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,
2007
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, or a smaller reporting company. See definition of “large
accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act. (Check one):
Large accelerated filerx Accelerated filero Non-accelerated filero Smaller reporting companyo
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Act). YES
o NO x
As of June 29, 2007, the aggregate market value of the
voting and non-voting common stock held by non-affiliates was $1,376,613,441. As
of February 1,
2008, the registrant had
42,585,553 shares of Class A Common Stock outstanding. The registrant also had
1,797,784 shares of Class B Stock outstanding on February 1, 2008 all of which are 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 - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
TABLE OF
CONTENTS
PART
I
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PART II
PART III
PART IV
Berry
Petroleum Company - 2007 Form 10-K
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 or forms of words such as
“will,” “might,” “intend,” “continue,” “target,” “expect,” “achieve,”
“strategy,” “future,” “may,” “could,” “goal,”, “forecast,” “anticipate,” or
other comparable words or phrases, or the negative of those words, and other
words of similar meaning, indicate forward-looking statements and important
factors which could affect actual results. 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 on page 14 in Part I, Item 1A in this Form 10-K
filed with the Securities and Exchange Commission, under the heading “Risk
Factors.”
PART
I
General. We are an independent energy company
engaged in the production, development, acquisition, exploitation of and
exploration for, crude oil and natural gas. While we were incorporated in
Delaware in 1985 and have been a publicly
traded company since 1987, we can trace our roots in California oil production back to 1909. In 2003,
we purchased and began operating properties in the Rocky Mountains. Our corporate headquarters are in
Bakersfield, California and we have a regional office in
Denver, Colorado. Information contained in this report
on Form 10-K reflects our business during the year ended December 31, 2007 unless noted
otherwise.
Our website, located at http://www.bry.com, can be used to access recent news
releases and Securities and Exchange Commission (SEC) filings, crude oil price
postings, our Annual Report, Proxy Statement, Board committee charters,
Corporate Governance
Guidelines, 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. Our objective is
to increase shareholder value through consistent growth in our production and
reserves, both through the drill bit and acquisitions. We strive to operate our
properties in an efficient manner to maximize the cash flow and earnings of our
assets. The strategies to accomplish these goals include:
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·
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Developing
our existing resource base. We intend to increase both
production and reserves annually. We are focused on the timely and prudent
development of our large resource base through developmental and step-out
drilling, down-spacing, well completions, remedial work and by application
of enhanced oil recovery (EOR) methods, as applicable. We have large crude
oil resources in place in the San Joaquin Valley basin, California, with diatomite being our
largest, and a resource play in the Uinta basin, Utah (Lake Canyon). In 2006, we invested in a
large undeveloped probable natural gas reserve position in the Piceance
basin in Colorado, and are planning to continue
significant drilling there over the next several years. We have a proven
track record of developing reserves on a competitive basis and have
increased annual production for over six
years.
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·
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Acquiring
additional assets with significant growth potential. We will continue to evaluate oil
and gas properties with proved reserves, probable reserves and/or sizeable
acreage positions that we believe contain substantial hydrocarbons which
can be developed at reasonable costs. In the last three years we have
completed over $400 million of gas-oriented acquisitions in Colorado, establishing two core areas
(the DJ and Piceance basins) of growth for us. We will continue to review
asset acquisitions that meet our economic criteria with a primary focus on
large repeatable development potential in the United States and concentrating on
opportunities where we have strong technical expertise. Additionally, we
seek to increase our net revenue interest in assets that we already
operate.
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·
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Utilizing
joint ventures with respected partners to enter new basins. We believe that early entry into
some basins offers the best potential for establishing low cost acreage
positions in those basins. In areas where we do not have existing
operations, we may seek to utilize the skills and knowledge of other
industry participants upon entering these new basins so that we can reduce
our risk and improve our ultimate success in the
area.
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·
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Accumulating
significant acreage positions near our producing operations. We are interested in adding
acreage positions near our existing producing operations to leverage our
operating and technical expertise within the area and to build on
established core operations. We believe this strategy can add
value by utilizing our operational knowledge in a given area and by
expanding our operations
efficiently.
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·
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Investing
our capital in a disciplined manner and maintaining a strong financial
position. The oil
and gas business is capital intensive. Therefore we focus on utilizing our
available capital on projects where we are likely to have success in
increasing production and/or reserves at attractive returns. We believe
that maintaining a strong financial position allows us to capitalize on
investment opportunities and to be better prepared for a lower commodity
price environment. We expect to continue to hedge oil and gas prices and
to utilize long-term sales contracts with the objective of achieving the
cash flow necessary for the development of our
assets.
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Berry
Petroleum Company - 2007 Form 10-K
Business
strengths.
