses in order to protect against the risks we face.
We do
not carry business interruption insurance. We may elect not to carry insurance
if our Management believes that the cost of available insurance is excessive
relative to the risks presented. In addition, we cannot insure fully against
pollution and environmental risks. The occurrence of an event not fully covered
by insurance could have a material adverse effect on our financial condition
and
results of operations. While we intend to obtain and maintain appropriate
insurance coverage for these risks, there can be no assurance that our
operations will not expose us to liabilities exceeding such insurance coverage
or to liabilities not covered by insurance.
We
are subject to complex federal, state, local and other laws and regulations
that
could adversely affect the cost, manner or feasibility of doing
business.
Our
development, exploration, production and marketing operations are regulated
extensively at the federal, state and local levels. In addition, a portion
of
our leases in the Uinta Basin are, and some of our future leases may be,
regulated by Native American tribes. Environmental and other governmental
laws
and regulations have increased the costs to plan, design, drill, install,
operate and abandon oil and natural gas wells. Under these laws and regulations,
we could also be liable for personal injuries, property damage and other
damages. Failure to comply with these laws and regulations may result in
the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, public interest in environmental
protection has increased in recent years, and environmental organizations
oppose
certain drilling projects and/or access to prospective lands.
Part
of
the regulatory environment in which we operate includes, in some cases, federal
requirements for obtaining environmental assessments, environmental impact
studies and/or plans of development before commencing exploration and production
activities. In addition, our activities are subject to the regulation by
oil and
natural gas-producing states and one Native American tribe of conservation
practices and protection of correlative rights. These regulations affect
our
operations and limit the quantity of oil and natural gas we may produce and
sell. A major risk inherent in our drilling plans is the need to obtain drilling
permits from state, local and Native American tribal authorities. Delays
in
obtaining regulatory approvals or drilling permits, the failure to obtain
a
drilling permit for a well or the receipt of a permit with unreasonable
conditions or costs could have a negative effect on our ability to explore
on or
develop its properties. Additionally, the oil and natural gas regulatory
environment could change in ways that might substantially increase the financial
and managerial costs to comply with the requirements of these laws and
regulations and, consequently, adversely affect our profitability.
Property
acquisitions are a component of our growth strategy, and our failure to complete
future acquisitions successfully could reduce our earnings and slow our
growth.
Our
business strategy has emphasized growth through strategic acquisitions, but
we
may not be able to continue to identify properties for acquisition or we
may not
be able to make acquisitions on terms that we consider economically acceptable.
There is intense competition for acquisition opportunities in our industry.
Competition for acquisitions may increase the cost of, or cause us to refrain
from, completing acquisitions. Our strategy of completing acquisitions is
dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. If we are unable to achieve
strategic acquisitions, our growth may be impaired, thus impacting earnings,
cash from operations and reserves.
Acquisitions
are subject to the uncertainties of evaluating recoverable reserves and
potential liabilities. Our
recent growth is due in part to acquisitions of producing properties, and
we
expect acquisitions will continue to contribute to our future growth. Successful
acquisitions require an assessment of a number of factors, many of which
are
beyond our control. These factors include recoverable reserves, exploration
potential, future oil and natural gas prices, operating costs, production
taxes
and potential environmental and other liabilities. Such assessments are inexact
and their accuracy is inherently uncertain. In connection with our assessments,
we perform a review of the acquired properties, which we believe is generally
consistent with industry practices. However, such a review will not reveal
all
existing or potential problems. In addition, our review may not allow us
to
become sufficiently familiar with the properties, and we do not always discover
structural, subsurface and environmental problems that may exist or arise.
Our
review prior to signing a definitive purchase agreement may be even more
limited.
We
generally are not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities, on acquisitions. Often,
we
acquire interests in properties on an "as is" basis with limited remedies
for
breaches of representations and warranties. If material breaches are discovered
by us prior to closing, we could require adjustments to the purchase price
or if
the claims are significant, we or the seller may have a right to terminate
the
agreement. We could also fail to discover breaches or defects prior to closing
and incur significant unknown liabilities, including environmental liabilities,
or experience losses due to title defects, for which we would have limited
or no
contractual remedies or insurance coverage.
There
are risks in acquiring producing properties, including difficulties in
integrating acquired properties into our business, additional liabilities
and
expenses associated with acquired properties, diversion of Management attention,
and costs of increased scope, geographic diversity and complexity of our
operations.
Increasing our reserve base through acquisitions is an important part of
our
business strategy. Our failure to integrate acquired businesses successfully
into our existing business, or the expense incurred in consummating future
acquisitions, could result in our incurring unanticipated expenses and losses.
In addition, we may have to assume cleanup or reclamation obligations or
other
unanticipated liabilities in connection with these acquisitions. The scope
and
cost of these obligations may ultimately be materially greater than estimated
at
the time of the acquisition.
In
connection with future acquisitions, the process of integrating acquired
operations into our existing operations may result in unforeseen operating
difficulties and may require significant Management attention and financial
resources that would otherwise be available for the ongoing development or
expansion of existing operations
Possible
future acquisitions could result in our incurring additional debt, contingent
liabilities and expenses, all of which could have a material adverse effect
on
our financial condition and operating results.
The
loss of key personnel could adversely affect our business.
We
depend
to a large extent on the efforts and continued employment of our executive
Management team and other key personnel. The loss of the services of these
or
other key personnel could adversely affect our business, and we do not maintain
key man insurance on the lives of any of these persons. Our drilling success
and
the success of other activities integral to our operations will depend, in
part,
on our ability to attract and retain experienced geologists, engineers, landmen
and other professionals. Competition for many of these professionals is intense.
If we cannot retain our technical personnel or attract additional experienced
technical personnel, our ability to compete could be harmed.
We
have limited control over the activities on properties that we do not operate.
Although
we operate most of the properties in which we have an interest, other companies
operate some of the properties. We have limited ability to influence or control
the operation or future development of these nonoperated properties or the
amount of capital expenditures that we are required to fund their operation.
Our
dependence on the operator and other working interest owners for these projects
and our limited ability to influence or control the operation and future
development of these properties could have a material adverse effect on the
realization of our targeted returns or lead to unexpected future costs.
We
may not adhere to our proposed drilling schedule. Our
final
determination of whether to drill any scheduled or budgeted wells will depend
on
a number of factors, including:
| · |
results
of our exploration efforts and the acquisition, review and analysis
of our
seismic data, if any;
|
| · |
availability
of sufficient capital resources to us and any other participants
for the
drilling of the prospects;
|
| · |
approval
of the prospects by other participants after additional data has
been
compiled;
|
| · |
economic
and industry conditions at the time of drilling, including prevailing
and
anticipated prices for oil and natural gas and the availability
and prices
of drilling rigs and crews; and
|
| · |
availability
of leases, license options, farm-outs, other rights to explore
and permits
on reasonable terms for the
prospects.
|
Although
we have identified or budgeted for numerous drilling prospects, we may not
be
able to lease or drill those prospects within our expected time frame, or
at
all. In addition, our drilling schedule may vary from our expectations because
of future uncertainties and rig availability and access to our drilling
locations utilizing available roads. As of December 31, 2005, the Company
owns
two drilling rigs and has additional one-year contract commitments on another
two drilling rigs. See Note 10 to the financial statements.
We
may incur losses as a result of title deficiencies. We
purchase working and revenue interests in the oil and natural gas leasehold
interests upon which we will perform our exploration activities from third
parties or directly from the mineral fee owners. The existence of a material
title deficiency can render a lease worthless and can adversely affect our
results of operations and financial condition. Title insurance covering mineral
leaseholds is not generally available and, often, we forego the expense of
retaining lawyers to examine the title to the mineral interest to be placed
under lease or already placed under lease until the drilling block is assembled
and ready to be drilled. As is customary in our industry, we rely upon the
judgment of oil and natural gas lease brokers or independent landmen who
perform
the field work in examining records in the appropriate governmental offices
and
abstract facilities before attempting to acquire or place under lease a specific
mineral interest. We, in some cases, perform curative work to correct
deficiencies in the marketability of the title to us. The work might include
obtaining affidavits of heirship or causing an estate to be administered.
In
cases involving more serious title problems, the amount paid for affected
oil
and natural gas leases can be generally lost, and the target area can become
undrillable.
The
future of the electricity market in California is uncertain.
We
utilize cogeneration plants in California to generate lower cost steam compared
to conventional steam generation methods. Electricity produced by our
cogeneration plants is sold to utilities and the steam costs are allocated
to
our oil and gas operations. While we have electricity sales contracts in
place
with the utilities that are currently scheduled to terminate in 2009, legal
and
regulatory decisions, especially related to the pricing of electricity under
the
contracts, can adversely affect the economics of our cogeneration facilities
and
thereby, the cost of steam for use in our oil and gas operations.
Estimates
may differ from actual. The
preparation of financial statements in conformity with accounting principles
generally accepted in the U.S. requires Management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
related disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Certain accounting policies involve judgments and
uncertainties to such an extent that there is reasonable likelihood that
materially different amounts could have been reported under different
conditions, or if different assumptions had been used. Actual results may
differ
from these estimates and assumptions used in preparation of its financial
statements. Significant estimates with regard to these financial statements
include the estimate of proved oil and gas reserve quantities, the related
present value of estimated future net cash flows therefrom, the costs to
develop
and abandon oil and gas properties, the valuation of derivative positions
and
stock-based compensation valuation.
None.
Information
required by Item 2 Properties is included under Item 1 Business.
While
the
Company is, from time to time, a party to certain lawsuits in the ordinary
course of business, the Company does not believe any of such existing lawsuits
will have a material adverse effect on the Company's operations, financial
condition, or liquidity.
No
matters were submitted to a vote of security holders during the most recently
ended fiscal quarter.
Executive
Officers of the Registrant. Listed
below are the names, ages (as of December 31, 2005) and positions of the
executive officers of Berry and their business experience during at least
the
past five years. All officers of the Company are appointed in May of each
year
at an organizational meeting of the Board of Directors. There are no family
relationships between any of the executive officers and members of the Board
of
Directors.
ROBERT
F.
HEINEMANN, 52, has been President and Chief Executive Officer since June
2004.
Mr. Heinemann was Chairman of the Board and interim President and Chief
Executive Officer from April 2004 to June 2004. From December 2003 to March
2004, Mr. Heinemann was the director designated to serve as the presiding
director at executive sessions of the Board in the absences of the Chairman
and
to act as liaison between the independent directors and the CEO. Mr. Heinemann
joined the Company’s Board in March of 2003. From 2000 until 2002, Mr. Heinemann
served as the Senior Vice President and Chief Technology Officer of Halliburton
Company and as the Chairman of the Halliburton Technology Advisory Committee.
He
was previously with Mobil Oil Corporation (Mobil) where he served in a variety
of positions for Mobil and its various affiliate companies in the energy
and
technical fields from 1981 to 1999, with his last responsibilities as Vice
President of Mobil Technology Company and General Manager of the Mobil
Exploration and Producing Technical Center.
RALPH
J.
GOEHRING, 49, has been Executive Vice President and Chief Financial Officer
since June 2004. Mr. Goehring was Senior Vice President from April 1997 to
June
2004, and has been Chief Financial Officer since March 1992 and was Manager
of
Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant
Secretary for the Company.
MICHAEL
DUGINSKI, 39, has been Executive Vice President of Corporate Development
and
California since October 2005. Mr. Duginski was Senior Vice President of
Corporate Development from June 2004 through October 2005 and was Vice President
of Corporate Development from February 2002 through June 2004. Mr. Duginski,
a
mechanical engineer, was previously with Texaco, Inc. from 1988 to 2002 where
his positions included Director of New Business Development, Production Manager
and Gas and Power Operations Manager. Mr. Duginski is also an Assistant
Secretary for the Company.
LOGAN
MAGRUDER, 49, has been Executive Vice President of the Rocky Mountains and
Mid-Continent region since October 2005. Mr. Magruder was Senior Vice President
of the Rocky Mountain and Mid-Continent region from June 2004 through October
2005 and was Vice President of the Rocky Mountain and Mid-Continent region
from
August 2003 through June 2004. Mr. Magruder, a petroleum engineer, was a
consultant for the Company from February 2003 through August 2003. Mr. Magruder
was previously Vice President of U.S. Operations for Calpine Natural Gas
Company
from 2001 to 2003. Prior to Calpine, Mr. Magruder was employed by Barrett
Resources as Vice President of Engineering and Operations from 1996 to 2001.
DAN
ANDERSON, 43, has been Vice President of Rocky Mountains and Mid-Continent
Production since October 2005. Mr. Anderson was Rocky Mountain and Mid-Continent
Manager of Engineering from August 2003 through October 2005. Mr. Anderson
was
previously a Senior Staff Petroleum Engineer with Williams Production RMT
from
August 2001 through August 2003. He previously was a Senior Staff Engineer
with
Barrett Resources from October 2000 through August 2001.
GEORGE
T.
CRAWFORD, 45, has been Vice President of California Production since October
2005. Mr. Crawford was Vice President of Production from December 2000 through
October 2005 and was Manager of Production from January 1999 to December
2000.
Mr. Crawford, a petroleum engineer, was previously the Production Engineering
Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998 in numerous
engineering and operational assignments including Production Engineering
Supervisor, Planning and Evaluation Consultant and Operations
Superintendent.
BRUCE
S.
KELSO, 50, has been Vice President of Rocky Mountains and Mid-Continent
Exploration since October 2005. Mr. Kelso was Rocky Mountain and Mid-Continent
Exploration Manager from August 2003 through October 2005. Mr. Kelso, a
petroleum geologist, was previously a Senior Staff Geologist assigned to
Rocky
Mountain assets with Williams Production RMT, from January 2002 through August
2003. He previously was the Vice President of Exploration and Development
at
Redstone Resources, Inc. from 2000 to 2001.
BRIAN
L.
REHKOPF, 58, has been Vice President of Technology since October 2005. Mr.
Rehkopf was Vice President of Engineering from March 2000 through October
2005
and was Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf,
a
registered petroleum engineer, joined the Company’s engineering department in
June 1997 and was previously a Vice President and Asset Manager with ARCO
since
1992 and an Operations Engineering Supervisor from 1988 to 1992. Mr. Rehkopf
is
also an Assistant Secretary for the Company.
SHAWN
M.
CANADAY, 30, has been Treasurer since December 2004 and was Senior Financial
Analyst from November 2003 until December 2004. Mr. Canaday has worked in
the
oil and gas industry since 1998 in various finance functions at ChevronTexaco
and in public accounting. Mr. Canaday is also an Assistant Secretary for
the
Company.
DONALD
A.
DALE, 59, has been Controller since December 1985.
KENNETH
A. OLSON, 50, has been Corporate Secretary since December 1985 and was Treasurer
from August 1988 until December 2004.
PART
II
Shares
of
Class A Common Stock (Common Stock) and Class B Stock, referred to collectively
as the "Capital Stock," are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $1.00 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option
of the
holder.
In
November 1999, the Company adopted a Shareholder Rights Agreement and declared
a
dividend distribution of one such Right for each outstanding share of Capital
Stock on December 8, 1999. Each share of Capital Stock issued after December
8,
1999 includes one Right. The Rights expire on December 8, 2009. See Note
7 to
the financial statements.
Berry's
Class A Common Stock is listed on the New York Stock Exchange (NYSE) under
the
symbol BRY. The Class B Stock is not publicly traded. The market data and
dividends for 2005 and 2004 are shown below:
|
|
|
2005
|
|
2004
|
|
||||||||||||||
|
|
|
Price
Range
|
|
Dividends
|
|
Price
Range
|
|
Dividends
|
|
||||||||||
|
|
|
High
|
|
Low
|
|
Per
Share
|
|
High
|
|
Low
|
|
Per
Share
|
|
||||||
|
First
Quarter
|
|
$
|
66.09
|
$
|
43.85
|
$
|
.12
|
|
$
|
27.30
|
|
$
|
18.25
|
|
$
|
0.11
|
|
||
|
Second
Quarter
|
|
|
54.95
|
40.78
|
.12
|
|
|
31.07
|
|
|
25.09
|
|
|
0.11
|
|
||||
|
Third
Quarter
|
|
|
67.00
|
52.30
|
.23
|
|
|
38.44
|
|
|
27.73
|
|
|
0.18
|
|
||||
|
Fourth
Quarter
|
|
|
68.66
|
52.30
|
.13
|
|
|
50.58
|
|
|
35.16
|
|
|
0.12
|
|
||||
|
Total
Dividend Paid
|
$
|
.60
|
$
|
.52
|
|||||||||||||||
|
|
|
February
10, 2006
|
|
December
31, 2005
|
|
December
31, 2004
|
|
|||
|
Berry’s
Common Stock closing price per share as reported on NYSE Composite
Transaction Reporting System
|
|
$
|
68.90
|
|
$
|
57.20
|
$
|
47.70
|
|
|
The
number of holders of record of the Company's Common Stock was 605 as of February
10, 2006. There was one Class B Shareholder of record as of February 10,
2006.
Dividends.
The
Company paid a special dividend of $.10 per share on September 29, 2005 and
increased its regular quarterly dividend by 8%, from $.12 to $.13 per share
beginning with the September 29, 2005 dividend. The Company's regular annual
dividend is currently $.52 per share, payable quarterly in March, June,
September and December. The Company paid a special dividend of $.06 per share
on
September 29, 2004 and increased its regular quarterly dividend by 9%, from
$.11
to $.12 per share beginning with the September 2004 dividend.
Since
Berry Petroleum Company's formation in 1985 through December 31, 2005, the
Company has paid dividends on its Common Stock for 65 consecutive quarters
and
previous to that for eight consecutive semi-annual periods. The Company intends
to continue the payment of dividends, although future dividend payments will
depend upon the Company's level of earnings, operating cash flow, capital
commitments, financial covenants and other relevant factors. Dividend payments
are limited by covenants in the Company's credit facility to the greater
of $20
million or 75% of net income.
As
of
December 31, 2005, dividends declared on 3,984,080 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by the Company to the surviving member of a group of individuals,
the B
group, for as long as this remaining member shall live.
Equity
Compensation Plan Information
|
|
|
Number
of securities to be
|
|
|
|
|
|
|
|
issued
upon exercise of
|
|
Weighted
average exercise
|
|
Number
of securities
|
|
|
|
outstanding
options, warrants
|
|
price
of outstanding options,
|
|
remaining
available for future
|
|
Plan
category
|
|
and
rights
|
|
warrants
and rights
|
|
issuance
|
|
Equity
compensation plans approved by security holders
|
|
1,625,763
|
$33.52
|
1,080,187
|
||
|
|
|
|||||
|
Equity
compensation plans not approved by security holders
|
|
-
|
-
|
-
|
In
June
2005, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $50 million of the Company's
outstanding Class A Common Stock. Through December 31, 2005, the Company
repurchased 108,900 shares for approximately $6.3 million, which increased
diluted earnings by $.01 per share.
In
December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities
Exchange Act of 1934 to facilitate the repurchase of its shares of common
stock.
Rule 10b5-1 allows a company to purchase its shares at times when it would
not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. In addition
to
share repurchases by the Rule 10b5-1 plan, Berry expects to continue repurchases
in the open market from time to time during its normal trading windows. This
10b5-1 plan is authorized under, and is administered consistent with, the
Company's $50 million share repurchase program. All repurchases of common
stock
are made in compliance with regulations set forth by the SEC and are subject
to
market conditions, applicable legal requirements and other factors.
This
program does not obligate the Company to acquire any particular amount of
common
stock and the plan may be suspended at any time at the Company's
discretion.
Issuer
Purchases of Equity Securities
|
Period
|
(a)
Total number of shares purchased
|
(b)
Average price paid per share
|
(c)
Total number of shares purchased as part of publicly announced
plans or
programs
|
(d)
Maximum number (or approximate dollar value) of shares that may
yet be
purchased under the plans or programs
|
||||
|
Third
Quarter 2005
|
43,900
|
$58.48
|
|
43,900
|
|
$47,433,000
|
||
|
November
2005
|
16,300
|
57.25
|
|
16,300
|
|
46,500,000
|
||
|
December
2005
|
48,700
|
57.80
|
|
48,700
|
|
43,684,500
|
||
|
Total
|
|
108,900
|
|
$57.99
|
|
108,900
|
|
$43,684,500
|
The
following table sets forth certain financial information with respect to
the
Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8
Financial Statements and Supplementary Data. The statement of income and
balance
sheet data included in this table for each of the five years in the period
ended
December 31, 2005 were derived from the audited financial statements and
the
accompanying notes to those financial statements (in thousands, except per
share, per BOE and % data).
|
|
|
2005
|
|
2004
(3)
|
|
2003
(3)
|
|
2002
(1) (3)
|
|
2001
(1) (3)
|
|
|||||
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Statement
of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Sales
of oil and gas
|
|
$
|
349,691
|
|
$
|
226,876
|
|
$
|
135,848
|
|
$
|
102,026
|
|
$
|
100,146
|
|
|
Sales
of electricity
|
|
|
55,230
|
|
|
47,644
|
|
|
44,200
|
|
|
27,691
|
|
|
35,133
|
|
|
Operating
costs - oil and gas production
|
|
|
99,066
|
|
|
73,838
|
|
|
57,830
|
|
|
41,108
|
34,605
|
|
||
|
Operating
costs - electricity generation
|
|
|
55,086
|
|
|
46,191
|
|
|
42,351
|
|
|
26,747
|
|
|
36,890
|
|
|
Production
taxes
|
11,506
|
6,431
|
3,097
|
2,907
|
2,479
|
|||||||||||
|
General
and administrative expenses (G&A)
|
|
|
21,396
|
|
|
22,504
|
|
|
14,495
|
|
|
10,417
|
|
|
9.748
|
|
|
Depreciation,
depletion & amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production
|
|
|
38,150
|
|
|
29,752
|
|
|
17,258
|
|
|
13,388
|
|
|
13,225
|
|
|
Electricity
generation
|
|
|
3,260
|
|
|
3,490
|
|
|
3,256
|
|
|
3,064
|
|
|
3,295
|
|
|
Net
income
|
|
|
112,356
|
|
|
69,187
|
|
|
32,363
|
|
|
29,210
|
|
|
20,985
|
|
|
Basic
net income per share
|
|
|
5.10
|
|
|
3.16
|
|
|
1.49
|
|
|
1.34
|
|
|
0.96
|
|
|
Diluted
net income per share
|
|
|
5.00
|
|
|
3.08
|
|
|
1.47
|
|
|
1.33
|
|
|
0.95
|
|
|
Weighted
average number of shares outstanding (basic)
|
|
|
22,041
|
|
|
21,894
|
|
|
21,772
|
|
|
21,741
|
|
|
21,973
|
|
|
Weighted
average number of shares outstanding (diluted)
|
|
|
22,490
|
|
|
22,470
|
|
|
22,031
|
|
|
21,902
|
|
|
22,162
|
|
|
Balance
Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital
|
|
$
|
(54,757
|
)
|
$
|
(3,840
|
)
|
$
|
(3,540
|
)
|
$
|
(2,892
|
)
|
$
|
6,314
|
|
|
Total
assets
|
|
|
635,051
|
|
|
412,104
|
|
|
340,377
|
|
|
259,325
|
|
|
238,779
|
|
|
Long-term
debt
|
|
|
75,000
|
|
|
28,000
|
|
|
50,000
|
|
|
15,000
|
|
|
25,000
|
|
|
Shareholders'
equity
|
|
|
334,210
|
|
|
263,086
|
|
|
197,338
|
|
|
172,774
|
|
|
153,590
|
|
|
Cash
dividends per share
|
|
|
0.60
|
|
|
0.52
|
|
|
0.47
|
|
|
0.40
|
|
|
0.40
|
|
|
Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
|
187,780
|
|
|
124,613
|
|
|
64,825
|
|
|
57,895
|
|
|
35,433
|
|
|
Exploration
and development of oil and gas properties
|
|
|
118,718
|
|
|
71,556
|
|
|
41,061
|
|
|
30,163
|
|
|
14,776
|
|
|
Property/facility
acquisitions
|
|
|
112,249
|
|
|
2,845
|
|
|
48,579
|
|
|
5,880
|
|
|
2,273
|
|
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
11,762
|
669
|
494
|
469
|
119
|
|
||||||||
|
Unaudited
Operating Data
|
|
|
||||||||||||||
|
Oil
and gas producing operations (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
47.01
|
|
$
|
33.64
|
|
$
|
24.48
|
|
$
|
20.11
|
|
$
|
19.63
|
|
|
Average
sales price after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
|
19.79
|
|
|
Average
operating costs - oil and gas production
|
|
|
11.79
|
|
|
10.09
|
|
|
9.57
|
|
|
7.83
|
|
|
6.86
|
|
|
Production
taxes
|
1.37
|
.86
|
.51
|
.55
|
.49
|
|||||||||||
|
G&A
|
|
|
2.55
|
|
|
2.99
|
|
|
2.40
|
|
|
1.98
|
|
|
1.93
|
|
|
DD&A
- oil and gas production
|
|
|
4.54
|
|
|
3.96
|
|
|
2.86
|
|
|
2.55
|
|
|
3.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
(MBOE)
|
|
|
8,401
|
|
|
7,517
|
|
|
6,040
|
|
|
5,251
|
|
|
5,044
|
|
|
Production
(MMWh)
|
|
|
741
|
|
|
776
|
|
|
767
|
|
|
748
|
|
|
483
|
|
|
Proved
Reserves Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
BOE
|
|
|
126,285
|
|
|
109,836
|
|
|
109,920
|
|
|
101,719
|
|
|
102,855
|
|
|
Standardized
measure (2)
|
|
$
|
1,251,380
|
|
$
|
686,748
|
|
$
|
528,220
|
|
$
|
449,857
|
|
$
|
278,453
|
|
|
Year-end
average BOE price for PV10 purposes
|
|
|
48.21
|
|
|
29.87
|
|
|
25.89
|
|
|
24.91
|
|
|
14.13
|
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average shareholders' equity
|
|
|
37.63
|
%
|
|
31.06
|
%
|
|
17.50
|
%
|
|
17.90
|
%
|
|
14.00
|
%
|
|
Return
on average total assets
|
|
|
20.15
|
%
|
|
18.60
|
%
|
|
10.80
|
%
|
|
11.70
|
%
|
|
8.80
|
%
|
(1)
Information has been revised to reflect the Company's change in allocation
of
cogeneration costs to oil and gas operations. See Item 7 Management’s Discussion
and Analysis.
(2)
See Supplemental Information About Oil & Gas Producing
Activities.
(3)
Information has been revised to reflect the Company's change in allocation
of
technical labor and production taxes. See Note 2 to the financial
statements.
Corporate
Strategy.
Berry’s
mission is to increase shareholder value, primarily through increasing the
net
asset value and maximizing the cash flow and earnings of its assets. The
strategies to accomplish these goals include:
| · |
Growing
production and reserves from existing assets while managing
expenses
|
| · |
Acquiring
more light oil and natural gas assets with significant growth potential
in
the Rocky Mountain and Mid-Continent
region
|
| · |
Appraising
our exploitation and exploration projects in an expedient
manner
|
| · |
Investing
our capital in an efficient, disciplined manner to increase production
and
reserves
|
| · |
Utilizing
joint ventures with respected partners to enter new
basins
|
Notable
Items in 2005.
| · |
Achieved
record production which averaged 23,015 BOE/D, up 12% from
2004
|
| · |
Achieved
record cash from operating activities of $188 million, up 50% from
2004
|
| · |
Achieved
record net income of $112 million, up 62% from
2004
|
| · |
2005
developmental capital expenditures were $131 million, up 82% from
2004
|
| · |
Acquired
and integrated the eastern Colorado Niobrara natural gas producing
assets
- acquisition cost of $105 million
|
| · |
Added
24.9 million BOE of reserves before production ending 2005 at 126.3
million BOE
|
| · |
Achieved
reserve replacement rate of 296%
|
| · |
Negotiated
new four-year crude oil sales contract for California heavy oil
production
|
| · |
Observed
positive results on Diatomite play and expanded
pilot
|
| · |
Placed
price collars on 10,000 barrels per day of future production from
2006
through 2009
|
| · |
Added
approximately 186,000 gross (46,000 net) acres in the North Dakota
Bakken
play
|
| · |
Added
approximately 624,000 gross (315,000 net) acres to Tri-State area
inventory
|
| · |
Increased
quarterly dividend to $.13 per share and paid special dividend
of $.10 per
share for total payout of $.60 per
share
|
| · |
Began
drilling to assess several prospects including Lake Canyon, Coyote
Flats
and Tri-State area
|
| · |
Increased
financial capacity by establishing a $500 million unsecured credit
facility
|
| · |
Initiated
a $50 million share buyback program
|
Acquisitions. On
January 27, 2005, we acquired certain interests in the Niobrara fields in
northeastern Colorado for approximately $105 million. At December 31, 2005
the
properties consist of approximately 127,000 gross (100,000 net) acres.
Production at acquisition was approximately 9 MMcf of natural gas per day,
with
estimated proved reserves of 87 Bcf. For the month of December 2005, production
averaged approximately 13,800 MMcf per day and reserves were 105 Bcf. The
acquisition included approximately 200 miles of a pipeline gathering system
and
gas compression facilities for delivery into interstate gas lines.
In
January 2005, we acquired a working interest in eastern Colorado, western
Kansas
and southwestern Nebraska, from an industry partner. Berry and its partner,
will
jointly explore and develop shallow Niobrara natural gas, Sharon Springs
shale
gas and deeper Pennsylvanian formation oil assets on the acreage. We paid
approximately $5 million for our working interest in the acreage and believe
the
potential of the Tri-State area can be exploited by using new drilling
techniques, with 3-D seismic technology, to assess structural complexity,
estimate potentially recoverable oil and gas and determine drilling locations.
In
2005,
we completed several transactions whereby we now have working interests in
186,000 gross acres (46,000 net) located in the Williston Basin in North
Dakota.
These lease acquisitions, totaling approximately $11 million, provide us
an
entry into the emerging Bakken oil play in the Williston Basin. The acreage
covers several contiguous blocks located primarily on the eastern flank of
the
Nesson Anticline. Development activity in the Middle Bakken play is generally
expanding to the area surrounding the Nesson Anticline.
In
October 2005, we purchased a 50% working interest in approximately 69,000
gross
undeveloped acres (24,000 net) in Colorado’s Phillips and Sedgwick Counties.
This additional Niobrara leasehold position is adjacent to and immediately
north
of Berry’s producing natural gas assets in Yuma County. We expect to begin
shooting a 3-D seismic survey and drilling the first delineation wells in
2006.
On
January 27, 2006, we announced an agreement with a private seller to acquire
a
50% working interest in natural gas assets in the Piceance Basin of western
Colorado for approximately $150 million in cash. Berry internally estimates
there are 26 billion cubic feet (Bcf) of proved reserves and has identified
over
600 drilling locations based on 10-acre development. We will be the operator
in
the 6,314 gross acres targeting gas in the Williams Fork section of the
Mesaverde formation. We increased the 2006 capital budget by an additional
$48
million to $208 million to develop this resource. There are two drilling
rigs
dedicated to this project, and we will ramp up our drilling activity to four
rigs by the end of the year along with complementary services and goods to
accelerate the development of this acquisition. Based on the productivity
of
this acreage and surrounding producing operations, we are seeking to add
additional drilling rigs to accelerate development. The transaction closed
on
February 28, 2006.
Capital
Expenditures. Excluding
any future acquisitions, in 2006 we plan to spend approximately $208 million.
These expenditures will be directed toward developing reserves, increasing
oil
and gas production and exploration opportunities. For 2006, Berry plans to
invest approximately $146 million, or 70%, in our Rocky Mountain and
Mid-Continent region assets, and $61 million, or 30%, in our California assets.
Approximately half the capital budget is focused on converting probable and
possible reserves into proved reserves and on our appraisal and exploratory
projects.
This
robust capital program allows Berry to continue its record activity levels
by
planning to drill 476 net wells and perform 55 well workover activities in
2006
versus approximately 188 wells and 140 well workovers in 2005. As a result,
we
are targeting production growth of 12% to average approximately 25,800 BOE
per
day, which includes the Piceance Basin acquisition, but before any other
acquisitions, and we plan to continue to actively appraise significant acreage
positions held for hydrocarbon potential. In 2006, we expect production to
be
approximately 70% heavy oil, 15% light oil and 15% natural gas and anticipate
funding our capital program from internally generated cash flow. Successes
may
also encourage the initiation of additional discretionary projects. We have
currently secured the necessary equipment and are meeting permit requirements
to
achieve the 2006 program.
Appraisal,
Evaluation and Exploitation Activity. Since
2003, we have been active in assembling significant acreage positions which
we
believe are highly prospective for finding and developing commercial quantities
of hydrocarbons. This chart depicts our prospective acreage by basin, all
of
which is in the Rocky Mountain and Mid-Continent region:
Rocky
Mountain and Mid-Continent
We
plan
to appraise five project areas in this region in 2006 for an estimated $23
million budgeted. These five projects are Lake Canyon, Coyote Flats, Big
Wash
Unit, Tri-State Area and the Bakken Play. We have interests in over one million
gross acres, including both productive and prospective, in the Rocky Mountain
and Mid-Continent region and the acreage in the five appraisal projects accounts
for about 80% of that total.
Uinta
Basin Projects
Lake
Canyon - Shallow: On January 13, 2006, we announced commercial success from
our
first two wells on this acreage. The Nielsen Marsing and Taylor Herrick wells
have tested production rates of 98 and 163 BOE/D, respectively, from the
same
Green River formation that is productive immediately east (approximately
3
miles) in our Brundage Canyon field. Initial performance from these discovery
wells suggests that expected reserves per well are on par with the Brundage
Canyon field (approximately 80,000 BOE gross) that is currently being developed
on 40-acre spacing. Current production from the Taylor Herrick well is not
at
full capacity as additional facilities are in the process of being installed.
Production from the Nielsen Marsing well is selectively limited to two of
five
completion intervals within the well and will be further optimized by March
2006
when natural gas facilities are completed. We are proceeding with another
four
wells on the eastern edge of this 169,000 acre block. If the results of these
wells are deemed satisfactory, Berry will expand the drilling program and
attempt to drill up to another 30 wells over approximately 20,000 acres.
The
focus will be to begin the methodical appraisal of a sizeable portion of
this
acreage block. Berry’s working interest in these wells will be either 75% or
56.25% depending on the participation of the land owner. The shallow zones
are
those above the Wasatch which is at approximately 6,500 feet.
Lake
Canyon - Deep: Berry’s industry partner recently reached total depth of 14,325
feet on its Mesaverde test and set casing to a depth of 11,539 feet. Testing
will focus on several Upper Price River and shallower Wasatch intervals where
analysis indicates gas potential; the deeper Mesaverde and Blackhawk intervals
did not warrant further evaluation. Berry will participate with its industry
partner to complete the testing and evaluation of the first deep well on
the
acreage once pipeline construction into the area is completed, which is
currently targeted by May 1, 2006. The second well is scheduled to begin
drilling in the fourth quarter of 2006.
Coyote
Flats: We will continue to test the viability of the Ferron gas development
and
Emery CBM pilot with additional drilling.
Big
Wash
Unit: We will test the shallow oil and deeper gas potential located about
two
miles southeast of Brundage Canyon.
Denver-Julesburg
Basin Projects
Tri-State
Area: We will be very active in testing the Niobrara gas potential located
in
the Tri-State area of Colorado, Kansas and Nebraska. We will participate
in 16
exploratory gas wells, drill 11 development wells and acquire additional
3D
seismic. Immediately to the north of our producing assets in Yuma County,
Colorado, we may drill up to 17 wells based on the acquisition of new seismic
data covering the northern acreage.
Williston
Basin Projects
Bakken
Play: In North Dakota, we intend to participate with up to a 15% working
interest in at least four horizontal oil wells to appraise the prospective
oil
formation.
California-Diatomite
In
2005,
oil production from the initial 14 well pilot (6 producers) averaged
approximately 135 Bbl/D.
Based on promising results from the pilot project, we began an expansion
of the
pilot with a 25 well program (15 producers) in the third quarter of 2005,
and
completed it in the fourth quarter. We continue to assess the long-term economic
and operating viability of the project as the early wells are an indication
of
future large-scale development. Results are in accordance with expectations.
We
are judiciously monitoring the steam to oil ratio (SOR) because we believe
achieving an SOR of 6 or less is the threshold for commerciality. SOR measures
how much steam is required for injection into the reservoir to produce one
barrel of oil. Estimated original oil in place ranges between 200 million
to 250
million barrels with targets of a minimum 25% recovery of original oil in
place.
In 2005, we booked 2.5 million BOE of reserves based on asset performance.
We
believe that the project continues to remain on track towards
commerciality.
In
2006,
we are expanding the commercial test of our diatomite resource by investing
approximately $25 million in a program that will add another 50 wells (31
producers, 16 steam injectors, and 3 service wells). Since completing our
expansion of the initial pilot in December 2005, we now have a total of 39
wells
(21 producers, 15 steam injectors, and 3 service wells) that we will be using
to
monitor reservoir performance. In addition to the drilling program, we will
add
significant facilities including steam generation equipment and will be
optimizing the pattern configuration and layout for the eventual full-field
development if commerciality is determined.
Development
Activity
Rocky
Mountain and Mid-Continent
Approximately
$93 million will be invested in this region, with $58 million targeting the
continued development drilling of the Green River formation at Brundage Canyon
to assist full development and will include a 20-acre spacing pilot. In
northeastern Colorado, $17 million will be invested to acquire additional
seismic data and drill 150 wells to further develop the Niobrara natural
gas
production from our producing assets.
California
Berry
will invest $37 million in its heavy oil properties, utilizing horizontal
well
and new steam-optimization technologies to maximize recovery from our legacy
assets. Development activity at our Poso Creek, Ethel D and Midway-Sunset
assets
will utilize improved application of steam flood technology to provide
production growth.
See
Item
1 Business for more information on Development Activity.
Obstacles
and Risks to Accomplishment of Strategies and Goals.
See Item
1A Other Factors Affecting the Company's Business and Financial Results for
a
detailed discussion of factors that affect our business, financial condition
and
results of operations.
Results
of Operations. Approximately
86% of Berry's revenues are generated through the sale of oil and natural
gas
production under either negotiated contracts or spot gas purchase contracts
at
market prices. Over 83% of these volumes are from oil production, and the
majority of those volumes are from heavy oil production in California. The
remaining 14% of Berry's revenues are derived from electricity sales from
cogeneration facilities which supply over half of Berry’s steam requirement for
use in its 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.
Revenues.
Sales of
oil and gas were up 54% in 2005 compared to 2004 and up 157% from 2003. This
significant improvement was due to increases in both oil and gas prices and
production levels.
 |
Improvements
in production volume are due to acquisitions and sizable capital
investments. Improvement in prices during 2005 are due to a tighter
supply
and demand balance and the nervousness of the market about possible
supply
disruptions. The increase in oil prices contributed roughly two-thirds
of
the revenue increase and the increase in production volumes contributed
the other third. Approximately 84% of Berry’s oil and gas sales volumes in
2005 were crude oil, with 78% of the crude oil being heavy oil
produced in
California which was sold under a contract based on the higher
of WTI
minus a fixed differential or the average posted price plus a premium.
This contract ended on January 31, 2006. The contract allowed us
to
improve our California revenues over the posted price by approximately
$38
million and $13 million in 2005 and 2004, respectively.
On
November 21, 2005, we entered into a new crude oil sales contract
for our
California production for deliveries beginning February 1, 2006.
The per
barrel price, calculated on a monthly basis and blended across
the various
producing locations, is the higher of 1) the WTI NYMEX crude oil
price
less a fixed differential approximating $8.15, or 2) heavy oil
field
postings plus a premium of approximately $1.35. The initial term
of the
contract is for four years with a one-year renewal at our option.
The
agreement effectively eliminates our exposure to the risk of a
widening
WTI to California heavy crude price differential and allows us
to
effectively hedge our production based on WTI pricing similar to
the
previous contract. Initial deliveries under the contract are
approximately 15,000 net barrels per day or approximately two-thirds
of
Berry's total production.
|
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
sold under contract at WTI less a fixed differential approximating $2.00
per
barrel. This contract expires on September 30, 2006. Any new contract will
be
negotiated based on market prices. We believe the differential has widened
by
several dollars per barrel. The majority of this crude oil, while light,
is a
“paraffinic” crude, and can be processed efficiently by only a limited number
of stranded inland refineries. The production of this type crude is
increasing regionally and beginning to strain the capacity of these refineries.
Other new crude sources from the region are pressuring pricing. If these
refineries limit the volumes of this parraffinic crude oil they are willing
to
process, it could impact the marketability of this type of crude which, for
Berry, represents approximately 3,500 Bbl/D of production or approximately
15%
of total current production. We are investigating the market opportunities
for
this crude oil. If market prices continue to deteriorate,
we may
allocate capital expenditures to projects which produce natural gas and crude
oils with lower paraffinic content until the refinery constraint is
resolved.
The
following companywide results are in millions (except per share data) for
the
years ended December 31:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Sales
of oil
|
$
|
289
|
$
|
210
|
$
|
130
|
||||
|
Sales
of gas
|
61
|
17
|
6
|
|||||||
|
Total
sales of oil and gas
|
$
|
350
|
$
|
227
|
$
|
136
|
||||
|
Sales
of electricity
|
55
|
|
48
|
44
|
|
|||||
|
Interest
and other income, net
|
2
|
|
-
|
1
|
|
|||||
|
Total
revenues and other income
|
$
|
407
|
|
$
|
275
|
$
|
181
|
|
||
|
Net
income
|
$
|
112
|
|
$
|
69
|
$
|
32
|
|
||
|
Earnings
per share (diluted)
|
$
|
5.00
|
$
|
3.08
|
$
|
1.47
|
||||
 |
 |
Reserve
Replacement Rate.
The
reserve replacement rate is calculated by dividing total new proved reserves
added for the year by total production for the year. This measure is important
because it is an indication of growth in proved reserves of the Company and,
thus may impact the value of the Company. We believe our calculation of this
measure is substantially similar to how other companies compute reserve
replacement rate.
Hedging.
See Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Operating
data.
The
following table is for the years ended December 31:
|
|
|
2005
|
%
|
2004
|
%
|
2003
|
%
|
|||
|
Oil
and Gas
|
|
|
|
|
|
|
||||
|
Heavy
Oil Production (Bbl/D)
|
16,063
|
70
|
15,901
|
77
|
15,477
|
94
|
||||
|
Light
Oil Production (Bbl/D)
|
3,336
|
14
|
3,345
|
16
|
489
|
3
|
||||
|
Total
Oil Production (Bbl/D)
|
|
|
19,399
|
84
|
|
19,246
|
93
|
|
15,966
|
97
|
|
Natural
Gas Production (Mcf/D)
|
|
|
21,696
|
16
|
|
7,752
|
7
|
|
3,499
|
3
|
|
Total
(BOE/D)
|
|
|
23,015
|
100
|
|
20,537
|
100
|
|
16,549
|
100
|
|
Percentage
increase from prior year
|
12%
|
24%
|
15%
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
47.01
|
|
$
|
33.64
|
|
$
|
24.48
|
|
|
Average
sales price after hedging
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
||||||||||
|
Average
WTI price
|
$
|
56.70
|
$
|
39.21
|
$
|
31.16
|
||||
|
Price
sensitive royalties
|
(4.42
|
)
|
(2.78
|
)
|
(1.79
|
)
|
||||
|
Gravity
differential
|
(5.22
|
)
|
(4.93
|
)
|
(2.97
|
)
|
||||
|
Crude
oil hedges
|
(6.21
|
)
|
(2.93
|
)
|
(2.03
|
)
|
||||
|
Average
oil sales price after hedging
|
$
|
40.85
|
$
|
28.57
|
$
|
24.37
|
||||
|
Gas,
per MMBtu:
|
||||||||||
|
Average
Henry Hub price
|
$
|
8.05
|
$
|
6.13
|
$
|
5.11
|
||||
|
Natural
gas hedges
|
(.11
|
)
|
(.01
|
)
|
.02
|
|||||
|
Location
and quality differentials
|
(1.45
|
)
|
(.63
|
)
|
(.81
|
)
|
||||
|
Average
gas sales price after hedging
|
$
|
6.49
|
$
|
5.49
|
$
|
4.32
|
||||
Electricity. Berry
consumes natural gas as fuel to operate its three cogeneration facilities
which
are intended to provide an efficient and secure long-term supply of steam
necessary for the economic production of heavy oil. We sell our electricity
to
utilities under Standard Offer contracts, under which our revenues are linked
to
the cost of natural gas. Natural gas index prices are the primary determinant
of
Berry’s electricity sales price. The correlation between electricity sales and
natural gas prices allows us to more effectively manage our cost of producing
steam. Revenue and operating costs in the year ended 2005 were up from the
year
ended 2004 due to 18% higher electricity prices and 34% higher natural gas
prices, respectively. We purchased approximately 38 MMBtu/D as fuel for use
in
our cogeneration facilities in the year ended December 31, 2005.
|
|
|
2005
|
2004
|
2003
|
|
|||||
|
Electricity
|
||||||||||
|
Revenues
(in millions)
|
$
|
55.2
|
$
|
47.6
|
$
|
44.2
|
||||
|
Operating
costs (in millions)
|
$
|
55.1
|
$
|
46.2
|
$
|
42.4
|
||||
|
Decrease
to total oil and gas operating expenses-per barrel
|
$
|
.02
|
$
|
.19
|
$
|
.32
|
||||
|
Electric
power produced - MWh/D
|
|
|
2,030
|
|
|
2,121
|
|
|
2,100
|
|
|
Electric
power sold - MWh/D
|
|
|
1,834
|
|
|
1,915
|
|
|
1,925
|
|
|
Average
sales price/MWh before hedging
|
|
$
|
82.73
|
|
$
|
70.24
|
|
$
|
62.91
|
|
|
Average
sales price/MWh after hedging
|
|
$
|
82.73
|
|
$
|
70.24
|
|
$
|
61.95
|
|
|
Fuel
gas cost/MMBtu (after hedging and excluding
transportation)
|
|
$
|
7.30
|
|
$
|
5.46
|
|
$
|
4.88
|
|
Royalties.