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High
quality asset portfolio with a long reserve life. Over the last
several years we have diversified our asset base through acquisitions and
now have approximately 40% of our production and proved reserves in the
Rocky Mountain region with the balance in California. Our proved
reserves consist of 69% crude oil and 31% natural gas. Our legacy
California assets provides us with a steady stream of cash flow to
re-invest into our significant drilling inventory and the appraisal of our
prospects. Our wells are generally characterized by long production lives
and predictable performance. At December 31, 2007 our implied reserve
life was 16.5 years and our implied proved developed reserve life was
10.1 years.
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Track
record of efficient proved reserve and production growth. For the three years ended
December 31,
2007, our average
annual reserve replacement rate was 316% at an average cost of $12.23 per
barrel of oil equivalent (BOE). See Item 7 Management’s Discussion and
Analysis of Financial Condition and Results of Operation for further
explanation of the reserve replacement rate. During the same period our
proved reserves and production increased at an annualized compounded rate
of 15% and 9%, respectively. We were able to deliver that growth
predominantly through low-risk drilling. In 2007, we achieved an average
gross drilling success rate of 98%. We believe we can continue to deliver
strong growth through the drill bit by exploiting our large undeveloped
leasehold position. We also plan to complement this drill bit growth
through selective and focused
acquisitions.
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Experienced
management and operational teams. We operate our assets through
six integrated teams organized around our six core areas of operations.
These teams have clear objectives in production, reserves, finding and
development costs, operating costs and are charged with value enhancement.
In the last several years we have expanded and deepened our core team of
technical staff and operating managers, who have broad industry
experience, including experience in California heavy oil thermal recovery
operations and Rocky Mountain tight gas sands development and completion.
We continue to utilize technologies and steam practices that we believe
will allow us to improve the ultimate recoveries of crude oil on our
mature California properties. We also utilize 3-D
seismic technology for evaluation of sub-surface geologic trends of our
many prospects.
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Operational
control and financial flexibility. We exercise operating control
over approximately 98% of our proved reserve base. We generally prefer to
retain operating control over our properties, allowing us to control
operating costs more effectively, the timing of development activities and
technological enhancements, the marketing of production and the allocation
of our capital budget. In addition, the timing of most of our capital
expenditures is discretionary, which allows us a significant degree of
flexibility to adjust the size and timing of our capital budget. We
finance our drilling budget primarily through our internally generated
operating cash flows and we also have a $750 million senior unsecured
revolving credit facility with a current borrowing base of
$550 million.
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Established
risk management policies. We actively manage our exposure
to commodity price fluctuations by hedging a portion of our forecasted
production. We use hedges to assist us in mitigating the effects of price
declines and to secure operating cash flows in order to fund our capital
expenditures program. Our long-term crude oil contracts with refiners and
our long-term firm natural gas pipeline transportation agreements assist
us in mitigating price differential volatility and in assuring product
delivery to markets. Currently, the operation of our cogeneration
facilities in California provides a partial hedge against
increases in natural gas prices (which translates into higher steam costs)
because of the high correlation between electricity and natural gas prices
under our existing electricity sales
contracts.
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Proved
Reserves and Revenues. As
of December 31,
2007, our estimated proved
reserves were 169 million BOE, of which 60% are heavy crude oil, 9% light crude
oil and 31% natural gas. We have a geographically diverse asset base with 60% of
our reserves located in California, and 40% in the Rocky Mountains. Of our proved reserves 61% were
proved developed, while proved undeveloped reserves make up 39% of our proved
total. The projected future capital to develop these proved undeveloped reserves
is $677 million at an estimated cost of approximately $10.21 per BOE.
Approximately 62% of the capital to develop these reserves is expected to be
expended in the next five years. Production in 2007 was 9.8 million BOE, up 6%
from production of 9.3 million BOE in 2006.
Our properties generally have long
reserve lives and reasonably stable and predictable well production
characteristics with a ratio of proved reserves to production (based on the year
ended December 31,
2007) of approximately
16.5 years as compared to 15.3 years at year end 2006.