A
price-sensitive royalty burdens a portion of our Midway-Sunset California
property which produces approximately 3,800 barrels per day. This royalty
is 75%
of the amount of the heavy oil posted price above a base price which was
$15.18
in 2005. This base price escalates at 2% annually, thus the threshold price
is
$15.48 per barrel in 2006. Amounts paid were $29 million, $19.3 million and
$10.2 million in the years ended December 31, 2005, 2004 and 2003, respectively.
Accounts payable associated with this royalty at year end 2005 was $29 million.
Because our interest in the revenue varies according to crude prices, the
continuing development on this property will depend on its future profitability.
A
second
price sensitive royalty burdens approximately 700 barrels per day at our
Placerita field in California. This royalty is calculated when the sales
price
exceeds $26 per barrel up to a maximum. The royalty was $2.8 million, $1.4
million and $.3 million in the years ended December 31, 2005, 2004 and 2003,
respectively. The maximum amount of the royalty over its life is $5 million,
thus, we expect this royalty payable will end in the first quarter of
2006.
In
2005,
the Bureau of Land Management revoked their royalty exemption for certain
heavy
oil properties. This resulted in a reduction to Berry of .9 million barrels
of
reserves and approximately 100 BOE/D in the fourth quarter of 2005. In December
2004, certain royalty owners exercised their right to convert their royalty
interest into a working interest on our Formax property in the Midway-Sunset
field. This resulted in a reduction of 1.8 million barrels of reserves and
represented approximately 450 BOE/day as of December 31, 2004.
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
We
believe that the most informative way to analyze changes in recurring operating
expenses from one period to another is on a per unit-of-production, or BOE,
basis. The following table presents information about our operating expenses
for
each of the years in the two-year period ended December 31, 2005:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
|
2005
|
|
2004
|
|
Change
|
|
2005
|
|
2004
|
|
Change
|
|
||||||
|
Operating
costs - oil and gas production
|
|
$
|
11.79
|
|
$
|
10.09
|
|
|
17
|
%
|
$
|
99,066
|
|
$
|
73,838
|
|
|
34
|
%
|
|
Production
taxes
|
1.37
|
.86
|
59
|
%
|
11,506
|
6,431
|
79
|
%
|
|||||||||||
|
DD&A
- oil and gas production
|
|
|
4.54
|
|
|
3.96
|
|
|
15
|
%
|
|
38,150
|
|
|
29,752
|
|
|
28
|
%
|
|
G&A
|
|
|
2.55
|
|
|
2.
99
|
|
|
(15)
|
%
|
|
21,396
|
|
|
22,504
|
|
|
(5)
|
%
|
|
Interest
expense
|
|
|
0.72
|
|
|
0.27
|
|
|
167
|
%
|
|
6,048
|
|
|
2,067
|
|
|
193
|
%
|
|
Total
|
|
$
|
20.97
|
|
$
|
18.17
|
|
|
15
|
%
|
$
|
176,166
|
|
$
|
134,592
|
|
|
31
|
%
|
Our
total
operating costs, production taxes, G&A and interest expenses for 2005,
stated on a unit-of-production basis, increased 15% over 2004. The changes
were
primarily related to the following items:
| · |
Operating
costs: Higher crude oil and natural gas prices have created an
incentive
for the U.S. domestic oil and gas industry to significantly increase
exploration and development activities, which is straining the
capacity
for goods and services that support our industry. Thus, higher
costs are
prominent throughout the industry and resulted in higher operating
costs
per BOE for the year ended 2005 as compared to 2004. Costs in California
were also higher due to increased well servicing activities and
increases
in steam costs. The cost of Berry’s steaming operations on our heavy oil
properties represents a significant portion of our operating costs
and
will vary depending on the cost of natural gas used as fuel and
the volume
of steam injected. The following table presents steam information:
|
|
2005
|
2004
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
70,032
|
69,200
|
1%
|
|
|
Fuel
gas cost/MMBtu
|
$7.30
|
$5.46
|
34%
|
|
As
commodity prices remain robust, we anticipate that cost pressures within
our
industry may continue. Natural gas prices impact our cost structure in
California by approximately $1.75 per California BOE for each $1.00 move
in
natural gas price. The California production target for 2006 is 16,700
BOE/D.
| · |
Production
taxes: Higher prices, such as those exhibited in 2005, create increased
production taxes.
|
| · |
Depreciation,
depletion and amortization: DD&A increased per BOE in the year ended
2005 from the year ended 2004 due to higher acquisition costs of
our Rocky
Mountain and Mid-Continent region assets as compared to our legacy
heavy
oil assets in California and higher finding and development costs.
As
these costs increase, our DD&A rates per BOE will also increase.
|
| · |
General
and administrative: Approximately two-thirds of Berry’s G&A is
compensation or compensation related costs. We intend to remain
competitive in workforce compensation to achieve our growth plans.
Stock-based compensation expense was $.35 per BOE and $.56 per
BOE for the
years ended December 31, 2005 and 2004, respectively. Compensation
expenses increased due to increased staffing resulting from our
growth,
and increases in compensation levels and bonuses. Additionally,
we
incurred increased legal and accounting fees, primarily due to
compliance
with Sarbanes-Oxley, and growth through acquisitions and other
financial
reporting related matters. Legal and accounting expenses were $.28
per BOE
in 2005 as compared to $.23 per BOE in
2004.
|
| · |
Interest
expense: We increased our outstanding borrowings to $75 million
at
December 31, 2005 as compared to $28 million at December 31, 2004.
Average
borrowings increased as a result of acquisitions of $112 million
during
2005. Additionally, interest rates have increased by approximately
1.75%
since December 31, 2004.
|
The
following table presents information about our operating expenses for each
of
the years in the two-year period ended December 31, 2004:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
2004
|
|
2003
|
|
Change
|
|
2004
|
|
2003
|
|
Change
|
|
||||||
|
Operating
costs - oil and gas production
|
|
$
|
10.09
|
|
$
|
9.57
|
|
|
5
|
%
|
$
|
73,838
|
|
$
|
57,830
|
|
|
28
|
%
|
|
Production
taxes
|
.86
|
.51
|
69
|
%
|
6,431
|
3,097
|
108
|
%
|
|||||||||||
|
DD&A
- oil and gas production
|
|
|
3.96
|
|
|
2.86
|
|
|
38
|
%
|
|
29,752
|
|
|
17,258
|
|
|
72
|
%
|
|
G&A
|
|
|
2.99
|
|
|
2.40
|
|
|
25
|
%
|
|
22,504
|
|
|
14,495
|
|
|
55
|
%
|
|
Interest
expense
|
|
|
0.27
|
|
|
0.23
|
|
|
17
|
%
|
|
2,067
|
|
|
1,414
|
|
|
46
|
%
|
|
Total
|
|
$
|
18.17
|
|
$
|
15.57
|
|
|
17
|
%
|
$
|
134,592
|
|
$
|
94,094
|
|
|
43
|
%
|
Our
total
operating, production taxes, G&A and interest expenses for 2004, stated on a
unit-of-production basis, increased 17% over 2003. The changes were primarily
related to the following items:
· Operating
costs: 2004, on a per barrel basis, increased over 2003 due primarily to
higher
steam costs. The cost of Berry's steaming operations for its heavy oil
properties represents a significant portion of our operating costs
and will vary depending on both the cost of natural gas used as fuel and
the
volume of steam injected during the year. The following table presents steam
information:
|
2004
|
2003
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
69,200
|
63,300
|
9%
|
|
|
Fuel
gas cost/MMBtu
|
$5.46
|
$4.88
|
12%
|
· Depreciation,
depletion and amortization: 2004 was higher due to higher finding and
development costs, the shorter reserve life of our Brundage Canyon properties
in
Utah and the cumulative effect of increased development activities in recent
years. We expect DD&A to trend higher over the next few years due to the
shorter reserve life of the Rocky Mountain assets compared to our California
properties and continued development of our California and Rocky Mountain
properties.
· General
and administrative: 2004 was up from 2003 due to stock-based compensation
costs
increasing by $2.8 million in 2004, or $.56 per BOE, which are primarily
non-cash charges resulting from marked-to-market adjustments under the variable
method of accounting prior to the change of certain exercise provisions of
our
stock option plan on July 29, 2004 and non-cash compensation expense under
the
fair value method of accounting. Compensation expenses increased due to
increased staffing resulting from our growth, an increase in compensation
levels
and bonuses and costs related to a change in chief executive officers.
Additionally, we incurred increased legal and accounting fees during 2004,
primarily due to compliance with Sarbanes-Oxley and other financial reporting
related matters.
· Interest
expense: 2004 was up from 2003. Although our borrowings at year-end 2004
were
$28 million, down from $50 million in 2003, we borrowed $40 million in August
2003 to fund the acquisition of our Brundage Canyon property. We reduced
our
debt from 2003 levels during the latter half of 2004.
Estimated
2006 Oil and Gas Operating, G&A and Interest
Expenses
|
|
Amount
per BOE
|
|
||||||||
|
|
|
Anticipated
|
|
|
|
|||||
|
|
|
range
in 2006
|
|
2005
|
|
2004
|
||||
|
|
||||||||||
|
Operating
costs-oil and gas production (1)
|
$
|
13.00
to 16.00
|
|
$
|
11.79
|
|
$
|
10.09
|
||
|
Production
taxes
|
1.35
to 1.65
|
1.37
|
.86
|
|||||||
|
DD&A
|
|
|
5.75
to 6.50
|
|
|
4.54
|
|
|
3.96
|
|
|
G&A
|
|
|
2.75
to 3.00
|
|
|
2.55
|
|
|
2.99
|
|
|
Interest
expense
|
|
|
1.35
to 1.60
|
|
|
0.72
|
|
|
.27
|
|
|
Total
|
|
$
|
24.20
to 28.75
|
|
$
|
20.97
|
|
$
|
18.17
|
|
| (1) |
Assuming
natural gas prices of approximately NYMEX HH $8.50 MMBtu, we plan
to
inject steam at levels in 2006 comparable to, or slightly higher
than 2005
levels.
|
Dry
hole, abandonment and impairment. The
$5.7
million reflected on Berry’s income statement under dry hole, abandonment and
impairment is made up of the following three items:
| · |
At
December 31, 2004, we were in the process of drilling one exploratory
well
on our Midway-Sunset property and one exploratory well on our Coyote
Flats
prospect. These two wells were determined non-commercial in February
2005
and $2.2 million was incurred and expensed in 2005.
|
| · |
Two
exploratory wells at northern Brundage Canyon were expensed for
$.6
million.
|
| · |
Finally,
we impaired the remaining carrying value of our Illinois and eastern
Kansas prospective CBM acreage acquired in 2002 by $2.9 million.
|
Costs
of
$.7 million which were incurred on the Midway-Sunset property and the
exploratory well on the Coyote Flats prospect as of December 31, 2004 were
charged to expense. During 2003, we recorded a pre-tax write down of $4.2
million related to two CBM pilot projects.
Exploration
costs.
We
incurred exploration costs of $3.6 million in 2005 compared to zero costs
in
2004 and 2003. These costs consist primarily of geological and geophysical
costs. Berry participated in 3-D seismic surveys at Lake Canyon, Utah and
in the
Tri-State area. We are projecting exploration costs in 2006 of between $4
million and $6 million.
Income
Taxes.
The
Revenue Reconciliation Act of 1990 included a tax credit for certain costs
associated with extracting high-cost, capital-intensive marginal oil or gas
and
which utilizes at least one of nine designated "enhanced" or
tertiary recovery methods (EOR). Cyclic steam and steam flood recovery
methods for heavy oil, which Berry utilizes extensively, are qualifying EOR
methods. In 1996, California conformed to the federal law, thus, on a combined
basis, we are able to achieve credits approximating 12% of our qualifying
costs.
The credit is earned only for qualified EOR projects by investing in one
of
three types of expenditures: 1) drilling development wells, 2) adding facilities
that are integrally related to qualified EOR production, or 3) utilizing
a
tertiary injectant, such as steam, to produce oil. The credit may be utilized
to
reduce our tax liability down to, but not below, our alternative minimum
tax
liability. This credit has been significant through 2005 in reducing our
income
tax liabilities and effective tax rate. However, with higher crude oil prices
and the increasing investment in its light crude oil and natural gas properties,
Berry’s effective income tax rate trended higher in 2005 compared to prior
years. The average U.S. wellhead price for crude oil exceeded $43 in 2005,
thus
triggering a full phase-out of the EOR credit for 2006. If the U.S. wellhead
price of crude oil declines below the triggering point in future years, we
will
be able to claim the EOR credit on qualifying expenditures and our effective
tax
rate should decline. As of December 31, 2005 the Company has approximately
$23
million of federal and $17 million of state (California) EOR tax credit
carryforwards available to reduce future income taxes. The EOR credits will
begin to expire, if unused, in 2024 and 2015 for federal and California,
respectively.
We
experienced an effective tax rate of 31%, 23% and 12% reported in 2005, 2004
and
2003, respectively. The increase in effective tax rate during 2005 is primarily
due to a much higher (over 80%) pre-tax income in relation to consistent
EOR
credits in 2005 over 2004. Our expansion outside of California and investment
in
non-thermal projects are also key factors in the increase. We have been able
to
achieve an effective tax rate below the statutory tax rate of approximately
40%
through 2005 primarily as a result of significant EOR tax credits earned
by our
continued investment in the development of thermal EOR projects, both through
capital expenditures and continued steam injection. We expect our effective
tax
rate will be higher as the EOR credit will be non-existent for 2006 and possibly
later years, and we expect to have an effective tax rate in the 37% to 39%
range
in 2006, based on WTI prices averaging between $50 and $70. See Note 9 to
the
financial statements for further information.
Financial
Condition, Liquidity and Capital Resources. Substantial
capital is required to replace and grow reserves. We achieve reserve replacement
and growth primarily through successful development and exploration drilling
and
the acquisition of properties. Fluctuations in commodity prices have been
the
primary reason for short-term changes in our cash flow from operating
activities. The net long-term growth in our cash flow from operating activities
is the result of growth in production as affected by period to period
fluctuations in commodity prices.
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. Excess cash generated from operations is expected to be
applied toward acquisitions, debt reduction or other corporate purposes.
Excluding
any future acquisitions, in 2006 we plan to spend approximately $208 million
on
capital projects and anticipate funding these expenditures from internally
generated cash flow. These expenditures will be directed toward developing
reserves, increasing oil and gas production and exploration opportunities.
For
2006, Berry plans to invest approximately $146 million, or 70%, in our Rocky
Mountain and Mid-Continent region assets, and $61 million, or 30%, in our
California assets. Approximately half the capital budget is focused on
converting probable and possible reserves into proved reserves and on our
appraisal and exploratory projects. Total capital expenditures in 2005,
excluding acquisitions, were $119 million and included the drilling of
approximately 188 new wells and completing 140 workovers on our properties.
All
capital expenditures, excluding acquisitions, were funded out of internally
generated cash flow. See Item 1 Business for further details.
Dividends.
The
regular quarterly dividend was increased by 8%, from $.12 to $.13 per share,
beginning with the September 2005 dividend. The total dividend payable on
September 29, 2005 was $.23 per share which included a special $.10 per share
dividend. This is the third consecutive year that we have raised the quarterly
dividend and distributed a special dividend. This action resulted in a total
payout in 2005 of $.60 per share, up 16% from the $.52 per share paid out
in
2004 and up 28% from the $.47 per share paid out in 2003.
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 natural gas
prices increased in 2005 (see graphs on page 30) and we increased production
by
12%.
Our
working capital balance fluctuates as a result of the amount of borrowings
and
the timing of repayments under our credit arrangements. We used our long-term
borrowings under our 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. In 2005, the working
capital deficit was substantially greater than 2004. The deficit is primarily
made up of changes in the following four balance sheet accounts from 2005
as
compared to 2004; a $14.7 million decrease in cash, an $11 million increase
in
the Formax royalty payable, an $11.5 million increase in the short-term line
of
credit which is used to improve cash management and a $9 million increase
in
fair value of derivatives (net liability) which is associated with our increased
use of hedging in 2005.
The
table
below compares financial condition, liquidity and capital resources changes
for
the years ended December 31 (in millions, except for production and average
prices):
|
2005
|
2004
|
Change
|
|
|
Production
(BOE/D)
|
23,015
|
20,537
|
+12%
|
|
Average
oil and gas sales prices, per BOE after hedging
|
$
41.62
|
$
30.32
|
+37%
|
|
Net
cash provided by operating activities
|
$
188
|
$
125
|
+50%
|
|
Working
capital
|
$
(54.8)
|
$
(3.8)
|
(134)%
|
|
Sales
of oil and gas
|
$
350
|
$
227
|
+54%
|
|
Long-term
debt
|
$
75
|
$
28
|
+168%
|
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
231
|
$
85.3
|
+171%
|
|
Dividends
paid
|
$
13.2
|
$
11.4
|
+16%
|
In
June
2005, a share repurchase program was authorized for up to an aggregate of
$50
million of Berry's outstanding Class A Common Stock. Through December 31,
2005,
we had repurchased 108,900 shares for approximately $6.3 million. See Note
7 to
the financial statements.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15
to the
financial statements.
Credit
Facility. See
Note
6 to the financial statements for more information. We have a $500 million
unsecured credit facility, which has a current borrowing base of $350 million
and is an integral part of our financing structure that provides improved
access
to capital and the flexibility to support growth plans.
Contractual
Obligations. Refer
to
Note 10 to the financial statements.
Application
of Critical Accounting Policies. The
preparation of financial statements in conformity with generally accepted
accounting principles requires Management to make estimates and assumptions
for
the reporting period and as of the financial statement date. These estimates
and
assumptions affect the reported amounts of assets and liabilities, the
disclosure of contingent liabilities and the reported amounts of revenues
and
expenses. Actual results could differ from those amounts.
A
critical accounting policy is one that is important to the portrayal of the
Company's financial condition and results, and requires Management to make
difficult subjective and/or complex judgments. Critical accounting policies
cover accounting matters that are inherently uncertain because the future
resolution of such matters is unknown. The Company believes the following
accounting policies are critical policies.
Successful
Efforts Method of Accounting. The
Company accounts for its oil and gas exploration and development costs using
the
successful efforts method. Geological and geophysical costs and the costs
of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes.
All
exploratory wells are evaluated for economic viability within one year of
well
completion. Exploratory wells that discover potentially economic reserves
that
are in areas where a major capital expenditure would be required before
production could begin, and where the economic viability of that major capital
expenditure depends upon the successful completion of further exploratory
work
in the area, remain capitalized as long as the additional exploratory work
is
under way or firmly planned.
Oil
and Gas Reserves. Oil
and
gas reserves include proved reserves that represent estimated quantities
of
crude oil, natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. The
Company's oil and gas reserves are based on estimates prepared by independent
engineering consultants. Reserve engineering is a subjective process that
requires judgment in the evaluation of all available geological, geophysical,
engineering and economic data. Projected future production rates, the timing
of
future capital expenditures as well as changes in commodity prices may
significantly impact estimated reserve quantities. Depreciation, depletion
and
amortization (DD&A) expense and impairment of proved properties are impacted
by the Company's estimation of proved reserves. These estimates are subject
to
change as additional information and technologies become available. Accordingly,
oil and natural gas quantities ultimately recovered and the timing of production
may be substantially different than projected. Reduction in reserve estimates
may result in increased DD&A expense, increased impairment of proved
properties and a lower standardized measure of discounted future net cash
flows.
Carrying
Value of Long-lived Assets.
Downward revisions in the Company’s estimated reserve quantities, increases in
future cost estimates or depressed crude oil or natural gas prices could
cause
the Company to reduce the carrying amounts of its properties. The Company
performs an impairment analysis of its proved properties annually by comparing
the future undiscounted net revenue per the annual reserve valuation prepared
by
the Company’s independent reserve engineers to the net book carrying value of
the assets. An analysis of the proved properties will also be performed whenever
events or changes in circumstances indicate an asset’s carrying value may not be
recoverable from future net revenue. Assets are grouped at the field level
and
if it is determined that the net book carrying value cannot be recovered
by the
estimated future undiscounted cash flow, they are written down to fair value.
Cash flows used in the impairment analysis are determined based on Management’s
estimates of crude oil and natural gas reserves, future crude oil and natural
gas prices in effect at the end of the period and costs to extract these
reserves. For its unproved properties, the Company performs an impairment
analysis annually or whenever events or changes in circumstances indicate
an
asset’s net book carrying value may not be recoverable.
Derivatives
and Hedging. The
Company follows the provisions of Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting
for Derivative Instruments and Hedging Activities.
SFAS
133 requires the accounting recognition of all derivative instruments as
either
assets or liabilities at fair value. Derivative instruments that are not
hedges
must be adjusted to fair value through net income. Under the provisions of
SFAS
133, the Company may designate a derivative instrument as hedging the exposure
to change in fair value of an asset or liability that is attributable to
a
particular risk (a fair value hedge) or as hedging the exposure to variability
in expected future cash flows that are attributable to a particular risk
(a cash
flow hedge). Both at the inception of a hedge and on an ongoing basis, a
fair
value hedge must be expected to be highly effective in achieving offsetting
changes in fair value attributable to the hedged risk during the periods
that a
hedge is designated. Similarly, a cash flow hedge must be expected to be
highly
effective in achieving offsetting cash flows attributable to the hedged risk
during the term of the hedge. The expectation of hedge effectiveness must
be
supported by matching the essential terms of the hedged asset, liability
or
forecasted transaction to the
derivative
contract or by effectiveness assessments using statistical measurements.
The
Company's policy is to assess hedge effectiveness at the end of each calendar
quarter.
Income
Taxes. The
Company computes income taxes in accordance with SFAS No. 109, Accounting
for Income Taxes.
SFAS
No. 109 requires an asset and liability approach which results in the
recognition of deferred income taxes on the difference between the tax basis
of
an asset or liability and its carrying amount in the Company's financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered
or
settled, respectively. Considerable judgment is required in determining when
these events may occur and whether recovery of an asset is more likely than
not.
Additionally, the Company's federal and state income tax returns are generally
not filed before the financial statements are prepared, therefore the Company
estimates the tax basis of its assets and liabilities at the end of each
calendar year as well as the effects of tax rate changes, tax credits, and
tax
credit carryforwards. A valuation allowance is recognized if it is determined
that deferred tax assets may not be fully utilized in future periods.
Adjustments related to differences between the estimates used and actual
amounts
reported are recorded in the period in which income tax returns are filed.
These
adjustments and changes in estimates of asset recovery could have an impact
on
results of operations. The Company may generate enhanced oil recovery tax
credits from the production of its heavy crude oil in California which results
in a deferred tax asset and believes that these credits will be fully utilized
in future years and consequently has not recorded any valuation allowance
related to these credits. Due to uncertainties involved with tax matters,
the
future effective tax rate may vary significantly from the estimated current
year
effective tax rate.
Asset
Retirement Obligations.
The
Company has significant obligations to plug and abandon oil and natural gas
wells and related equipment at the end of oil and gas production operations.
The
computation of the Company's asset retirement obligations (ARO) was prepared
in
accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations,
which
requires the Company to record the fair value of liabilities for retirement
obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted
in an immaterial difference in the liability that had been previously recorded
by the Company. Estimating the future ARO requires Management to make estimates
and judgments regarding timing, current estimates of plugging and abandonment
costs, as well as what constitutes adequate remediation. The Company obtained
estimates from third parties and used the present value of estimated cash
flows
related to its ARO to determine the fair value. Inherent in the present value
calculation are numerous assumptions and judgments including the ultimate
costs,
inflation factors, credit adjusted discount rates, timing of settlement and
changes in the legal, regulatory, environmental and political environments.
Changes in any of these assumptions can result in significant revisions to
the
estimated ARO. To the extent future revisions to these assumptions impact
the
present value of the existing ARO liability, a corresponding adjustment will
be
made to the related asset. Due to the subjectivity of assumptions and the
relatively long life of the Company's assets, the costs to ultimately retire
the
Company's wells may vary significantly from previous estimates.
Environmental
Remediation Liability. The
Company reviews, on a quarterly basis, its estimates of costs of the cleanup
of
various sites including sites in which governmental agencies have designated
the
Company as a potentially responsible party. In accordance with SFAS No. 5,
Accounting
for Contingencies,
when it
is probable that obligations have been incurred and where a minimum cost
or a
reasonable estimate of the cost of remediation can be determined, the applicable
amount is accrued. Determining when expenses should be recorded for these
contingencies and the appropriate amounts for accrual is an estimation process
that includes the subjective judgment of Management. In many cases, Management's
judgment is based on the advice and opinions of legal counsel and other
advisers, the interpretation of laws and regulations, which can be interpreted
differently by regulators or courts of law, the experience of the Company
and
other companies in dealing with similar matters and the decision of Management
on how it intends to respond to a particular matter. A change in estimate
could
impact the Company's oil and gas operating costs and the liability, if
applicable, recorded on the Company's balance sheet.
Accounting
for Business Combinations. The
Company has grown substantially through acquisitions and our business strategy
is to continue to pursue acquisitions as opportunities arise. We have accounted
for all of our business combinations using the purchase method, which is
the
only method permitted under SFAS 141. The accounting for business combinations
is complicated and involves the use of significant judgment. Under the purchase
method of accounting, a business combination is accounted for at a purchase
price based upon the fair value of the consideration given, whether in the
form
of cash, assets, stock or the assumption of liabilities. The assets and
liabilities acquired are measured at their fair values, and the purchase
price
is allocated to the assets and liabilities based upon these fair values.
The
excess of the fair value of assets acquired and liabilities assumed over
the
cost of an acquired entity, if any, is allocated as a pro rata reduction
of the
amounts that otherwise would have been assigned to certain acquired assets.
Determining
the fair values of the assets and liabilities acquired involves the use of
judgment, since some of the assets and liabilities acquired do not have fair
values that are readily determinable. Different techniques may be used to
determine fair values, including market prices, where available, appraisals,
comparisons to transactions for similar assets and liabilities and present
value
of estimated future cash flows, among others. Since these estimates involve
the
use of significant judgment, they can change as new information becomes
available.
Each
of
the business combinations completed were of interests in oil and gas assets.
We
believe the consideration we paid to acquire these assets represents the
fair
value of the assets and liabilities acquired at the time of acquisition.
Consequently, we have not recognized any goodwill from any of our business
combinations, nor do we expect to recognize any goodwill from similar business
combinations that we may complete in the future.
Stock-Based
Compensation.
Effective January 1, 2004, the Company voluntarily adopted the fair value
method
of accounting for its stock option plan as prescribed by SFAS 123, Accounting
for Stock-Based Compensation. The modified prospective method was selected
as
described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognizes stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Stock option compensation expense is recognized
from
the date of grant to the vesting date. The
fair
value of each option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the following assumptions. Expected
volatilities are based on the historical volatility of the Company's stock.
The
Company uses historical data to estimate option exercises and employee
terminations within the valuation model; separate groups of employees that
have
similar historical exercise behavior are considered separately for valuation
purposes. The expected term of options granted is based on historical exercise
behavior and represents the period of time that options granted are expected
to
be outstanding; the range results from certain groups of employees exhibiting
different exercise behavior. The risk free rate for periods within the
contractual life of the option is based on U.S. Treasury rates in effect
at the
time of grant.
Electricity
Cost Allocation. The
Company’s investment in its cogeneration facilities has been for the express
purpose of lowering steam costs in its California heavy oil operations and
securing operating control of the respective steam generation. Such cogeneration
operations produce electricity and steam and use natural gas as fuel. The
Company allocates steam costs to its oil and gas operating costs based on
the
conversion efficiency (of fuel to electricity and steam) of the cogeneration
facilities plus certain direct costs in producing steam. Electricity revenue
represents sales to the utilities. Electricity used in oil and gas operations
is
allocated at cost. A portion of the DD&A expenses associated with capital is
allocated to DD&A - oil and gas production.
Recent
Accounting Pronouncements. In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. This
eliminates the exception to account for such awards using the intrinsic method
previously allowable under Accounting Principles Board (APB) Opinion No.
25. In
April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for
annual reporting periods beginning on or after June 15, 2005. As a result,
the
Company expects to adopt this statement on January 1, 2006. The Company
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly the Company believes SFAS No. 123(R) will not have a material
impact
on its financial statements; however, it continues to assess the potential
impact that the adoption of SFAS No. 123(R) will have on the classification
of
tax deductions for stock-based compensation in the statements of cash flows.
In
March
2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation
No. 47, Accounting
for Conditional Asset Retirement Obligations
(“FIN
47”). FIN 47 clarifies the definition and treatment of conditional asset
retirement obligations as discussed in FASB Statement No. 143, Accounting
for Asset Retirement Obligations.
A
conditional asset retirement obligation is defined as an asset retirement
activity in which the timing and/or method of settlement are dependent on
future
events that may be outside the control of the company. FIN 47 states that
a
company must record a liability when incurred for conditional asset retirement
obligations if the fair value of the obligation is reasonably estimable.
FIN 47
is intended to provide more information about long-lived assets and future
cash
outflows for these obligations and more consistent recognition of these
liabilities and is effective for the fiscal year end December 31, 2005. The
adoption of FIN 47 by the Company did not have an immediate affect on the
financial statements.
On
April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1
Accounting
for Suspended Well Costs that
amends SFAS 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies,
to
permit the continued capitalization of exploratory well costs beyond one
year if
the well found a sufficient quantity of reserves to justify its completion
as a
producing well and the entity is making sufficient progress assessing the
reserves and the economic and operating viability of the project. In accordance
with the guidance in the FSP, the Company applied the requirements prospectively
in its second quarter of 2005. The adoption of FSP 19-1 by the Company did
not
have an immediate effect on the financial statements. However, it could impact
the timing of the recognition of expenses for exploratory well costs in future
periods.
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB
Statement No. 3 was
issued. SFAS No. 154 requires retrospective application to prior period
financial statements for changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to the direct
effects
of the change. Indirect effects of a change in accounting principle should
be
recognized in the period of the accounting change. SFAS No. 154 will become
effective for the Company’s fiscal year beginning January 1, 2006. The
impact of SFAS No. 154 will depend on
the
nature and extent of any voluntary accounting changes and correction of errors
after the effective date.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for the Company’s fiscal year after September
15, 2006. The impact of SFAS No. 155 will depend on the nature and extent
of any new derivative instruments entered into after the effective
date.
As
discussed in Note 15 to the financial statements, to minimize the effect
of a
downturn in oil and gas prices and protect the profitability of the Company
and
the economics of the Company’s development plans, from time to time the Company
enters into crude oil and natural gas hedge contracts. The terms of contracts
depend on various factors, including Management’s view of future crude oil and
natural gas prices and the Company’s 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 Berry to participate in the upside.
In
California, Berry benefits from lower natural gas pricing and elsewhere,
Berry
benefits from higher natural gas pricing. The Company has, and may hedge
both
natural gas purchases and sales as determined appropriate by Management.
Management regularly monitors the crude oil and natural gas markets and the
Company’s financial commitments to determine if, when, and at what level some
form of crude oil and/or natural gas hedging or other price protection is
appropriate in accordance with Board established policy.
Currently,
the Company’s hedges are in the form of swaps and collars. However, the Company
may use a variety of hedge instruments in the future to hedge WTI or the
index
gas price. The Company has 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 the Company
sells its produced gas in Colorado and Utah at the Colorado Interstate Gas
(CIG)
and Questar index prices, respectively.
The
following table summarizes the hedge position of the Company as of December
31,
2005:
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Barrels
|
|
Average
|
|
|
|
MMBtu
|
|
Average
|
|
Term
|
|
Per
Day
|
|
Price
|
|
Term
|
|
Per
Day
|
|
Price
|
|
Crude
Oil Sales (NYMEX WTI)
|
|
|
|
|
|
Natural
Gas Sales (CIG)
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
Swaps
|
|
|
|
|
|
1st
Quarter 2006
|
|
3,000
|
|
$
50.90
|
|
1st
Quarter 2006
|
|
3,000
|
|
$
7.49
|
|
2nd
Quarter 2006
|
|
3,000
|
|
$
50.20
|
|
|
|
|
|
|
|
3rd
Quarter 2006
|
|
3,000
|
|
$
49.56
|
|
|
|
|
|
|
|
|
|
Natural
Gas Purchases (SoCal Border)
|
|
|
|
|
||||
|
Collars
|
|
Floor/Ceiling
Prices
|
|
Swaps
|
|
|||||
|
1st
through 3rd Quarter 2006
|
|
7,000
|
|
$47.50
/ $70
|
|
1st
Quarter 2006
|
|
5,000
|
$
4.85
|
|
|
4th
Quarter 2006
|
10,000
|
$47.50
/ $70
|
|
2nd
Quarter 2006
|
|
5,000
|
$
4.85
|
|||
|
Full
year 2007
|
10,000
|
$47.50
/ $70
|
|
|||||||
|
Full
year 2008
|
10,000
|
$47.50
/ $70
|
|
|||||||
|
Full
year 2009
|
10,000
|
$47.50
/ $70
|
|
On
March
1, 2006, the Company entered into the following derivative instruments:
|
|
|
Average
|
|
|
|
Average
|
|||
|
|
|
MMBtu
|
|
Average
|
|
|
MMBtu
|
Average
|
|
|
Term
|
|
Per
Day
|
|
Price
|
Term
|
|
Per
Day
|
Price
|
|
|
Natural
Gas Sales (NYMEX HH)
|
|
|
|
|
Natural
Gas Sales (NYMEX HH)
|
|
|
|
|
|
Swaps
|
|
|
|
|
Collars
|
Floor/Ceiling
Prices
|
|||
|
2nd
Quarter 2006
|
|
4,000
|
|
$
6.96
|
4th
Quarter 2006
|
|
8,000
|
$8
/ $9.72
|
|
|
3rd
Quarter 2006
|
|
6,000
|
|
$
7.35
|
1st
Quarter 2007
|
12,000
|
$8
/ $16.70
|
||
|
|
2nd
Quarter 2007
|
13,000
|
$8
/ $8.82
|
||||||
|
3rd
Quarter 2007
|
14,000
|
$8
/ $9.10
|
|||||||
|
4th
Quarter 2007
|
15,000
|
$8
/ $11.39
|
|||||||
|
1st
Quarter 2008
|
16,000
|
$8
/ $15.65
|
|||||||
|
2nd
Quarter 2008
|
17,000
|
$7.50
/ $8.40
|
|||||||
|
3rd
Quarter 2008
|
19,000
|
$7.50
/ $8.50
|
|||||||
|
4th
Quarter 2008
|
21,000
|
$8
/ $9.50
|
Payments
to the Company's counterparties are triggered when the monthly average prices
are above the swap price in the case of the Company's crude oil and natural
gas
sales hedges and below the swap price for the Company's natural gas purchase
hedge positions. Conversely, payments from our counterparties are received
when
the monthly average prices are below the swap price for the Company's crude
oil
and natural gas sales hedges and above the swap price for the Company's natural
gas purchase hedge positions.
The
collar strike prices will allow the Company to protect a significant portion
of
its future cash flow if 1) oil prices decline below $47.50 per barrel while
still participating in any oil price increase up to $70 per barrel on these
volumes and 2) if gas prices decline below approximately $8 per MMBtu. These
hedges improve the Company’s financial flexibility by locking in significant
revenues and cash flow upon a substantial decline in crude oil or natural
gas
prices. It also allows the Company to develop its long-lived assets and pursue
exploitation opportunities with greater confidence in the projected economic
outcomes and allows the Company to borrow a higher amount under the credit
facility.
While
the
Company has designated its 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, the Company may have some ineffectiveness in its natural
gas hedges put into place on March 1, 2006, due to the movement of HH pricing
as
compared to actual sales points. If this occurs, the ineffective portion
will
directly impact net income rather than being reported as Other Comprehensive
Income. While Management believes that the differential will narrow and move
closer toward its historical level over time, there are no assurances as
to the
movement in the differential. If the differential were to change significantly,
it is possible that the Company’s hedges, when marked-to-market, could have a
material impact on earnings in any given quarter and, thus, add increased
volatility to the Company’s net income. The marked-to-market values reflect the
liquidation values of such hedges and not necessarily the values of the hedges
if they are held to maturity. Irrespective of the unrealized gains reflected
in
Other Comprehensive Income, the ultimate impact to net income over the life
of
the hedges will reflect the actual settlement values. All of these hedges
have
historically been deemed to be cash flow hedges with the marked-to-market
valuations provided by external sources, based on prices that are actually
quoted.
At
December 31, 2005, Accumulated Other Comprehensive Loss, net of income taxes,
consisted of $24.4 million of unrealized losses from the Company's crude
oil and
natural gas hedges. Deferred net losses recorded in Accumulated Other
Comprehensive Loss at December 31, 2005 are expected to be reclassified to
earnings through 2006 for the Company’s swaps and at current prices the
Company’s collars are not expected to impact earnings.
|
2005
|
2004
|
2003
|
||||||||
|
Net
reduction of sales of oil and gas revenue due to hedging activities
(in
millions)
|
|
$
|
45.3
|
|
$
|
24.9
|
|
$
|
11.8
|
|
|
Net
reduction of cost of gas due to hedging activities (in
millions)
|
$
|
5.0
|
$
|
1.3
|
$
|
.1
|
||||
|
Net
reduction in revenue per BOE due to hedging activities
|
$
|
5.39
|
$
|
3.32
|
$
|
1.96
|
The
use
of hedging transactions may involve basis risk. The Company's oil hedges
are
based on reported settlement prices on the NYMEX. The basis risk between
NYMEX
and the Company's California heavy crude oil is mitigated by the Company's
crude
oil
sales
contracts. On November 21, 2005, the Company entered into a new crude oil
sales
contract for its California production for deliveries beginning February
1,
2006. The per barrel price, calculated on a monthly basis and blended across
the
various producing locations, is the higher of 1) the WTI NYMEX crude oil
price
less a fixed differential approximating $8.15, or 2) heavy oil field postings
plus a premium of approximately $1.35. The initial term of the contract is
for
four years with a one-year renewal at the Company’s option. The Company has
redesignated its existing crude oil collars as cash flow hedges related to
California crude oil production, and there was no related effect to Other
Comprehensive Income with regard to this redesignation.
Pricing
in the existing crude oil sales agreement at Brundage Canyon is based upon
average weekly WTI minus a fixed differential of approximately $2 per barrel
through September 30, 2006. Any new contract will be negotiated based on
market
prices. Upon the expiration of these crude oil contracts, and absent any
new
contracts, the Company will be exposed to fluctuations in the basis
differentials between WTI and the posted price for its crude oil at its various
producing locations until new contracts which lock in such differential can
be
obtained.
The
use
of hedging transactions also involves the risk that the counterparties will
be
unable to meet the financial terms of such transactions. With respect to
the
Company’s hedging activities, the Company utilizes multiple counterparties on
its hedges and monitors each counterparty’s credit rating. The Company also
attempts to minimize credit exposure to counterparties through diversification.
Based
on
NYMEX futures prices as of December 31, 2005, (WTI $62.71; HH $10.83) and
due to
the backwardated nature of the futures prices as of that date, the Company
would
expect to make pre-tax future cash payments or to receive payments over the
remaining term of its crude oil and natural gas hedges in place as
follows:
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|||||||||||
|
|
|
12/31/05
|
|
on
earnings
|
|
|||||||||||
|
|
|
NYMEX
Futures
|
|
-20%
|
|
-10%
|
|
+
10%
|
|
+
20%
|
|
|||||
|
Average
WTI Price
|
|
$
|
62.71
|
$
|
50.17
|
|
$
|
56.44
|
|
$
|
68.98
|
$
|
75.25
|
|||
|
Crude
Oil gain/(loss) (in millions)
|
|
|
(10.4
|
)
|
|
(.1
|
)
|
|
(5.2
|
)
|
|
(17.5
|
)
|
|
(92.8
|
)
|
|
Average
HH Price
|
|
|
10.83
|
|
8.67
|
|
|
9.75
|
|
|
11.92
|
|
13.00
|
|||
|
Natural
Gas gain/(loss) (in millions)
|
3.8
|
2.4
|
3.1
|
4.4
|
5.1
|
|||||||||||
|
|
||||||||||||||||
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
||||||||||||||||
|
2006
|
$
|
(6.6
|
)
|
$
|
2.3
|
$
|
(2.1
|
)
|
$
|
(11.5
|
)
|
$
|
(32.3
|
)
|
||
|
2007
|
-
|
-
|
-
|
(1.6
|
)
|
(24.8
|
)
|
|||||||||
|
2008
|
-
|
-
|
-
|
-
|
(18.7
|
)
|
||||||||||
|
2009
|
|
|
-
|
|
-
|
-
|
-
|
(11.9
|
)
|
|||||||
|
Total
|
|
$
|
(6.6
|
)
|
$
|
2.3
|
$
|
(2.1
|
)
|
$
|
(13.1
|
)
|
$
|
(87.7
|
)
|
|
Interest
Rates.
The
Company’s exposure to changes in interest rates results primarily from long-term
debt. Total long-term debt outstanding at December 31, 2005 and 2004 was
$75
million and $28 million, respectively. Interest on amounts borrowed is charged
at LIBOR plus 1.0% to 1.75%. Based on year-end 2005 borrowings, a 1% change
in
interest rates would not have a material impact on the Company’s financial
statements.
|
|
Page
|
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public
Accounting
Firm
|
42
|
|
Balance
Sheets at December 31, 2005 and 2004
|
43
|
|
Statements
of Income for the Years Ended December 31, 2005, 2004 and 2003
|
44
|
|
Statements
of Comprehensive Income for the Years Ended December 31, 2005,
2004 and
2003
|
44
|
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2005,
2004 and
2003
|
45
|
|
Statements
of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003
|
46
|
|
Notes
to the Financial Statements
|
47
|
|
Supplemental
Information About Oil & Gas Producing Activities
(unaudited)
|
65
|
Financial
statement schedules have been omitted since they are either not required,
are
not applicable, or the required information is shown in the financial statements
and related notes.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Board of Directors and Shareholders of Berry Petroleum Company:
We
have
completed integrated audits of Berry Petroleum Company’s December 31, 2005 and
2004 financial statements and of its internal control over financial reporting
as of December 31, 2005, and an audit of its December 31, 2003 financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Financial
statements
In
our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Berry Petroleum
Company at December 31, 2005 and 2004, and the results of its operations
and its
cash flows for each of the three years in the period ended December 31, 2005
in
conformity with accounting principles generally accepted in the United States
of
America. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements
in
accordance with the standards of the Public Company Accounting Oversight
Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether the financial statements are free
of
material misstatement. An audit of financial statements includes examining,
on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
Internal
control over financial reporting
Also,
in
our opinion, management’s assessment, included in Management’s Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as
of
December 31, 2005 based on criteria established in Internal
Control - Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005,
based on criteria established in Internal
Control - Integrated Framework
issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight
Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding
of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in
the
circumstances. We believe that our audit provides a reasonable basis for
our
opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures
of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use,
or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers LLP
Los
Angeles, California
March
1,
2006
BERRY
PETROLEUM COMPANY
December
31, 2005 and 2004
(In
Thousands, Except Share Information)
|
|
|
2005
|
|
2004
|
|
||
|
ASSETS
|
|
||||||
|
Current
assets:
|
|||||||
|
Cash
and cash equivalents
|
|
$
|
1,990
|
|
$
|
16,690
|
|
|
Short-term
investments available for sale
|
|
|
661
|
|
|
659
|
|
|
Accounts
receivable
|
|
|
59,672
|
|
|
34,621
|
|
|
Deferred
income taxes
|
|
|
4,547
|
|
|
3,558
|
|
|
Fair
value of derivatives
|
|
|
3,618
|
|
|
3,243
|
|
|
Prepaid
expenses and other
|
|
|
4,398
|
|
|
2,230
|
|
|
Total
current assets
|
|
|
74,886
|
|
|
61,001
|
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
552,984
|
|
|
338,706
|
|
|
Deposits
on potential property acquisitions
|
|
|
-
|
|
|
10,221
|
|
|
Long-term
deferred income taxes
|
1,600
|
-
|
|||||
|
Other
assets
|
|
|
5,581
|
|
|
2,176
|
|
|
|
|
$
|
635,051
|
|
$
|
412,104
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
57,783
|
|
$
|
27,750
|
|
|
Revenue
and royalties payable
|
|
|
34,920
|
|
|
23,945
|
|
|
Accrued
liabilities
|
|
|
8,805
|
|
|
6,132
|
|
|
Line
of credit
|
11,500
|
-
|
|||||
|
Income
taxes payable
|
|
|
1,237
|
|
|
1,067
|
|
|
Fair
value of derivatives
|
|
|
15,398
|
|
|
5,947
|
|
|
Total
current liabilities
|
|
|
129,643
|
|
|
64,841
|
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
55,804
|
|
|
47,963
|
|
|
Long-term
debt
|
|
|
75,000
|
|
|
28,000
|
|
|
Abandonment
obligation
|
|
|
10,675
|
|
|
8,214
|
|
|
Unearned
revenue
|
866
|
-
|
|||||
|
Fair
value of derivatives
|
|
|
28,853
|
|
|
-
|
|
|
|
|
|
171,198
|
|
|
84,177
|
|
|
Commitments
and contingencies (Notes 10 and 11)
|
|
|
|
|
|
|
|
|
Shareholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
|
-
|
|
|
Capital
stock, $.01 par value:
|
|
|
|
|
|
|
|
|
Class
A Common Stock, 50,000,000 shares authorized; 21,099,906 shares
issued and
outstanding (21,060,420 in 2004)
|
|
|
211
|
|
|
210
|
|
|
Class
B Stock, 1,500,000 shares authorized; 898,892 shares issued and
outstanding (liquidation preference of $899)
|
|
|
9
|
|
|
9
|
|
|
Capital
in excess of par value
|
|
|
56,064
|
|
|
60,676
|
|
|
Accumulated
other comprehensive loss
|
|
|
(24,380
|
)
|
|
(987
|
)
|
|
Retained
earnings
|
|
|
302,306
|
|
|
203,178
|
|
|
Total
shareholders' equity
|
|
|
334,210
|
|
|
263,086
|
|
|
|
|
$
|
635,051
|
|
$
|
412,104
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
ended December 31, 2005, 2004 and 2003
(In
Thousands, Except Per Share Data)
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
REVENUES
|
|
|
|
|
|
|
|
|||
|
Sales
of oil and gas
|
|
$
|
349,691
|
|
$
|
226,876
|
|
$
|
135,848
|
|
|
Sales
of electricity
|
|
|
55,230
|
|
|
47,644
|
|
|
44,200
|
|
|
Interest
and other income, net
|
|
|
1,804
|
|
|
426
|
|
|
816
|
|
|
|
|
|
406,725
|
|
|
274,946
|
|
|
180,864
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|||
|
Operating
costs - oil and gas production
|
|
|
99,066
|
|
|
73,838
|
|
|
57,830
|
|
|
Operating
costs - electricity generation
|
|
|
55,086
|
|
|
46,191
|
|
|
42,351
|
|
|
Production
taxes
|
11,506
|
6,431
|
3,097
|
|||||||
|
Exploration
costs
|
3,649
|
-
|
-
|
|||||||
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
38,150
|
|
|
29,752
|
|
|
17,258
|
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
3,260
|
|
|
3,490
|
|
|
3,256
|
|
|
General
and administrative
|
|
|
21,396
|
|
|
22,504
|
|
|
14,495
|
|
|
Interest
|
|
|
6,048
|
|
|
2,067
|
|
|
1,414
|
|
|
Dry
hole, abandonment and impairment
|
|
|
5,705
|
|
|
745
|
|
|
4,195
|
|
|
Loss
on disposal of assets
|
|
|
-
|
|
|
410
|
|
|
-
|
|
|
|
|
|
243,866
|
|
|
185,428
|
|
|
143,896
|
|
|
Income
before income taxes
|
|
|
162,859
|
|
|
89,518
|
|
|
36,968
|
|
|
Provision
for income taxes
|
|
|
50,503
|
|
|
20,331
|
|
|
4,605
|
|
|
|
|
|
|
|
|
|
|
|||
|
Net
income
|
|
$
|
112,
356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
|
|
|
|
|
|
|
|
|||
|
Basic
net income per share
|
|
$
|
5.10
|
|
$
|
3.16
|
|
$
|
1.49
|
|
|
|
|
|
|
|
|
|
|
|||
|
Diluted
net income per share
|
|
$
|
5.00
|
|
$
|
3.08
|
|
$
|
1.47
|
|
|
|
|
|
|
|
|
|
|
|||
|
Weighted
average number of shares of capital stock outstanding (used to
calculate
basic net income per share)
|
|
|
22,041
|
|
|
21,894
|
|
|
21,772
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|||
|
Stock
options
|
|
|
390
|
|
|
523
|
|
|
215
|
|
|
Other
|
|
|
59
|
|
|
53
|
|
|
44
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
22,490
|
|
|
22,470
|
|
|
22,031
|
|
|
|
|
|
|
|
|
|
|
|||
|
Statements
of Comprehensive Income
|
|
|||||||||
|
Years
Ended December 31, 2005, 2004 and 2003
|
||||||||||
|
(In
Thousands)
|
||||||||||
|
Net
income
|
|
$
|
112,356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($16,677),
($521),
and ($2,421), respectively
|
|
|
(25,015
|
)
|
|
(781
|
)
|
|
(3,632
|
)
|
|
Reclassification
of realized gains (losses) included in net income net of income
taxes of
$1,081, $2,284 and $1,712, respectively
|
|
|
1,622
|
|
|
3,426
|
|
|
2,569
|
|
|
Comprehensive
income
|
|
$
|
88,963
|
|
$
|
71,832
|
|
$
|
31,300
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
Ended December 31, 2005, 2004 and 2003
(In
Thousands, Except Per Share Data)
|
|
|
Class
A
|
|
Class
B
|
|
Capital
in Excess of Par Value
|
|
Deferred
Stock-Based Compensation
|
|
Retained
Earnings
|
|
Accumulated
Other Comprehensive
Income
(Loss)
|
|
Shareholders’
Equity
|
|
||||||||
|
Balances
at January 1, 2003
|
|
$
|
209
|
|
$
|
9
|
|
$
|
52,214
|
|
$
|
(346
|
)
|
$
|
123,257
|
|
$
|
(2,569
|
)
|
$
|
172,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued
compensation costs
|
|
|
-
|
|
|
-
|
|
|
3,319
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3,319
|
|
|
|
Deferred
director fees - stock compensation
|
|
|
-
|
|
|
-
|
|
|
169
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
169
|
|
|
|
Unearned
stock-based compensation
|
|
|
-
|
|
|
-
|
|
|
773
|
|
|
(773
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Amortization
of deferred stock option compensation
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11
|
|
|
-
|
|
|
-
|
|
|
11
|
|
|
|
Cash
dividends declared - $.47 per share
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(10,235
|
)
|
|
-
|
|
|
(10,235
|
)
|
|
|
Unrealized
loss on derivatives
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1,063
|
)
|
|
(1,063
|
)
|
|
|
Net
income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
32,363
|
|
|
-
|
|
|
32,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances
at December 31, 2003
|
|
209
|
|
9
|
56,475
|
|
(1,108
|
)
|
145,385
|
|
(3,632
|
)
|
197,338
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Adoption
of SFAS 123
|
|
-
|
|
-
|
(243
|
)
|
1,108
|
|
-
|
|
-
|
|
865
|
|
|||||||||
|
Stock-based
compensation (155,269 shares)
|
|
1
|
|
-
|
3,451
|
|
-
|
|
-
|
|
-
|
|
3,452
|
|
|||||||||
|
Deferred
director fees - stock compensation
|
|
-
|
|
-
|
993
|
|
-
|
|
-
|
|
-
|
|
993
|
|
|||||||||
|
Cash
dividends declared - $.52 per share
|
|
-
|
|
-
|
-
|
|
-
|
|
(11,394
|
)
|
-
|
|
(11,394
|
)
|
|||||||||
|
Unrealized
gain on derivatives
|
|
-
|
|
-
|
-
|
|
-
|
|
-
|
|
2,645
|
|
2,645
|
|
|||||||||
|
Net
income
|
|
-
|
|
-
|
-
|
|
-
|
|
69,187
|
|
-
|
|
69,187
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Balances
at December 31, 2004
|
|
210
|
|
9
|
60,676
|
|
-
|
|
203,178
|
|
(987
|
)
|
263,086
|
|
|||||||||
|
Share
repurchase (108,900 shares)
|
|
|
(2
|
)
|
-
|
(6,314
|
)
|
-
|
-
|
-
|
(6,316
|
)
|
|||||||||||
|
Stock-based
compensation (147,179 shares)
|
|
|
3
|
-
|
1,360
|
-
|
-
|
-
|
1,363
|
||||||||||||||
|
Deferred
director fees - stock compensation
|
|
|
-
|
-
|
342
|
-
|
-
|
-
|
342
|
||||||||||||||
|
Cash
dividends declared - $.60 per share
|
|
|
-
|
-
|
-
|
-
|
(13,228
|
)
|
-
|
(13,228
|
)
|
||||||||||||
|
Unrealized
loss on derivatives
|
|
|
-
|
-
|
-
|
-
|
-
|
(23,393
|
)
|
(23,393
|
)
|
||||||||||||
|
Net
income
|
|
|
-
|
-
|
-
|
-
|
112,356
|
-
|
112,356
|
||||||||||||||
|
|
|
|
|||||||||||||||||||||
|
Balances
at December 31, 2005
|
|
$
|
211
|
$
|
9
|
$
|
56,064
|
$
|
-
|
$
|
302,306
|
$
|
(24,380
|
)
|
$
|
334,210
|
|||||||
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Years
Ended December 31, 2005, 2004 and 2003
(In
Thousands)
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|||
|
Net
income
|
|
$
|
112,356
|
|
$
|
69,187
|
|
$
|
32,363
|
|
|
Depreciation,
depletion and amortization
|
|
|
41,410
|
|
|
33,242
|
|
|
20,514
|
|
|
Dry
hole, abandonment and impairment
|
|
|
4,324
|
|
(569
|
)
|
|
3,756
|
|
|
|
Stock-based
compensation expense
|
|
|
1,703
|
|
5,309
|
|
|
2,872
|
|
|
|
Deferred
income taxes, net
|
|
|
20,847
|
|
10,815
|
|
|
1,496
|
|
|
|
Other,
net
|
|
|
278
|
|
794
|
|
|
400
|
|
|
|
Increase
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
(26,717
|
)
|
|
(11,310
|
)
|
|
(9,034
|
)
|
|
Increase
in current liabilities other than line of credit
|
|
|
33,579
|
|
17,145
|
|
|
12,458
|
|
|
|
Net
cash provided by operating activities
|
|
|
187,780
|
|
124,613
|
|
|
64,825
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
||
|
Exploration
and development of oil and gas properties
|
|
|
(118,718
|
)
|
|
(71,556
|
)
|
|
(41,061
|
)
|
|
Property
acquisitions
|
|
|
(112,249
|
)
|
|
(2,845
|
)
|
|
(48,579
|
)
|
|
Additions
to vehicles, drilling rigs and other fixed assets
|
(11,762
|
)
|
(669
|
)
|
(494
|
)
|
||||
|
Deposits
on potential acquisitions
|
|
|
-
|
|
(10,221
|
)
|
|
-
|
|
|
|
Proceeds
from sale of assets
|
|
|
130
|
|
101
|
|
|
1,890
|
|
|
|
Other,
net
|
|
|
-
|
|
3
|
|
|
521
|
|
|
|
Net
cash used in investing activities
|
|
|
(242,599
|
)
|
|
(85,187
|
)
|
|
(87,723
|
)
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
||
|
Proceeds
from issuance of line of credit
|
18,000
|
-
|
-
|
|||||||
|
Payment
of line of credit
|
(6,500
|
)
|
-
|
-
|
||||||
|
Proceeds
from issuance of long-term debt
|
|
|
144,000
|
|
-
|
|
|
40,000
|
|
|
|
Payment
of long-term debt
|
|
|
(97,000
|
)
|
|
(22,000
|
)
|
|
(5,000
|
)
|
|
Dividends
paid
|
|
|
(13,228
|
)
|
|
(11,394
|
)
|
|
(10,235
|
)
|
|
Book
overdraft
|
1,921
|
-
|
-
|
|||||||
|
Repurchase
of shares
|
(6,315
|
)
|
-
|
-
|
||||||
|
Other,
net
|
|
|
(759
|
)
|
-
|
(1,075
|
)
|
|||
|
Net
cash provided by (used in) financing activities
|
|
|
40,119
|
|
(33,394
|
)
|
|
23,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(14,700
|
)
|
|
6,032
|
|
|
792
|
|
|
Cash
and cash equivalents at beginning of year
|
|
|
16,690
|
|
|
10,658
|
|
|
9,866
|
|
|
Cash
and cash equivalents at end of year
|
|
$
|
1,990
|
|
$
|
16,690
|
|
$
|
10,658
|
|
|
Supplemental
disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$
|
5,275
|
|
$
|
1,243
|
|
$
|
2,125
|
|
|
Income
taxes paid
|
|
$
|
26,544
|
|
$
|
11,652
|
|
$
|
2,510
|
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of $(3,631), $1,202, and ($635),
respectively)
|
|
$
|
(5,446
|
)
|
$
|
1,804
|
|
$
|
(952
|
)
|
|
Non-current
(net of income taxes of $(11,965), $561, and ($74),
respectively)
|
|
|
(17,947
|
)
|
|
841
|
|
|
(111
|
)
|
|
Net
increase (decrease) to accumulated other comprehensive
income
|
|
$
|
(23,393
|
)
|
$
|
2,645
|
|
$
|
(1,063
|
)
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
1. General
The
Company is an independent energy company engaged in the production, development,
acquisition, exploitation and exploration of crude oil and natural gas. The
Company has 74% of its oil and gas reserves in California and 26% in the
Rocky
Mountain and Mid-Continent region. Approximately 70% of the Company's production
is in California, most of which is heavy crude oil and is sold to a Bakersfield,
California refinery. The Company has invested in cogeneration facilities
which
provide steam required for the extraction of heavy oil and which generates
electricity for sale. Production of light crude oil and natural gas in the
Rocky
Mountain and Mid-Continent region accounts for approximately 30% of the
Company’s production.
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires Management to
make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the
date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
2. Summary
of Significant Accounting Policies
Cash
and cash equivalents
- The
Company considers all highly liquid investments purchased with a remaining
maturity of three months or less to be cash equivalents. The Company’s cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at December 31, 2005
is $1.9
million representing outstanding checks in excess of the bank balance (book
overdraft).
Short-term
investments
- All
short-term investments are classified as available for sale. Short-term
investments consist principally of United States treasury notes and corporate
notes with remaining maturities of more than three months at date of acquisition
and are carried at fair value. The Company utilizes specific identification
in
computing realized gains and losses on investments sold.
Accounts
receivable
-
Trade
accounts receivable are recorded at the invoiced amount and do not bear
interest. The Company does not have any off-balance-sheet credit exposure
related to its customers. The Company assesses credit risk and allowance
for
doubtful accounts on a customer specific basis. As of December 31, 2005 and
2004, the Company does not have an allowance for doubtful accounts.
Income
taxes
-
Income
taxes are provided based on the liability method of accounting. The provision
for income taxes is based on reported pre-tax financial statement income.
Deferred tax assets and liabilities are recognized for the future expected
tax
consequences of temporary differences between income tax and financial
reporting, and principally relate to differences in the tax bases of assets
and
liabilities and their reported amounts using enacted tax rates in effect
for the
year in which differences are expected to reverse. If it is more likely than
not
that some portion or all of a deferred tax asset will not be realized, a
valuation allowance is recognized.
Hedging
-
SFAS
No.
133, Accounting
for Derivative Instruments and Hedging Activities,
as
amended, requires that all derivative instruments subject to the requirements
of
the statement be measured at fair value and recognized as assets or liabilities
in the balance sheet. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation is generally established at the inception of a derivative. For
derivatives designated as cash flow hedges and meeting the effectiveness
guidelines of SFAS No. 133, changes in fair value, to the extent effective,
are
recognized in other comprehensive income until the hedged item is recognized
in
earnings. The hedging relationship between the hedging instruments and hedged
items, such as oil and gas, must be highly effective in achieving the offset
of
changes in cash flows attributable to the hedged risk, both at the inception
of
the hedge and on an ongoing basis. The Company measures hedge effectiveness
at
least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time, or in the case of options
based on the change in intrinsic value. Any change in fair value of a derivative
resulting from ineffectiveness or an excluded component of the gain/loss,
such
as time value for option contracts, is recognized immediately in the statements
of income. Gains and losses on hedging instruments and adjustments of the
carrying amounts of hedged items are included in revenues for hedges related
to
the Company's crude oil and natural gas sales and in operating expenses for
hedges related to the Company's natural gas consumption. The resulting cash
flows are reported as cash flows from operating activities. See Note 15 -
Hedging.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Oil
and gas properties, buildings and equipment
-
The
Company accounts for its oil and gas exploration and development costs using
the
successful efforts method. Geological and geophysical costs and the costs
of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes.
All
exploratory wells are evaluated for economic viability within one year of
well
completion and the related capitalized costs are reviewed quarterly. Exploratory
wells that discover potentially economic reserves that are in areas where
a
major capital expenditure would be required before production could begin,
and
where the economic viability of that major capital expenditure depends upon
the
successful completion of further exploratory work in the area, remain
capitalized if the well found a sufficient quantity of reserves to justify
its
completion as a producing well and the Company is making sufficient progress
assessing the reserves and the economic and operating viability of the project.
The costs of development wells are capitalized whether productive or
nonproductive.
Depletion
of oil and gas producing properties is computed using the units-of-production
method. Depreciation of lease and well equipment, including cogeneration
facilities and other steam generation equipment and facilities, is computed
using the units-of-production method or on a straight-line basis over estimated
useful lives ranging from 10 to 20 years. Buildings and equipment are recorded
at cost. Depreciation is provided on a straight-line basis over estimated
useful
lives ranging from 5 to 30 years for buildings and improvements and 3 to
10
years for machinery and equipment. Estimated residual salvage value is
considered when determining depreciation, depletion and amortization (DD&A)
rates.
Assets
are grouped at the field level and if it is determined that the book value
of
long-lived assets cannot be recovered by estimated future undiscounted cash
flows, they are written down to fair value. When assets are sold, the applicable
costs and accumulated depreciation and depletion are removed from the accounts
and any gain or loss is included in income. Expenditures for maintenance
and
repairs are expensed as incurred.
Asset
retirement obligations
-
The
Company has significant obligations to plug and abandon oil and natural gas
wells and related equipment at the end of oil and gas production operations.
The
computation of the Company's asset retirement obligations (ARO) is prepared
in
accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations.
Under
this standard, the Company records the fair value of the future abandonment
as
capitalized abandonment costs in Oil and Gas Properties with an offsetting
abandonment liability. The Company obtains estimates from third parties and
uses
the present value of estimated cash flows related to its ARO to determine
the
fair value. The capitalized abandonment costs are amortized with other property
costs using the units-of-production method. The Company increases the liability
monthly by recording accretion expense using the Company’s credit adjusted
interest rate. Accretion expense is included in DD&A in the Company’s
financial statements.
Revenue
recognition
-
Revenues
associated with sales of crude oil, natural gas, and electricity are recognized
when title passes to the customer, net of royalties, discounts and allowances,
as applicable. Electricity and natural gas produced by the Company and used
in
the Company’s operations are not included in revenues. Revenues from crude oil
and natural gas production from properties in which the Company has an interest
with other producers are recognized on the basis of the Company's net working
interest (entitlement method).
Conventional
steam costs
-
The
costs
of producing conventional steam are included in “Operating costs - oil and gas
production.”
Cogeneration
operations
-
The
Company’s investment in its cogeneration facilities has been for the express
purpose of lowering steam costs in its heavy oil operations and securing
operating control of the respective steam generation. Such cogeneration
operations produce electricity and steam. The Company allocates steam costs
to
its oil and gas operating costs based on the conversion efficiency of the
cogeneration facilities plus certain direct costs in producing steam.
Electricity revenue represents sales to the utilities. Electricity used in
oil
and gas operations is allocated at cost. Electricity consumption included
in oil
and gas operating costs for the years ended December 31, 2005, 2004 and 2003
was
$5.7 million, $5 million and $4.2 million, respectively.
Shipping
and handling costs
-
Shipping
and handling costs, which consist primarily of natural gas transportation
costs,
are included in both "Operating costs - oil and gas production" or "Operating
costs - electricity generation,” as applicable. Natural gas transportation costs
included in these categories were $5.8 million, $5.4 million and $4 million,
for
2005, 2004 and 2003, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Production
taxes
-
Consist
primarily of severance and ad valorem taxes.
Stock-based
compensation
-
Effective
January 1, 2004, the Company voluntarily adopted the fair value method of
accounting for its stock option plan as prescribed by SFAS 123, Accounting
for Stock-Based Compensation.
The
modified prospective method was selected as described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognizes stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Stock option compensation expense is recognized
from
the date of grant to the vesting date.
From
January 1, 2004 to July 29, 2004 a portion of the Company's stock option
compensation was calculated under variable accounting; however, the majority
of
stock option compensation was accounted for under the fair value method.
In
accordance with variable plan accounting, the Company recognized a corresponding
liability determined by a marked-to-market valuation of the Company's stock
at
each financial reporting date. The Company revised certain stock option exercise
provisions of the plan and, subsequent to July 29, 2004, variable plan
accounting was no longer required.
Had
compensation cost for the Company’s stock-based compensation plan (see Note 12)
been based upon the fair value at the grant dates for awards under the plan
consistent with SFAS No. 123, the Company’s compensation cost, net of related
tax effects, net income and earnings per share would have been recorded as
the
pro forma amounts indicated below (in thousands, except per share
data):
|
|
|
2003
|
|
|
|
Net
income, as reported
|
|
$
|
32,363
|
|
|
Plus
compensation cost (net of tax), as reported
|
|
|
2,335
|
|
|
Less
compensation cost (net of tax), pro forma
|
|
(1,323
|
)
|
|
|
Net
income, pro forma
|
|
$
|
33,375
|
|
|
|
|
|
||
|
Basic
net income per share:
|
|
|
|
|
|
As
reported
|
|
$
|
1.49
|
|
|
Pro
forma
|
|
$
|
1.53
|
|
|
|
|
|
|
|
|
Diluted
net income per share:
|
|
|
|
|
|
As
reported
|
|
$
|
1.47
|
|
|
Pro
forma
|
|
$
|
1.52
|
|
Under
SFAS No. 123, compensation cost would be recognized for the fair value of
the
employee's option rights. The fair value of each option grant was estimated
on
the date of grant using the Black-Scholes option-pricing model with the
following assumptions:
|
|
2003
|
|
||
|
Yield
|
|
2.87
|
%
|
|
|
Expected
option life - years
|
|
7.0
|
|
|
|
Volatility
|
|
27.87
|
%
|
|
|
Risk-free
interest rate
|
|
3.86
|
%
|
|
Comprehensive
income (loss)
-
Comprehensive
income (loss) includes net earnings (loss) as well as unrealized gains and
losses on derivative instruments, recorded net of tax.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Net
income per share
-
Basic
net
income per share is computed by dividing income available to shareholders
(the
numerator) by the weighted average number of shares of capital stock outstanding
(the denominator). The Company’s Class B Stock is included in the denominator of
basic and diluted net income. The computation of diluted net income per share
is
similar to the computation of basic net income per share except that the
denominator is increased to include the dilutive effect of the additional
common
shares that would have been outstanding if all convertible securities had
been
converted to common shares during the period.
Environmental
expenditures
-
The
Company reviews, on a quarterly basis, its estimates of costs of the cleanup
of
various sites, including sites in which governmental agencies have designated
the Company as a potentially responsible party. When it is probable that
obligations have been incurred and where a minimum cost or a reasonable estimate
of the cost of compliance or remediation can be determined, the applicable
amount is accrued. For other potential liabilities, the timing of accruals
coincides with the related ongoing site assessments. Any liabilities arising
hereunder are not discounted.
Accounting
for business combinations
- The
Company has accounted for all of its business combinations using the purchase
method, which is the only method permitted under SFAS 141, Accounting
for Business Combinations.
Under
the purchase method of accounting, a business combination is accounted for
at a
purchase price based upon the fair value of the consideration given, whether
in
the form of cash, assets, stock or the assumption of liabilities. The assets
and
liabilities acquired are measured at their fair values, and the purchase
price
is allocated to the assets and liabilities based upon these fair values.
The
excess of the fair value of assets acquired and liabilities assumed over
the
cost of an acquired entity, if any, is allocated as a pro rata reduction
of the
amounts that otherwise would have been assigned to certain acquired assets.
The
Company has not recognized any goodwill from any business combinations.
Recent
accounting developments
-
In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. This
eliminates the exception to account for such awards using the intrinsic method
previously allowable under Accounting Principles Board (APB) Opinion No.
25. In
April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for
annual reporting periods beginning on or after June 15, 2005. As a result,
the
Company expects to adopt this statement on January 1, 2006. The Company
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly the Company believes SFAS No. 123(R) will not have a material
impact
on its financial statements; however, it continues to assess the potential
impact that the adoption of SFAS No. 123(R) will have on the classification
of
tax deductions for stock-based compensation in the statements of cash
flows.
In
March
2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation
No. 47, Accounting
for Conditional Asset Retirement Obligations
(“FIN
47”). FIN 47 clarifies the definition and treatment of conditional asset
retirement obligations as discussed in FASB Statement No. 143, Accounting
for Asset Retirement Obligations.
A
conditional asset retirement obligation is defined as an asset retirement
activity in which the timing and/or method of settlement are dependent on
future
events that may be outside the control of the company. FIN 47 states that
a
company must record a liability when incurred for conditional asset retirement
obligations if the fair value of the obligation is reasonably estimable.
FIN 47
is intended to provide more information about long-lived assets and future
cash
outflows for these obligations and more consistent recognition of these
liabilities. FIN 47 is effective for the fiscal year end December 31, 2005.
The
adoption of FIN 47 by the Company did not have an impact on the financial
statements.
On
April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1
Accounting
for Suspended Well Costs that
amends SFAS 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies,
to
permit the continued capitalization of exploratory well costs beyond one
year if
the well found a sufficient quantity of reserves to justify its completion
as a
producing well and the entity is making sufficient progress assessing the
reserves and the economic and operating viability of the project. In accordance
with the guidance in the FSP, the Company applied the requirements prospectively
in its second quarter of fiscal 2005. The adoption of FSP 19-1 by the Company
did not have an effect on the financial statements. However, it could impact
the
timing of the recognition of expenses for exploratory well costs in future
periods.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB
Statement No. 3 was
issued. SFAS No. 154 requires retrospective application to prior period
financial statements for changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to the direct
effects
of the change. Indirect effects of a change in accounting principle should
be
recognized in the period of the accounting change. SFAS No. 154 will become
effective for the Company’s fiscal year beginning January 1, 2006. The
impact of SFAS No. 154 will depend on the nature and extent of any
voluntary accounting changes and correction of errors after the effective
date.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for the Company’s fiscal year after September
15, 2006. The impact of SFAS No. 155 will depend on the nature and extent
of any new derivative instruments entered into after the effective
date.
Revisions
to the classification of technical labor costs and production
taxes
-
In
connection with the preparation of the 2005 financial statements the Company
is
reclassifying technical labor between general and administrative expenses
and
operating costs-oil and gas and reclassifying production taxes out of operating
costs-oil and gas into a separate line. These reclassifications had no impact
on
net income or net cash provided by operating activities and did not effect
previously reported total revenues, total operating expenses, net income
or net
cash provided by operating activities. Accordingly, the Company has revised
prior classifications for the year ended December 31, 2004 as follows (in
thousands):
|
|
|
2004
|
|
2003
|
||
|
Operating
costs - oil and gas
|
|
|
|
|||
|
As
previously reported
|
|
$
|
82,419
|
$
|
62,554
|
|
|
As
revised
|
|
73,838
|
57,830
|
|||
|
Difference
|
|
$
|
8,581
|
$
|
4,724
|
|
|
|
|
|||||
|
Production
taxes
|
|
|
|
|||
|
As
previously reported
|
|
$
|
-
|
$
|
-
|
|
|
As
revised
|
|
|
6,431
|
|
3,097
|
|
|
Difference
|
|
$
|
(6,431)
|
$
|
(3,097)
|
|
|
G&A
expenses
|
|
|
|
|||
|
As
previously reported
|
|
$
|
20,354
|
$
|
12,868
|
|
|
As
revised
|
|
|
22,504
|
|
14,495
|
|
|
Difference
|
|
$
|
(2,150)
|
$
|
(1,627)
|
|
3. Fair
Value of Financial Instruments
Cash
equivalents consist principally of commercial paper investments. Cash
equivalents of $2 million and $16.7 million at December 31, 2005 and 2004,
respectively, are stated at cost, which approximates market.
The
Company’s short-term investments available for sale at December 31, 2005 and
2004 consist of United States treasury notes that mature in less than one
year
and are carried at fair value. For the three years ended December 31, 2005,
realized and unrealized gains and losses were insignificant to the financial
statements. A United States treasury note with a market value of $.7 million
is
pledged as collateral to the California State Lands Commission as a performance
bond on the Company’s Montalvo properties. The carrying value of the Company’s
long-term debt approximates its fair value since the interest rate is variable.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
4. Concentration
of Credit Risks
The
Company sells oil, gas and natural gas liquids to pipelines, refineries and
oil
companies and electricity to utility companies. Credit is extended based
on an
evaluation of the customer’s financial condition and historical payment
record.
Because
of the Company’s ability to deliver significant volumes of crude oil over a
multi-year period, the Company secured a thirty-nine month sales agreement,
beginning in late 2002, with a major California refiner whereby the Company
sold
over 90% of its California production under a negotiated pricing mechanism.
This
contract ended on January 31, 2006. Pricing in this agreement was based upon
the
higher of the average of the local field posted prices plus a fixed premium,
or
WTI minus a fixed differential near $6.00 per barrel. Both methods were
calculated using a monthly determination. In addition to providing a premium
above field postings, the agreement effectively eliminated the Company’s
exposure to the risk of widening WTI to California heavy crude price
differentials and allowed the Company to effectively hedge its production
based
on WTI pricing.
On
November 21, 2005, the Company entered into a new crude oil sales contract
for
its California production for deliveries beginning February 1, 2006. The
per
barrel price, calculated on a monthly basis and blended across the various
producing locations, is the higher of 1) the WTI NYMEX crude oil price less
a
fixed differential approximating $8.15, or 2) heavy oil field postings plus
a
premium of approximately $1.35. The initial term of the contract is for four
years with a one-year renewal at the Company’s option.
For
the
three years ended December 31, 2005, the Company has experienced no credit
losses on the sale of oil, gas and natural gas liquids.
The
Company places its temporary cash investments with high quality financial
institutions and limits the amount of credit exposure to any one financial
institution. For the three years ended December 31, 2005, the Company has
not
incurred losses related to these investments. With respect to the Company’s
hedging activities, the Company utilizes more than one counterparty on its
hedges and monitors each counterparty’s credit rating.
The
following summarizes the accounts receivable balances at December 31, 2005
and
2004 and sales activity with significant customers for each of the years
ended
December 31, 2005, 2004 and 2003 (in thousands). The Company does not believe
that the loss of any one customer would impact the marketability of its
California crude oil, gas, natural gas liquids or electricity sold.
Due to
the possibility of refinery constraints in the Utah region, it is possible
that
the loss of the current crude oil sales customer could impact the marketability
of a portion of the Company’s Utah crude oil volumes. The Company is
investigating its market opportunities for this Utah crude oil.
|
|
|
Accounts
Receivable
|
|
Sales
|
|
|||||||||||
|
|
|
For
the Year Ended December 31,
|
|
For
the Year Ended December 31,
|
|
|||||||||||
|
Customer
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
2003
|
|
|||||
|
Oil
& Gas Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
A
|
|
$
|
24,389
|
|
$
|
18,391
|
|
$
|
291,093
|
|
$
|
202,966
|
|
$
|
142,422
|
|
|
B
|
|
|
6,929
|
|
|
5,465
|
|
|
81,342
|
|
|
58,807
|
|
|
5,566
|
|
|
C
|
|
|
1,086
|
|
|
670
|
|
|
11,863
|
|
|
9,138
|
|
|
6,524
|
|
|
|
|
$
|
32,404
|
|
$
|
24,526
|
|
$
|
384,298
|
|
$
|
270,911
|
|
$
|
154,512
|
|
|
Electricity
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
D
|
|
$
|
4,375
|
|
$
|
3,402
|
|
$
|
24,391
|
|
$
|
21,755
|
|
$
|
20,334
|
|
|
E
|
|
|
7,806
|
|
|
2,764
|
|
|
30,893
|
|
|
26,524
|
|
|
24,616
|
|
|
|
|
$
|
12,181
|
|
$
|
6,166
|
|
$
|
55,284
|
|
$
|
48,279
|
|
$
|
44,950
|
|
Sales
amounts will not agree to the Statements of Income due primarily to the effects
of hedging and price sensitive royalties paid on a portion of the Company’s
crude oil sales, which are netted in “Sales of oil and gas” on the Statements of
Income.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment
Oil
and
gas properties, buildings and equipment consist of the following at December
31
(in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Oil
and gas:
|
|
|
|
|
|
||
|
Proved
properties:
|
|
|
|
|
|
||
|
Producing
properties, including intangible drilling costs
|
|
$
|
437,032
|
|
$
|
260,566
|
|
|
Lease
and well equipment(1)
|
|
|
275,346
|
|
|
236,932
|
|
|
|
|
|
712,378
|
|
|
497,498
|
|
|
Unproved
properties
|
|
|
|
|
|
|
|
|
Properties,
including intangible drilling costs
|
|
|
36,440
|
|
|
5,569
|
|
|
Lease
and well equipment
|
|
|
267
|
|
|
2,498
|
|
|
|
|
|
36,707
|
|
|
8,067
|
|
|
|
|
|
749,085
|
|
|
505,565
|
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
208,597
|
|
|
168,994
|
|
|
|
|
|
540,488
|
|
|
336,571
|
|
|
Commercial
and other:
|
|
|
|
|
|
|
|
|
Land
|
|
|
496
|
|
|
297
|
|
|
Buildings
and improvements
|
|
|
4,351
|
|
|
3,703
|
|
|
Machinery
and equipment
|
|
|
17,016
|
|
|
6,681
|
|
|
|
|
|
21,863
|
|
|
10,681
|
|
|
Less
accumulated depreciation
|
|
|
9,367
|
|
|
8,546
|
|
|
|
|
|
12,496
|
|
|
2,135
|
|
|
|
|
$
|
552,984
|
|
$
|
338,706
|
|
|
(1)Includes
cogeneration facility costs.
|
|
|
|
|
|
|
|
The
following sets forth costs incurred for oil and gas property acquisition,
development and exploration activities, whether capitalized or expensed (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Property
acquisitions (1)
|
|
|
|
|
|
|
|
|||
|
Proved
properties
|
|
$
|
97,348
|
|
$
|
440
|
|
$
|
49,326
|
|
|
Unproved
properties
|
|
|
24,566
|
|
|
2,405
|
|
|
853
|
|
|
Development (2)
|
|
|
112,255
|
|
|
66,664
|
|
|
42,391
|
|
|
Exploration
|
|
|
7,661
|
|
|
5,506
|
|
|
788
|
|
|
|
|
$
|
241,830
|
|
$
|
75,015
|
|
$
|
93,358
|
|
(1)
Costs incurred for proved and unproved property acquisitions in 2005 include
the
reclassification of 2004 deposits of $5,505 and $4,716,
respectively..
(2)
Development
costs include $.6 million, $.7 million and $.9 million that were charged
to
expense during 2005, 2004 and 2003, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
In
2005,
the Tri-State area is comprised of the following three acquisitions totaling
approximately 315,000 net acres:
| · |
Niobrara
gas producing assets in Yuma County in northeastern Colorado in
which the
Company has approximately 52% working interest were purchased for
approximately $105 million.
|
| · |
Eastern
Colorado, western Kansas and southwestern Nebraska assets in which
the
Company has approximately 50% working interest were purchased for
approximately $5 million.
|
| · |
Colorado’s
Phillips and Sedgwick Counties in which the Company has approximately
50%
working interest were purchased for approximately $.9 million.
This
Niobrara leasehold position is adjacent to and immediately north
of
Berry’s producing natural gas assets in Yuma County.
|
In
2005,
the Company completed several transactions whereby it now has working interests
in 186,000 gross acres (46,000 net) located in the Williston Basin in North
Dakota. These lease acquisitions, totaling approximately $11 million, cover
several contiguous blocks located primarily on the eastern flank of the Nesson
Anticline.
In
July
2004, the Company purchased approximately 169,000 gross acres with an industry
partner in the Lake Canyon prospect in Utah, of which 124,500 gross (62,250
net)
acres are leased from the Ute Tribe and 44,500 gross (22,250 net) acres are
fee
lands. Total cost to Berry was approximately $2 million. The Company will
drill
and operate shallow wells which target light oil in the Green River formation
and retain a 75% working interest. The Company’s partner will drill and operate
deeper wells and the Company will retain a 25% working interest. The Ute
Tribe
has the option to participate in all wells and retain up to a 25% working
interest. As of December 31, 2005, the Company's minimum obligation under
its
agreement is $9.6 million through 2009.
In
2003,
the Company purchased leases totaling 45,380 acres in the Brundage Canyon
field
in Utah for approximately $45 million and the McVan property totaling 560
acres
in the Poso Creek field in Kern County, California for approximately $2.6
million. The Company capitalized approximately $2.6 million in future
abandonment obligations related to the 2003 acquisitions.
|
Results
of operations from oil and gas producing
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
and
exploration activities (in thousands):
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Sales
to unaffiliated parties
|
|
$
|
349,691
|
$
|
226,876
|
|
$
|
135,848
|
|
|
|
Production
costs
|
|
|
(110,572
|
)
|
|
(80,269
|
)
|
|
(60,927
|
)
|
|
Depreciation,
depletion and amortization
|
|
|
(38,150
|
)
|
|
(29,752
|
)
|
|
(17,258
|
)
|
|
Dry
hole, abandonment and impairment
|
|
|
(5,705
|
)
|
|
(745
|
)
|
|
(4,195
|
)
|
|
|
|
|
195,264
|
|
116,110
|
|
|
53,468
|
|
|
|
Income
tax expenses
|
|
|
(59,664
|
)
|
|
(33,840
|
)
|
|
(9,340
|
)
|
|
|
|
|
|
|
|
|
|
|
||
|
Results
of operations from producing and exploration activities
|
|
$
|
135,600
|
$
|
82,270
|
|
$
|
44,128
|
|
|
The
following table provides an aging of capitalized exploratory well costs based
on
the date the drilling was completed and the number of wells for which
exploratory well costs have been capitalized for a period of greater than
one
year since the completion of drilling (in thousands, except number of
projects):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Capitalized
exploratory well costs that have been capitalized for a period
of one year
or less
|
|
$
|
6,037
|
|
$
|
2,941
|
|
$
|
511
|
|
|
Capitalized
exploratory well costs that have been capitalized for a period
greater
than one year
|
|
|
-
|
|
|
511
|
|
|
-
|
|
|
Balance
at December 31
|
|
$
|
6,037
|
|
$
|
3,452
|
|
$
|
511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of projects that have exploratory well costs that have been capitalized
for a period of greater than one year
|
|
|
-
|
|
|
1
|
|
|
-
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
The
following table reflects the net changes in capitalized exploratory well
costs
during the years ended 2005, 2004 and 2003 (in thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Beginning
balance at January 1
|
|
$
|
3,452
|
|
$
|
511
|
|
$
|
1,684
|
|
|
Additions
to capitalized exploratory well costs pending the determination
of proved
reserves
|
|
|
8,840
|
|
|
3,420
|
|
|
1,081
|
|
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved
reserves
|
|
|
(3,369
|
)
|
|
-
|
|
|
-
|
|
|
Capitalized
exploratory well costs charged to expense
|
|
|
(2,886
|
)
|
|
479
|
|
|
2,254
|
|
|
Ending
balance at December 31
|
|
$
|
6,037
|
$
|
3,452
|
|
$
|
511
|
|
|
In
2004,
included in the amount of exploratory well costs that have been capitalized
for
a period of greater than one year since completion of drilling are costs
of $.5
million that have been capitalized since 2003. These costs are related to
the
Company's diatomite project in the Midway-Sunset field and have been
reclassified from exploratory well costs in 2005.
Dry
hole, abandonment and impairment.
The
$5.7
million reflected on the Company’s income statement under dry hole, abandonment
and impairment is made up of the following three items:
| · |
At
December 31, 2004, the Company was in the process of drilling one
exploratory well on its Midway-Sunset property and one exploratory
well on
its Coyote Flats prospect. These two wells were determined non-commercial
in February 2005 and $2.2 million was incurred and expensed in
2005.
|
| · |
Two
exploratory wells at northern Brundage Canyon were expensed for
$.6
million.
|
| · |
Finally,
the Company impaired the remaining carrying value of its Illinois
and
eastern Kansas prospective CBM acreage acquired in 2002 by $2.9
million.
|
Costs
of
$.7 million which were incurred on the Midway-Sunset property and the
exploratory well on the Coyote Flats prospect as of December 31, 2004 were
charged to expense. During 2003, the Company recorded a pre-tax write down
of
$4.2 million related to two CBM pilot projects.
6. Long-term
and Short-term Debt Obligations
|
|
|
2005
|
|
2004
|
|
||
|
Long-term
debt for the years ended December 31 (in thousands):
|
|
|
|
|
|
||
|
Revolving
bank facility
|
|
$
|
75,000
|
|
$
|
28,000
|
|
Long-term
debt
In
June
2005, the Company completed a new unsecured five year bank credit agreement
(the
Agreement) with a banking syndicate. The Agreement is a revolving credit
facility for up to $500 million with nine banks and replaces the previous
$200
million facility which was due to mature in 2006. Initial borrowings were
$125
million which represented an amount equal to the borrowings outstanding under
the previous credit facility and the initial borrowing base was established
as
$350 million. This transaction is considered a modification of a debt instrument
due to modification of terms in accordance with Emerging Issues Task Force,
(EITF) 98-14,
Debtor’s Accounting forChanges in Line of Credit or Revolving Debt
Arrangements.
The
credit available under the Agreement is $264 million at December 31, 2005
without any increase to the borrowing base. 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 the Company and the
banks
have bilateral rights to one additional redetermination each year.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
6. Long-term
and Short-term Debt Obligations (Cont’d)
The
Agreement matures on July 1, 2010. Interest on amounts borrowed is charged
at
LIBOR plus a margin of 1.00% to 1.75%, or the higher of the lead bank’s prime
rate or the federal funds rate plus .50% plus a margin of 0% to .50% at the
Company’s option, with margins on the various rate options based on the ratio of
credit outstanding to the borrowing base. The Company is required under the
Agreement to pay an annual commitment fee of .25% to .38% on the unused portion
of the credit facility.
The
weighted average interest rate on outstanding borrowings at December 31,
2005
and 2004 was 4.9% and 3.37%, respectively. The Agreement contains restrictive
covenants which, among other things, require the Company to maintain a certain
debt to EBITDA ratio and a minimum current ratio, as defined. The Company
was in
compliance with all such covenants as of December 31, 2005.
Short-term
debt
In
November 2005, the Company completed a new unsecured uncommitted money market
line of credit (Line of Credit). Borrowings under the Line of Credit may
be up
to $30 million for a maximum of 30 days. The Line of Credit may be terminated
at
any time upon written notice by either the Company or the lender. At December
31, 2005 the outstanding balance under this Line of Credit was $11.5 million.
Interest on amounts borrowed is charged at LIBOR plus a margin of approximately
1%. The weighted average interest rate on outstanding borrowings at December
31,
2005 was 5.4%.
7. Shareholders’
Equity
Shares
of
Class A Common Stock (Common Stock) and Class B Stock, referred to collectively
as the "Capital Stock," are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $1.00 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option
of the
holder.
The
Company's Capital Stock activity follows (in number of shares):
|
|
|
Class
A
|
|
Class
B
|
|
||
|
December
31, 2002
|
|
20,852,695
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
51,683
|
-
|
||||
|
Shares
repurchased and retired
|
|
(6
|
)
|
-
|
|||
|
December
31, 2003
|
|
20,904,372
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
155,269
|
-
|
||||
|
Shares
issued under Director deferred compensation plan
|
|
797
|
-
|
||||
|
Shares
repurchased and retired
|
|
(18
|
)
|
-
|
|||
|
December
31, 2004
|
|
21,060,420
|
898,892
|
||||
|
Shares
issued from option exercises
|
|
147,179
|
-
|
||||
|
Shares
issued under Director deferred compensation plan
|
|
1,207
|
-
|
||||
|
Shares
repurchased and retired
|
|
(108,900
|
)
|
-
|
|||
|
December
31, 2005
|
|
21,099,906
|
898,892
|
||||
In
June
2005, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $50 million of the Company's
outstanding Class A Common Stock. Through December 31, 2005, the Company
repurchased 108,900 shares for approximately $6.3 million.
In
December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities
Exchange Act of 1934 to facilitate the repurchase of its shares of common
stock.
Rule 10b5-1 allows a company to purchase its shares at times when it would
not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. This 10b5-1
plan
is authorized under, and is administered consistent with, the Company's $50
million share repurchase program. All repurchases of common stock are made
in
compliance with regulations set forth by the SEC and are subject to market
conditions, applicable legal requirements and other factors.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
7. Shareholders’
Equity (Cont'd)
This
program does not obligate the Company to acquire any particular amount of
common
stock and the plan may be suspended at any time at the Company's
discretion.
Dividends
In
2005,
the Company paid a special dividend of $.10 per share on September 29, 2005
and
increased its regular quarterly dividend by 8%, from $.12 to $.13 per share
beginning with the September 29, 2005 dividend. The Company's annual dividend
is
currently $.52 per share, paid quarterly in March, June, September and
December.
In
2004,
the Company paid a special dividend of $.06 per share on September 29, 2004
and
increased its regular quarterly dividend by 9%, from $.11 to $.12 per share
beginning with the September 2004 dividend. In 2003, the Company paid a special
dividend of $.04 per share on May 2, 2003 and increased its regular quarterly
dividend by 10%, from $.10 to $.11 per share beginning with the June 2003
dividend.
As
of
December 31, 2005, dividends declared on 3,984,080 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by the Company to the surviving member of a group of individuals,
the B
Group, as long as this remaining member shall live.
Dividend
payments are limited by a covenant in the Company's credit facility to the
greater of $20 million or 75% of net income.
Shareholder
Rights Plan
In
November 1999, the Company adopted a Shareholder Rights Agreement and declared
a
dividend distribution of one Right for each outstanding share of Capital
Stock
on December 8, 1999. Each Right, when exercisable, entitles the holder to
purchase one one-hundredth of a share of a Series B Junior Participating
Preferred Stock, or in certain cases other securities, for $38.00. The exercise
price and number of shares issuable are subject to adjustment to prevent
dilution. The Rights would become exercisable, unless earlier redeemed by
the
Company, 10 days following a public announcement that a person or group has
acquired, or obtained the right to acquire, 20% or more of the outstanding
shares of Common Stock or 10 business days following the commencement of
a
tender or exchange offer for such outstanding shares which would result in
such
person or group acquiring 20% or more of the outstanding shares of Common
Stock,
either event occurring without the prior consent of the Company.
The
Rights will expire on December 8, 2009 or may be redeemed by the Company
at $.01
per Right prior to that date unless they have theretofore become exercisable.
The Rights do not have voting or dividend rights, and until they become
exercisable, have no diluting effect on the earnings of the Company. A total
of
250,000 shares of the Company’s Preferred Stock has been designated Series B
Junior Participating Preferred Stock and reserved for issuance upon exercise
of
the Rights.
8. Asset
Retirement Obligations
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the years ended December 31 (in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Beginning
balance at January 1
|
|
$
|
8,214
|
$
|
7,311
|
|
|
|
Liabilities
incurred
|
|
|
2,952
|
|
769
|
|
|
|
Liabilities
settled
|
|
|
(1,382
|
)
|
|
(570
|
)
|
|
Accretion
expense
|
|
|
891
|
|
704
|
|
|
|
|
|
|
|
|
|
||
|
Ending
balance at December 31
|
|
$
|
10,675
|
$
|
8,214
|
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
9. Income
Taxes
The
provision for income taxes consists of the following (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Current:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
$
|
22,666
|
$
|
7,073
|
|
$
|
2,490
|
|
|
|
State
|
|
|
6,990
|
|
2,443
|
|
|
619
|
|
|
|
|
|
|
29,656
|
|
9,516
|
|
|
3,109
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
||
|
Federal
|
|
|
20,640
|
|
11,959
|
|
|
2,027
|
|
|
|
State
|
|
|
207
|
|
(1,144
|
)
|
|
(531
|
)
|
|
|
|
|
|
20,847
|
|
10,815
|
|
|
1,496
|
|
|
|
Total
|
|
$
|
50,503
|
$
|
20,331
|
|
$
|
4,605
|
|
|
The
current deferred tax assets and liabilities are offset and presented as a
single
amount in the financial statements. Similarly, the non-current deferred tax
assets and liabilities are presented in the same manner. The following table
summarizes the components of the total deferred tax assets and liabilities
before such financial statement offsets. The components of the net deferred
tax
liability consist of the following at December 31
(in thousands):
|
|
|
2005
|
|
2004
|
|
||
|
Deferred
tax asset:
|
|
|
|
|
|
||
|
Federal
benefit of state taxes
|
|
$
|
2,712
|
$
|
1,308
|
|
|
|
Credit
carryforwards
|
|
|
31,929
|
|
26,478
|
|
|
|
Stock
option costs
|
|
|
2,352
|
|
1,700
|
|
|
|
Derivatives
|
|
|
16,253
|
|
658
|
|
|
|
Other,
net
|
|
|
139
|
|
1,610
|
|
|
|
|
|
|
53,385
|
|
31,754
|
|
|
|
Deferred
tax liability:
|
|
|
|
|
|
||
|
Depreciation
and depletion
|
|
|
(102,754
|
)
|
|
(76,311
|
)
|
|
Other,
net
|
|
|
(289
|
)
|
|
152
|
|
|
|
|
|
|
|
|
||
|
|
|
|
(103,043
|
)
|
|
(76,159
|
)
|
|
|
|
|
|
|
|
||
|
Net
deferred tax liability
|
|
$
|
(49,658
|
)
|
$
|
(44,405
|
)
|
At
December 31, 2005, the Company's net deferred tax assets and liabilities
were
recorded as a current asset of $4.5 million and a net long-term liability
of
$54.2 million. At December 31, 2004, the Company's net deferred tax assets
and
liabilities were recorded as a current asset of $3.6 million and a long-term
liability of $48 million.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
9. Income
Taxes (Cont’d)
Reconciliation
of the statutory federal income tax rate to the effective income tax rate
follows:
|
|
|
2005
|
|
2004
|
|
2003
|
||||
|
Tax
computed at statutory federal rate
|
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
income taxes, net of federal benefit
|
|
|
3
|
|
|
1
|
|
|
1
|
|
|
Tax
credits
|
|
|
(7
|
)
|
|
(9
|
)
|
|
(24
|
)
|
|
Recognition
of tax basis of properties
|
|
|
-
|
|
(5
|
)
|
|
-
|
|
|
|
Other
|
|
|
-
|
|
|
1
|
|
|
-
|
|
|
Effective
tax rate
|
|
|
31
|
%
|
|
23
|
%
|
|
12
|
%
|
The
Company has approximately $23 million of federal and $17 million of state
(California) EOR tax credit carryforwards available to reduce future income
taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015
for
federal and California, respectively.
10. Commitments
The
Company's contractual obligations as of December 31, 2005 are as follows
(in
thousands):
|
Contractual
Obligations
|
|
Total
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
|||||||
|
Long-term
debt and interest
|
|
$
|
79,500
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
79,500
|
$
|
-
|
$
|
-
|
|
Abandonment
obligations
|
|
|
10,675
|
|
315
|
|
360
|
|
539
|
|
556
|
|
556
|
|
8,349
|
|
Operating
lease obligations
|
|
|
802
|
|
538
|
|
138
|
|
108
|
|
18
|
|
-
|
|
-
|
|
Drilling
and rig obligations
|
|
|
16,698
|
|
8,948
|
|
2,400
|
|
2,950
|
|
2,400
|
|
-
|
|
-
|
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
||||||
|
transportation
contracts
|
|
|
36,454
|
|
3,706
|
|
4,574
|
|
4,398
|
|
4,386
|
|
4,386
|
|
15,004
|
|
Total
|
|
$
|
144,129
|
$
|
13,507
|
$
|
7,472
|
$
|
7,995
|
$
|
86,860
|
$
|
4,942
|
$
|
23,353
|
Long-term
debt and interest
-
Long-term debt and related interest of approximately 6% on the long-term
debt
borrowings can be paid before its maturity date without significant
penalty.
Operating
leases -
The
Company leases corporate and field offices in California and in Denver. Rent
expense with respect to the Company's lease commitments for the years ended
December 31, 2005, 2004 and 2003 was $.6 million, $.6 million, and $.5 million,
respectively.
Drilling
obligation
-
The
Company intends to participate in the drilling of over 16 gross wells on
its
Lake Canyon prospect over the next four years. The Company's minimum obligation
under its exploration and development agreement is $9.6 million.
Drilling
rig obligation
- The
Company is obligated in operating lease agreements for two drilling rigs,
each
for one year ending in 2006.
Firm
natural gas transportation
-
The
Company entered into several firm transportation contracts which provide
the
Company additional flexibility in securing its natural gas supply and allows
the
Company to potentially benefit from lower natural gas prices in the Rocky
Mountains compared to natural gas prices in California.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
11. Contingencies
The
Company has accrued environmental liabilities for all sites, including sites
in
which governmental agencies have designated the Company as a potentially
responsible party, where it is probable that a loss will be incurred and
the
minimum cost or amount of loss can 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 higher than the liability
currently accrued. Amounts currently accrued are not significant to the
financial position of the Company and Management believes, based upon current
site assessments, that the ultimate resolution of these matters will not
require
substantial additional accruals. 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 the Company’s financial position, results of
operations or liquidity.
12. Equity
Compensation Plans
On
December 2, 1994, the Board of Directors of the Company adopted the Berry
Petroleum Company 1994 Stock Option Plan which was restated and amended in
December 1997 and December 2001 (the 1994 Plan or Plan) and approved by the
shareholders in May 1998 and May 2002, respectively. The 1994 Plan provided
for
the granting of stock options to purchase up to an aggregate of 3,000,000
shares
of Common Stock. All options, with the exception of the formula grants to
non-employee Directors, were granted at the discretion of the Compensation
Committee of the Board of Directors. The term of each option did not exceed
ten
years from the date the options were granted. The 1994 Plan expired on December
2, 2004, and the shareholders approved a new equity incentive plan in May
2005.
The
2005
Equity Incentive Plan (the 2005 Plan) provides for granting of equity
compensation to purchase up to an aggregate of 1,450,000 shares of Common
Stock.
All equity grants are at market value on the date of grant and at the discretion
of the Compensation Committee or the Board of Directors. The term of each
employee grant did not exceed ten years from the grant date and vest 25%
per
year for 4 years. The 2005 Plan also allows for grants to non-employee
Directors. During 2005, each of the non-employee Directors received 5,000
options at the market value on the date of grant. The options granted to
the
non-employee Directors vest immediately.
Stock
Options
Effective
January 1, 2004, the Company voluntarily adopted the fair value method of
accounting for its stock option plans as prescribed by SFAS 123, Accounting
for Stock-Based Compensation.
The
modified prospective method was selected as described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognized stock option compensation expense as
if it
had applied the fair value method to account for unvested stock options from
its
original effective date. Compensation expense under the fair value method
for
the years ended December 31, 2005 and 2004 was $2.9 million and $1.5 million,
respectively. Additionally, the Company recorded $4.4 million and $3.9 million
for the years ended December 31, 2004 and 2003, respectively, in compensation
expense under the variable method of accounting prior to the modification
of
certain exercise provisions of the Company's 1994 Plan on July 29,
2004.
The
fair
value of each option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the assumptions noted in the
following table. Expected volatilities are based on the historical volatility
of
the Company's stock. The Company uses historical data to estimate option
exercises and employee terminations within the valuation model; separate
groups
of employees that have similar historical exercise behavior are considered
separately for valuation purposes. The expected term of options granted is
based
on historical exercise behavior and represents the period of time that options
granted are expected to be outstanding; the range given below results from
certain groups of employees exhibiting different exercise behavior. The risk
free rate for periods within the contractual life of the option is based
on U.S.
Treasury rates in effect at the time of grant.
|
|
2005
|
|
2004
|
|
Expected
volatility
|
28%
- 32%
|
|
25%
|
|
Weighted-average
volatility
|
32%
|
|
25%
|
|
Expected
dividends
|
.92%
- 1.3%
|
|
1.27%
- 2.45%
|
|
Expected
term (in years)
|
4
-
5
|
|
4
-
7
|
|
Risk-free
rate
|
3.8%
- 4.4%
|
|
3.4%
- 4.4%
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont'd)
The
following table summarizes information related to stock options outstanding
and
exercisable as of December 31, 2005:
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
Average
|
|
|
|
Weighted
|
|
Range
of
|
|
|
|
Average
|
|
Remaining
|
|
|
|
Average
|
|
Exercise
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
Options
|
|
Exercise
|
|
Prices
|
|
Outstanding
|
|
Price
|
|
Life
|
|
Exercisable
|
|
Price
|
|
$10.63
- $23.76
|
|
707,575
|
|
$17.27
|
6.61
|
514,475
|
|
$16.80
|
||
|
$23.77
- $36.90
|
|
103,500
|
|
28.79
|
8.47
|
25,875
|
|
28.79
|
||
|
$36.91
- $50.04
|
479,875
|
|
43.21
|
8.94
|
131,188
|
|
43.26
|
|||
|
$50.05
- $63.18
|
|
264,463
|
|
61.25
|
9.95
|
40,000
|
|
61.29
|
||
|
Total
|
|
1,555,413
|
|
$33.52
|
8.02
|
711,538
|
|
$24.61
|
Weighted
average option exercise price information for the years ended December 31
is as
follows:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Outstanding
at January 1
|
|
$
|
25.41
|
|
$
|
16.50
|
|
$
|
15.17
|
|
|
Granted
during the year
|
|
|
59.13
|
|
|
40.60
|
|
|
19.31
|
|
|
Exercised
during the year
|
|
|
16.80
|
|
|
15.73
|
|
|
13.15
|
|
|
Cancelled/expired
during the year
|
|
|
37.36
|
|
|
18.02
|
|
|
16.55
|
|
|
Outstanding
at December 31
|
|
|
33.52
|
|
|
25.41
|
|
|
16.50
|
|
|
Exercisable
at December 31
|
|
|
24.61
|
|
|
17.61
|
|
|
15.62
|
|
The
following is a summary of stock option activity for the years ended December
31
is as follows:
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Balance
outstanding, January 1
|
|
|
1,565,625
|
|
|
1,701,925
|
|
|
1,604,575
|
|
|
Granted
|
|
|
299,463
|
|
|
567,750
|
|
|
411,500
|
|
|
Exercised
|
|
|
(302,600
|
)
|
|
(581,550
|
)
|
|
(294,150
|
)
|
|
Canceled/expired
|
|
|
(7,075
|
)
|
|
(122,500
|
)
|
|
(20,000
|
)
|
|
Balance
outstanding, December 31
|
|
|
1,555,413
|
|
|
1,565,625
|
|
|
1,701,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at December 31
|
|
|
711,538
|
|
|
688,275
|
|
|
1,037,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for future grant
|
|
|
1,150,537
|
|
|
-
|
|
|
615,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average remaining contractual life (years)
|
|
|
8
|
|
|
8
|
|
|
7
|
|
|
Weighted
average fair value per option granted during the year based on
the
Black-Scholes pricing model
|
|
$
|
19.16
|
|
$
|
10.10
|
|
$
|
5.11
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont'd)
The
total
intrinsic value of options exercised during the years ended December 31,
2005,
2004 and 2003, was $12.6 million, $7.2 million and $1.6 million, respectively.
At December 31, 2005, the intrinsic value of options outstanding was $36.8
million and the intrinsic value of exercisable options was $26.2
million.
As
of
December 31, 2005, there was $8.2 million of total unrecognized compensation
cost related to stock options granted under the Plan. This cost is expected
to
be recognized over a weighted-average period over 4 years.
Restricted
Stock Units
Under
the
2005 Equity Incentive Plan, the Company began a long-term incentive program
whereby restricted stock units (RSUs) are available for grant to certain
employees and
vest 25%
per year over 4 years. In 2005, 70,950
RSUs were granted with a weighted average fair value per unit granted during
the
year of $61.29. As
of
December 31, 2005, there was $3.7 million of total unrecognized compensation
cost related to RSUs granted under the Plan. This cost is expected to be
recognized over a weighted-average period of 4 years, which is also the weighted
average remaining contractual life. Unearned compensation under the restricted
stock award plan is amortized over the vesting period. The Company will pay
cash
compensation on the RSUs in an equivalent amount of actual dividends paid
on a
per share basis of the Company’s outstanding common stock.
13. 401(k)
Plan
The
Company sponsors a defined contribution thrift plan under section 401(k)
of the
Internal Revenue Code to assist all eligible employees in providing for
retirement or other future financial needs. Employee contributions (up to
6% of
earnings) were matched by the Company at a range of $1 for $1 up to a maximum
of
$1.50 for $1 based on monthly profit levels for the Company. Effective November
1, 1992, the 401(k) Plan was modified to provide for increased Company matching
of employee contributions whereby the monthly Company matching contributions
will range from 6% to 9% of eligible participating employee earnings, if
certain
financial targets are achieved. The Company's contributions to the 401(k)
Plan
were $1.1 million, $.8 million and $.5 million in 2005, 2004 and 2003,
respectively. Approximately 99% of full-time employees participate in the
Plan.
In December 2005, the 401(k) Plan was amended whereby effective January 1,
2006,
the Company’s matching contribution will be $1 for $1 up to a maximum of 8% of
an employee’s eligible compensation.
14. Director
Deferred Compensation Plan
The
Company established a non-employee director deferred stock and compensation
plan
to permit eligible directors, in recognition of their contributions to the
Company, to receive fees as compensation and defer recognition of their
compensation in whole or in part to a Stock Unit Account or an Interest Account.
When the eligible director ceases to be a director, the distribution from
the
Stock Unit Account shall be made in shares using an established market value
date and the distribution from the Interest Account shall be made in cash.
The
aggregate number of shares which may be issued to eligible directors under
the
plan shall not exceed 250,000, subject to adjustment for corporate transactions
that change the amount of outstanding stock. The plan may be amended at any
time, not more than once every six months, by the Compensation Committee
or the
Board of Directors and shall terminate, unless extended, on May 31,
2008.
Amounts
allocated to the Stock Unit Account have the right to receive an amount equal
to
the dividends per share declared by the Company on the applicable dividend
payment date and this “dividend equivalent” shall be treated as reinvested in an
additional number of units and credited to their account using an established
market value date. Amounts allocated to the Interest Account are credited
with
interest at an established interest rate.
Shares
earned and deferred in accordance with the plan as of December 31, 2005,
2004
and 2003 were 6,885, 7,481 and 11,037, respectively.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
15. Hedging
From
time
to time, the Company enters into crude oil and natural gas hedge contracts,
the
terms of which depend on various factors, including Management’s view of future
crude oil and natural gas prices and the Company’s future financial commitments.
This hedging program is designed to moderate the effects of a severe crude
oil
price downturn and protect certain operating margins in the Company's California
operations. Currently, the hedges are in the form of swaps and collars, however,
the Company may use a variety of hedge instruments in the future. Management
regularly monitors the crude oil and natural gas markets and the Company’s
financial commitments to determine if, when, and at what level some form
of
crude oil and/or natural gas hedging or other price protection is appropriate.
All of these hedges have historically been deemed to be cash flow hedges
with
the marked-to-market valuations provided by external sources, based on prices
that are actually quoted.
In
June
2005, the Company entered into derivative instruments (zero-cost collars)
for
approximately 10,000 Bbl/D for the period January 1, 2006 through December
31,
2009. Based on WTI pricing, the floor is $47.50 and the ceiling is $70 per
barrel. Upon entering into the new crude oil sales contract for California
production in November 2005, the Company redesignated its existing crude
oil
collars as cash flow hedges related to California crude oil production, and
there was no related effect to Other Comprehensive Income with regard to
this
redesignation. The use of hedging transactions also involves the risk that
the
counterparties will be unable to meet the financial terms of such transactions.
With respect to the Company’s hedging activities, the Company utilizes multiple
counterparties on its hedges and monitors each counterparty’s credit rating.
After the June hedge transaction, a significant credit risk concentration
existed in one broker. In July 2005, the Company reduced the concentration
as
the hedges were transferred to multiple counterparties. The Company is not
required to issue collateral on these hedging transactions.
At
December 31, 2005 and 2004, Accumulated Other Comprehensive Loss consisted
of $24.4 million and $1 million, respectively, net of tax of unrealized losses
from the Company's crude oil and natural gas swaps and collars. Deferred
net
losses recorded in Accumulated Other Comprehensive Loss at December 31,
2005 are expected to be reclassified to earnings over the life of the underlying
hedging contracts.
| 16. |
Pro
Forma Results (unaudited)
|
On
January 27, 2005, the Company acquired certain interests in the Niobrara
field
in northeastern Colorado for approximately $105 million (J-W Acquisition)
to
increase natural gas reserves and production. Assets purchased include $93
million of gas properties, $6 million of pipeline, and $ 5 million of
compression equipment. Liabilities assumed included $1 million of asset
retirement obligations.
The
unaudited pro forma results presented below for the year ended December 31,
2005
and 2004 have been prepared to give effect to the J-W Acquisition on the
Company’s results of operations under the purchase method of accounting as if it
had been consummated on January 1, 2004. The unaudited pro forma results
do not
purport to represent the results of operations that actually would have occurred
on such date or to project the Company’s results of operations for any future
date or period. (in thousands, except per share data):
|
2005
|
2004
|
||||
|
Proforma
Revenue
|
$
408,088
|
$
295,243
|
|||
|
Proforma
Income from operations
|
190,970
|
121,688
|
|||
|
Proforma
Net income
|
112,660
|
72,393
|
|||
|
Proforma
Basic earnings per share
|
5.11
|
3.31
|
|||
|
Proforma
Diluted earnings per share
|
5.01
|
3.22
|
|||
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
| 17. |
Lease
Receivable
|
Canyon
Drilling LLC (“Canyon”), a 100% owned Colorado entity, was dissolved in the
third quarter of 2005. Canyon owned a drilling rig which was leased to a
third
party. After the dissolution, the drilling rig is 100% owned by the Company.
Concurrent with the dissolution of Canyon, the original lease was terminated
and
a revised three-year lease agreement was executed which has similar terms
to the
original lease. The revised lease includes a three year purchase option.
The
total net investment in the revised lease is approximately $3.4 million and
is
accounted for as a direct financing lease as defined by SFAS No. 13,
Accounting
for Leases.
Net
investment in this lease as of December 31, 2005 is as follows (in
thousands):
|
Net
minimum lease payments receivable
|
$
4,781
|
|
|
Unearned
income
|
(1,382
|
)
|
|
Net
investment in direct financing lease
|
$
3,399
|
Estimated
future minimum lease payments, including the purchase option, to be received
as
of December 31, 2005 are as follows (in thousands):
|
2006
|
$
504
|
||
|
2007
|
504
|
||
|
2008
|
3,773
|
||
|
Total
|
$
4,781
|
Drilling
Rigs
During
2005, the Company purchased two drilling rigs. The first rig is leased to
a
drilling company under a three-year contract (see above), while the second
rig
is currently being refurbished in preparation for leasing under a similar
drilling contract. Both rigs carry purchase options available to the drilling
company.
18. Quarterly
Financial Data (unaudited)
The
following is a tabulation of unaudited quarterly operating results for 2005
and
2004 (in thousands, except per share data).
|
|
|
|
|
|
|
|
|
Basic
Net
|
|
Diluted
Net
|
|
|||||
|
|
|
Operating
|
|
Gross
|
|
Net
|
|
Income
|
|
Income
|
|
|||||
|
2005
|
|
Revenues
|
|
Profit
(2)
|
|
Income
|
|
Per
Share
|
|
Per
Share
|
|
|||||
|
First
Quarter
|
|
$
|
87,847
|
|
$
|
41,931
|
|
$
|
22,505
|
|
$
|
1.02
|
|
$
|
1.00
|
|
|
Second
Quarter
|
|
|
92,339
|
|
|
45,092
|
|
|
25,260
|
|
|
1.14
|
|
|
1.13
|
|
|
Third
Quarter
|
|
|
109,372
|
|
|
59,880
|
|
|
34,219
|
|
|
1.55
|
|
|
1.52
|
|
|
Fourth
Quarter
|
|
|
115,363
|
|
|
52,754
|
|
|
30,372
|
|
|
1.39
|
|
|
1.35
|
|
|
|
|
$
|
404,921
|
|
$
|
199,657
|
|
$
|
112,356
|
|
$
|
5.10
|
|
$
|
5.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$
|
57,139
|
|
$
|
20,948
|
|
$
|
10,364
|
|
$
|
0.48
|
|
$
|
0.47
|
|
|
Second
Quarter
|
|
|
64,046
|
|
|
25,591
|
|
|
15,278
|
|
|
0.70
|
|
|
0.68
|
|
|
Third
Quarter
|
|
|
72,904
|
|
|
31,716
|
|
|
18,229
|
|
|
0.83
|
|
|
0.82
|
|
|
Fourth
Quarter (1)
|
|
|
80,431
|
|
|
36,989
|
|
|
25,316
|
|
|
1.15
|
|
|
1.11
|
|
|
|
|
$
|
274,520
|
|
$
|
115,244
|
|
$
|
69,187
|
|
$
|
3.16
|
|
$
|
3.08
|
|
(1)
During the fourth quarter of 2004, the Company recorded a net tax benefit
of
approximately $2.3 million, primarily due to the recognition of deferred
tax
assets related to certain properties and other tax items.
(2)
Information has been revised in 2004 to reflect the Company's change in
allocation of technical labor as disclosed in Note 2.
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
19. Subsequent
Events
On
January 27, 2006 the Company announced that it had entered into an agreement
with a private seller to acquire a 50% working interest in natural gas assets
in
the Piceance Basin of western Colorado for approximately $159 million to
increase natural gas reserves and production. The acquisition was funded
under
the Company's existing credit facility. The effective date of the transaction
is
October 1, 2005. The Company purchased 100% interests in Piceance Operating
Company (which owns a 50% working interest in the acquired assets). The Company
will finalize its purchase price allocation after determining the post-closing
adjustments. The transaction closed on February 28, 2006.
In
February 2006, the Company purchased a third drilling rig for approximately
$5
million for use in its Piceance Basin development program.
On
March
1, 2006, the Board of Directors of the Company approved a two-for-one split
of
the Company's Class A Common Stock (Common Stock) and Class B Stock,
subject
to shareholder approval of an increase in authorized shares.The stock split
will
require that shareholders authorize the issuance of new shares at the Company’s
May 17, 2006 annual meeting. Berry's shareholders will be asked to approve
an
increase in the Company's authorized shares of Common Stock to 100 million
from
the current 50 million shares and the Class B Stock to 3.0 million shares
from
1.5 million shares. If approved, Berry’s transfer agent will distribute to each
holder of record as of the close of business on May 17, 2006, one additional
share for every share of stock held. The split will be in the form of a stock
dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should
begin trading on a post-split basis June 5, 2006. Based on shares outstanding
on
March 1, 2006, Berry would have approximately 42.2 million shares of Common
Stock and 1.8 million shares of Class B Stock outstanding following the proposed
stock split.
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent interests owned by the Company located solely within
the
United States. Proved reserves represent estimated quantities of crude oil
and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed oil and gas reserves
are the
quantities expected to be recovered through existing wells with existing
equipment and operating methods. Proved undeveloped oil and gas reserves
are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells for which relatively major expenditures are required
for
completion.
Disclosures
of oil and gas reserves which follow are based on estimates prepared by
independent engineering consultants as of December 31, 2005, 2004 and 2003.
Such
estimates are subject to numerous uncertainties inherent in the estimation
of
quantities of proved reserves and in the projection of future rates of
production and the timing of development expenditures. These estimates do
not
include probable or possible reserves. The information provided does not
represent Management's estimate of the Company's expected future cash flows
or
value of proved oil and gas reserves.
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
Changes
in estimated reserve quantities
The
net
interest in estimated quantities of proved developed and undeveloped reserves
of
crude oil and natural gas at December 31, 2005, 2004 and 2003, and changes
in
such quantities during each of the years then ended were as follows (in
thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||||||||||||||||||||||
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
Oil
|
|
Gas
|
|
|
|
|||||||||||
|
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
|||||||||||
|
Proved
developed and Undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Beginning
of year
|
|
|
105,549
|
25,724
|
109,836
|
|
106,640
|
|
|
19,680
|
|
|
109,920
|
|
|
100,744
|
|
|
5,850
|
|
|
101,719
|
|
|||||||
|
Revision
of previous estimates
|
|
|
(681
|
)
|
4,084
|
-
|
|
2,975
|
|
|
8,246
|
|
|
4,349
|
|
|
(82
|
)
|
|
293
|
|
|
(33
|
)
|
||||||
|
Improved
recovery
|
|
|
753
|
-
|
753
|
|
2,021
|
|
|
-
|
|
|
2,021
|
|
|
1,271
|
|
|
-
|
|
|
1,271
|
|
|||||||
|
Extensions
and discoveries
|
|
|
6,228
|
24,605
|
10,329
|
|
2,736
|
|
|
714
|
|
|
2,855
|
|
|
1,853
|
|
|
2,005
|
|
|
2,187
|
|
|||||||
|
Property
sales
|
|
|
(1,035
|
)
|
-
|
(1,035
|
)
|
|
(127
|
)
|
|
(77
|
)
|
|
(140
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|||||
|
Production
|
|
|
(7,081
|
)
|
(7,919
|
)
|
(8,401
|
)
|
|
(7,044
|
)
|
|
(2,839
|
)
|
|
(7,517
|
)
|
|
(5,827
|
)
|
|
(1,277
|
)
|
|
(6,040
|
)
|
||||
|
Purchase
of reserves in place (1)
|
|
|
-
|
88,817
|
14,803
|
|
132
|
|
|
-
|
|
|
132
|
|
|
8,681
|
|
|
12,809
|
|
|
10,816
|
|
|||||||
|
Royalties
converted to working interest
|
|
|
-
|
-
|
-
|
|
(1,784
|
)
|
|
-
|
|
|
(1,784
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|||||||
|
End
of year
|
|
|
103,733
|
135,311
|
126,285
|
|
105,549
|
|
|
25,724
|
|
|
109,836
|
|
|
106,640
|
|
|
19,680
|
|
|
109,920
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Beginning
of year
|
|
|
78,207
|
20,048
|
81,549
|
|
78,145
|
|
|
12,207
|
|
|
80,180
|
|
|
72,889
|
|
|
3,252
|
|
|
73,431
|
|
|||||||
|
End
of year
|
|
|
78,308
|
70,519
|
90,061
|
|
78,207
|
|
|
20,048
|
|
|
81,549
|
|
|
78,145
|
|
|
12,207
|
|
|
80,180
|
|
|||||||
(1)
Refer to Note 16 to the financial statements.
The
standardized measure has been prepared assuming year end sales prices adjusted
for fixed and determinable contractual price changes, current costs and
statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense. Cash outflows for future production and development costs
include cash flows associated with the ultimate settlement of the asset
retirement obligation.
Standardized
measure of discounted future net cash flows from estimated production of
proved
oil and gas reserves (in thousands):
|
|
|
2005
|
|
2004
|
|
2003
|
|
|||
|
Future
cash inflows
|
|
$
|
6,088,170
|
$
|
3,281,155
|
|
$
|
2,845,767
|
|
|
|
Future
production costs
|
|
|
(2,297,638
|
)
|
|
(1,405,432
|
)
|
|
(1,246,340
|
)
|
|
Future
development costs
|
|
|
(333,722
|
)
|
|
(216,859
|
)
|
|
(198,279
|
)
|
|
Future
income tax expenses
|
|
|
(1,115,516
|
)
|
|
(355,764
|
)
|
|
(324,097
|
)
|
|
Future
net cash flows
|
|
|
2,341,294
|
|
1,303,100
|
|
|
1,077,051
|
|
|
|
10%
annual discount for estimated timing of cash flows
|
|
|
(1,089,914
|
)
|
|
(616,352
|
)
|
|
(548,831
|
)
|
|
Standardized
measure of discounted future net cash flows
|
|
$
|
1,251,380
|
$
|
686,748
|
|
$
|
528,220
|
|
|
|
Average
sales prices at December 31:
|
|
|
|
|
|
|
|
|
||
|
Oil
($/Bbl)
|
|
$
|
48.38
|
$
|
29.49
|
|
$
|
25.77
|
|
|
|
Gas
($/Mcf)
|
|
$
|
7.91
|
$
|
6.61
|
|
$
|
4.94
|
|
|
|
BOE
Price
|
|
$
|
48.21
|
$
|
29.87
|
|
$
|
25.89
|
|
|
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
Changes
in standardized measure of discounted future net cash flows from proved oil
and
gas reserves (in thousands):
|
|
2005
|
|
2004
|
|
2003
|
|
||||
|
|
|
|
|
|
|
|
|
|||
|
Standardized
measure - beginning of year
|
|
$
|
686,748
|
$
|
528,220
|
|
$
|
449,857
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Sales
of oil and gas produced, net of production costs
|
|
|
(240,039
|
)
|
|
(144,457
|
)
|
|
(75,143
|
)
|
|
Revisions
to estimates of proved reserves:
|
|
|
|
|
|
|
|
|
||
|
Net
changes in sales prices and production costs
|
|
|
702,867
|
|
190,861
|
|
|
45,292
|
|
|
|
Revisions
of previous quantity estimates
|
|
|
5
|
|
40,419
|
|
|
(229
|
)
|
|
|
Improved
recovery
|
|
|
12,267
|
|
18,787
|
|
|
9,400
|
|
|
|
Extensions
and discoveries
|
|
|
168,291
|
|
26,541
|
|
|
16,171
|
|
|
|
Change
in estimated future development costs
|
|
|
(157,068
|
)
|
|
(56,314
|
)
|
|
(75,841
|
)
|
|
Purchases
of reserves in place
|
|
|
103,150
|
|
962
|
|
|
47,700
|
|
|
|
Sales
of reserves in place
|
|
|
(9,613
|
)
|
|
(1,043
|
)
|
|
-
|
|
|
Development
costs incurred during the period
|
|
|
111,613
|
|
65,971
|
|
|
41,461
|
|
|
|
Accretion
of discount
|
|
|
87,650
|
|
68,312
|
|
|
59,983
|
|
|
|
Income
taxes
|
|
|
(392,886
|
)
|
|
(16,890
|
)
|
|
(8,896
|
)
|
|
Other
|
|
|
178,395
|
|
(21,430
|
)
|
|
18,465
|
|
|
|
Royalties
converted to working interest
|
|
|
-
|
|
(13,191
|
)
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Net
increase (decrease)
|
|
|
564,632
|
|
158,528
|
|
|
78,363
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Standardized
measure - end of year
|
|
$
|
1,251,380
|
$
|
686,748
|
|
$
|
528,220
|
|
|
None.
Evaluation
of Disclosure Controls and Procedures
As
of
December 31, 2005, the Company has carried out an evaluation under the
supervision of, and with the participation of, the Company's Management,
including the Company's Chief Executive Officer and Chief Financial Officer,
of
the effectiveness of the design and operation of the Company's disclosure
controls and procedures pursuant to Rule 13a-15 under the Securities Exchange
Act of 1034, as amended.
Based
on
their evaluation as of December 31, 2005, the Chief Executive Officer and
Chief
Financial Officer of the Company have concluded that the Company’s 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 the Company in the reports that it
files
or submits under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in SEC rules and
forms.
Management’s
Report on Internal Control Over Financial Reporting
Internal
control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f)
promulgated under the Securities Exchange Act of 1934, as amended, as a process
designed by, or under the supervision of, the Company's principal executive
and
principal financial officers, or persons performing similar functions, and
effected by the Company's Board of Directors, Management and other personnel,
to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external reporting purposes
in
accordance with U.S. generally accepted accounting principles and includes
those
policies and procedures that:
· pertain
to the maintenance of records that in reasonable detail accurately and fairly
reflect the transactions and dispositions of the Company's assets;
· provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company
are
being made only in accordance with authorizations of the Company's Management
and Directors; and
· provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the Company's assets that could have a
material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. All internal control systems, no matter
how
well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect
to
financial statement preparation and presentation. Additionally, projections
of
any evaluation of effectiveness to future periods are subject to the risk
that
controls may become inadequate because of changes in conditions, or that
the
degree of compliance with the policies or procedures may
deteriorate.
Management
is responsible for establishing and maintaining adequate internal control
over
financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). Under the supervision and with the participation of
Management, including the principal executive officer and principal financial
officer, the Company conducted an evaluation of the effectiveness of its
internal control over financial reporting based on the framework in Internal
Control - Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission. Based
on
its evaluation under the framework in Internal
Control - Integrated Framework,
Management concluded that its internal control over financial reporting was
effective as of December 31, 2005.
Management’s
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2005 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm,
as
stated in their report which is included herein.
Changes
in Internal Control Over Financial Reporting
There
were no changes in the Company's internal control over financial reporting
that
occurred during the three months ended December 31, 2005 that have materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting. The Company may make changes in its internal
control procedures from time to time in the future.
On
March
1, 2006, the Board of Directors of the Company approved a two-for-one split
of
the Company's Class A Common Stock (Common Stock) and Class B Stock, subject
to
shareholder approval of an increase in authorized shares.The stock split
will
require that shareholders authorize the issuance of new shares at the Company’s
May 17, 2006 annual meeting. Berry's shareholders will be asked to approve
an
increase in the Company's authorized shares of Common Stock to 100 million
from
the current 50 million shares and the Class B Stock to 3.0 million shares
from
1.5 million shares. If approved, Berry’s transfer agent will distribute to each
holder of record as of the close of business on May 17, 2006, one additional
share for every share of stock held. The split will be in the form of a stock
dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should
begin trading on a post-split basis June 5, 2006. Based on shares outstanding
on
March 1, 2006, Berry would have approximately 42.2 million shares of Common
Stock and 1.8 million shares of Class B Stock outstanding following the proposed
stock split.
On
February 28, 2006 the Company completed the acquisition of a 50% working
interest in natural gas assets in the Grand Valley field in the Piceance
Basin
of western Colorado for approximately $159 million. The purchase was funded
under the Company's existing credit facility. Berry is the operator and owns
a
50% working interest in 6,314 gross acres targeting gas in the Williams Fork
section of the Mesaverde formation. Estimated daily production, net to Berry's
interest, is approximately 1 million cubic feet of natural gas per day (MMcf/D)
from three producing wells. The Company internally estimates 330 billion
cubic
feet of proved and probable
reserves,
none of which are included in Berry's 2005 year-end proved reserves of 126
million barrels of oil equivalent (BOE). With this acquisition, the Company's
current estimate of its total proved reserves is over 130 million BOE. Berry
is
increasing its 2006 capital budget by an additional $18 million to $208 million
for 2006 to accelerate the development of this resource. Seven wells are
currently awaiting completion which is expected by April 1, 2006.
On
January 31, 2006 the Company paid cash bonuses to employees related to the
Company's and each individual's performance in 2005. Mr Heinemann was paid
$500,000, Mr. Goehring $185,500, Mr. Duginski $212,000, Mr. Magruder $212,000
and Mr. Crawford $96,300. Effective January 1, 2006 Mr. Heinemann's salary
was increased to $500,000, Mr. Goehring's to $250,000, Mr. Duginski's to
$250,000, Mr. Magruder's to $250,000 and Mr. Crawford's to
$200,000.
Effective
in January 2006 the compensation of the Chairman of the Board, Mr. Martin
H.
Young, Jr., was increased by providing that he be paid the same meeting fees
as
all other directors in addition to the annual retainer of $125,000 and a
special
award of $40,000 was made to Mr. Young in recognition of extraordinary
commitment of time and resources by him on behalf of the Company in 2005.
Mr. Young has elected to receive all compensation paid for his service to
the
Company in the form of Company stock under the terms of the Non-Employee
Director Deferred Compensation Plan.
PART
III
The
information called for by Item 10 is incorporated by reference from information
under the captions “Corporate Governance and Board Matters” and “Compliance with
Section 16(a) of the Securities Exchange Act of 1934” in the Company’s
definitive proxy statement to be filed pursuant to Regulation 14A no later
than
120 days after the close of its fiscal year. Information regarding Executive
Officers is contained in this report in Part I, Item 1
Business.
The
information called for by Item 11 is incorporated by reference from information
under the caption "Executive Compensation" in the Company's definitive proxy
statement to be filed pursuant to Regulation 14A no later than 120 days after
the close of its fiscal year.
The
information called for by Item 12 is incorporated by reference from information
under the captions "Security Ownership of Directors and Management" and
"Principal Shareholders" in the Company's definitive proxy statement to be
filed
pursuant to Regulation 14A no later than 120 days after the close of its
fiscal
year.
The
information called for by Item 13 is incorporated by reference from information
under the caption "Certain Relationships and Related Transactions" in the
Company's definitive proxy statement to be filed pursuant to Regulation 14A
no
later than 120 days after the close of its fiscal year.
The
information called for by Item 14 is incorporated by reference from the
information under the caption “Fees to Independent Accountants for 2005 and
2004” in the Company’s definitive proxy statement to be filed pursuant to
Regulation 14A no later than 120 days after the close of its fiscal
year.
PART
IV
A.
Financial Statements and Schedules
See
Index
to Financial Statements and Supplementary Data in Item 8.
B.
Exhibits
|
Exhibit
No.
|
Description
of Exhibit
|
|
|
|
|
3.1
|
Registrant's
Restated Certificate of Incorporation
|
|
3.2*
|
Registrant's
Restated Bylaws dated July 1, 2005 (filed as Exhibit 3.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly period
ended
June 30, 2005, File No. 1-09735)
|
|
4.1*
|
Registrant's
Certificate of Designation, Preferences and Rights of Series B
Junior
Participating Preferred Stock (filed as Exhibit A to the Registrant's
Registration Statement on Form 8-A12B on December 7, 1999, File
No.
778438-99-000016)
|
|
4.2*
|
Rights
Agreement between Registrant and ChaseMellon Shareholder Services,
L.L.C.
dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B
on
December 7, 1999, File No. 778438-99-000016)
|
|
10.1
|
Description
of Cash Bonus Plan of Berry Petroleum Company
|
|
10.2*
|
Form
of Salary Continuation Agreement dated as of December 5, 1997,
by and
between Registrant and selected employees of the Company (filed
as Exhibit
10.3 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1997, File No. 1-9735)
|
|
10.3*
|
Form
of Salary Continuation Agreements dated as of March 20, 1987, as
amended
August 28, 1987, by and between Registrant and selected employees
of the
Company (filed as Exhibit 10.12 to the Registration Statement on
Form S-1
filed on June 7, 1989, File No. 33-29165)
|
|
10.4*
|
Instrument
for Settlement of Claims and Mutual Release by and among Registrant,
Victory Oil Company, the Crail Fund and Victory Holding Company
effective
October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to
the
Registrant's Registration Statement on Form S-4 filed on May 22,
1987,
File No. 33-13240)
|
|
10.5*
|
Credit
Agreement, dated as of June 27, 2005, by and between the Registrant
and
Wells Fargo Bank, N.A. and other financial institutions (filed
as Exhibit
10.1 to the Registrant's Quarterly Report on Form 10-Q for the
quarterly
period ended June 30, 2005, File No. 1-9735)
|
|
10.6
|
First
Amendment to Credit Agreement, dated as of December 15, 2005 by
and
between the Registrant and Wells Fargo Bank, N.A. and other financial
institutions
|
|
10.7*
|
Amended
and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the
Registrant’s Registration Statement on Form S-8 filed on August 20, 2002,
File No. 333-98379)
|
|
10.8*
|
Berry
Petroleum Company 2005 Equity Incentive Plan (filed as Exhibit
4.2 to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)
|
|
10.9*
|
Form
of the Stock Option Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 4.3 to
the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)
|
|
10.10*
|
Form
of the Stock Appreciation Rights Agreement, by and between Registrant
and
selected employees, directors, and consultants (filed as Exhibit
4.4 to
the Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018)"
|
|
10.11*
|
Form
of Stock Award Agreement, by an between Registrant and selected
employees,
directors, and consultants (filed as Exhibit 99.1 on Form 8-k filed
on
December 22, 2005, File No. 1-9735)
|
|
10.12*
|
Crude
oil purchase contract, dated November 14, 2005 between Registrant
and Big
West of California, LLC (filed as Exhibit 99.2 on Form 8-k filed
on
November 22, 2005, File No. 1-9735)
|
|
10.13
|
Non-Employee
Director Deferred Stock and Compensation Plan (as amended effective
January 1, 2006)
|
|
10.14*
|
Employment
Contract dated as of June 16, 2004 by and between the Registrant
and
Robert F. Heinemann (filed as Exhibit 10.1 to the Registrant's
Quarterly
Report on Form 10-Q for the quarter ended June 30, 2004, File No.
1-9735)
|
|
10.15*
|
Salary
Continuation Agreement dated as of June 16, 2004 by and between
the
Registrant and Robert F. Heinemann (filed as Exhibit 10.2 to the
Registrant's Quarterly Report on Form 10-Q for the quarter ended
June 30,
2004, File No. 1-9735)
|
|
10.16*
|
Purchase
and sale agreement between the Registrant and J-W Operating Company
(filed
as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A
filed on
February 15, 2005, File No. 1-9735)
|
|
10.17
|
Amended
and Restated Purchase and Sale Agreement between Registrant and
Orion
Energy Partners, LP.
|
|
23.1
|
Consent
of PricewaterhouseCoopers LLP, Independent Registered Public Accounting
Firm
|
|
23.2
|
Consent
of DeGolyer and MacNaughton
|
|
31.1
|
Certification
of Chief Executive Officer pursuant to SEC Rule
13(a)-14(a)
|
|
31.2
|
Certification
of Chief Financial Officer pursuant to SEC Rule
13(a)-14(a)
|
|
32.1
|
Certification
of Chief Executive Officer pursuant to Section 1350 of Chapter
63 of Title
18 of the U.S. Code
|
|
32.2
|
Certification
of Chief Financial Officer pursuant to Section 1350 of Chapter
63 of Title
18 of the U.S. Code
|
|
99.1*
|
Form
of Indemnity Agreement of Registrant (filed as Exhibit 99.1 in
Registrant's Annual Report on Form 10-K filed on March 31, 2005,
File No.
1-9735)
|
|
99.2*
|
Form
of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to
Registrant's Registration Statement on Form S-4 filed on May 22,
1987,
File No. 33-13240)
|
|
*
Incorporated by reference
|
|
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned, thereto duly authorized on March 1, 2006.
BERRY
PETROLEUM COMPANY
|
/s/
Robert F. Heinemann
|
/s/
Ralph J. Goehring
|
/s/
Donald A. Dale
|
|
ROBERT
F. HEINEMANN
|
RALPH
J. GOEHRING
|
DONALD
A. DALE
|
|
President,
Chief Executive Officer
|
Executive
Vice President and
|
Controller
|
|
and
Director
|
Chief
Financial Officer
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in
the
capacities on the dates so indicated.
|
Name
|
Office
|
Date
|
|
|
|
|
|
/s/
Martin H. Young, Jr.
|
Chairman
of the Board,
|
March
1, 2006
|
|
Martin
H. Young, Jr.
|
Director
|
|
|
/s/
Robert F. Heinemann
|
President,
Chief Executive Officer
|
March
1, 2006
|
|
Robert
F. Heinemann
|
and
Director
|
|
|
|
|
|
|
/s/
William F. Berry
|
Director
|
March
1, 2006
|
|
William
F. Berry
|
|
|
|
|
|
|
|
/s/
Joseph H. Bryant
|
Director
|
March
1, 2006
|
|
Joseph
H. Bryant
|
|
|
|
|
|
|
|
/s/
Ralph B. Busch, III
|
Director
|
March
1, 2006
|
|
Ralph
B. Busch, III
|
|
|
|
|
|
|
|
/s/
William E. Bush, Jr.
|
Director
|
March
1, 2006
|
|
William
E. Bush, Jr.
|
|
|
|
|
|
|
|
/s/
Stephen L. Cropper
|
Director
|
March
1, 2006
|
|
Stephen
L. Cropper
|
|
|
|
|
|
|
|
/s/
J. Herbert Gaul, Jr.
|
Director
|
March
1, 2006
|
|
J.
Herbert Gaul, Jr.
|
|
|
|
|
|
|
|
/s/
Thomas J. Jamieson
|
Director
|
March
1, 2006
|
|
Thomas
J. Jamieson
|
|
|
|
/s/
J. Frank Keller
|
Director
|
March
1, 2006
|
|
J.
Frank Keller
|
|
|
|
|
|
|
71