Berry
Petroleum Company - 2007 Form 10-K
We have organized our operations into
six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset
including diatomite (N. Midway), Southern California including Poso Creek and
Placerita (S. Cal), Piceance, Uinta and DJ. The following table sets forth the
estimated quantities of proved reserves and production attributable to our asset
teams as of December 31,
2007. We operate 98% of
these assets:
State
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Name
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Type
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Average Daily Production
(BOE/D)
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% of Daily
Production
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Proved Reserves (BOE) in
millions
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% of Proved
Reserves
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Oil & Gas Revenues before
hedging (in millions)
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% of Oil & Gas Revenues
before hedging
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9,616 |
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36 |
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52.4 |
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31 |
% |
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$ |
189.0 |
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39 |
% |
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5,743 |
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21 |
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23.4 |
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14 |
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91.6 |
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19 |
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4,265 |
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16 |
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26.3 |
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16 |
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101.8 |
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21 |
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3,123 |
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12 |
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21.1 |
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12 |
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34.2 |
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7 |
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2,068 |
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8 |
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22.8 |
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13 |
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50.4 |
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10 |
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1,715 |
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6 |
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23.1 |
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14 |
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16.4 |
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3 |
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372 |
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1 |
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.1 |
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- |
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5.8 |
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1 |
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26,902 |
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100 |
% |
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169.2 |
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100 |
% |
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$ |
489.2 |
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100 |
% |
(1) Primarily
relates to properties sold during
2007.
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We continue to engage DeGolyer and
MacNaughton (D&M) to appraise the extent and value of our proved oil and gas
reserves and the future net revenues to be derived from our properties for the
year ended December 31,
2007. 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 our reserves. 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,
2007. See Supplemental
Information About Oil & Gas Producing Activities (Unaudited) for our oil and
gas reserve disclosures.
Acquisitions.
See Item 7 Management’s
Discussion and Analysis of Financial Condition and Results of Operation.
Operations. In California, we operate all of our principal oil
and gas producing properties. The S. Midway, N. Midway and S. Cal assets contain predominantly heavy
crude oil which requires heat, supplied in the form of steam, which is injected
into the oil producing formations to reduce the oil viscosity, thereby allowing
the oil to flow to the wellbore for production. We utilize cyclic steam and/or
steam flood recovery methods on all assets. 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 Mountains, crude oil produced from the Uinta properties is transported by
truck. Natural gas produced from the Uinta, DJ and Piceance basin properties is
transported to one of several main pipelines. We have seven firm transportation
contracts on four different pipelines to provide transport for our Rocky
Mountain natural gas production. See table on page 7.
Economy.
Global and California crude oil demand continues to remain
strong although pricing is volatile. Product prices continued to exhibit an
overall-strengthening trend through December 2007. Oil is a globally priced
commodity and is priced according to the supply and demand of crude oil and its
products. The weakness of the U.S. dollar in 2007 has contributed to a rise in
the price of crude oil denominated in U.S. dollars. This price action is a
contributor to the volatility of the commodity. Other dominant factors in the
pricing of our crude oil include the condition of the global economy and
political tension in or near oil producing regions. The range of West Texas
Intermediate (WTI) crude prices for 2007, based upon NYMEX settlements, was a
low of $50.48 and a high of $98.18. We expect that crude prices will continue to
be volatile in 2008.
Berry
Petroleum Company - 2007 Form 10-K
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2007
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2006
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2005
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Average NYMEX settlement price
for WTI
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$ |
72.41 |
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$ |
66.25 |
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$ |
56.70 |
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Average posted price for
Berry’s:
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Utah 40 degree black wax (light)
crude oil
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59.28 |
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56.34 |
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53.03 |
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California 13 degree API heavy crude oil
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61.64 |
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54.38 |
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44.36 |
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Average crude price differential
between WTI and Berry’s:
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Utah light 40 degree black wax
(light) crude oil
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13.13 |
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9.91 |
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3.67 |
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California 13 degree API heavy crude
oil
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10.77 |
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11.87 |
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12.34 |
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The above posting prices and
differentials are not necessarily amounts paid or received by us due to the
contracts discussed below. The crude oil price differential between WTI and
California’s heavy crude has remained relatively
stable in 2007 and 2006. On December 31, 2007 the differential was $12.44 and ranged
from a low of $9.11 to a high of $12.47 per barrel during the year. Crude oil
price differentials between WTI and Utah’s 40 degree black wax (light) crude
oil were fairly consistent during 2007. On December 31, 2007 the differential was $14.50 and ranged
from a low of $12.41 to a high of $14.50 per barrel during the year.
Oil
Contracts. We market our
crude oil production to competing buyers which may be an independent or a major
oil refining company.
California - We have the ability to deliver
significant volumes of crude oil over a multi-year period. On November 21, 2005, we entered into a new crude oil sales
contract with an independent refiner for substantially all of our California production for deliveries beginning
February 1,
2006 and ending
January 31,
2010. After the initial
term of the contract, we have a one-year renewal at our option. 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 $8.10, or 2) heavy oil field postings plus a premium
of approximately $1.35. The agreement effectively eliminates our exposure to the
risk of a widening WTI to California heavy crude price differential over
the four year contract term and allows us to effectively hedge our production
based on WTI pricing. This contract allowed us to improve our California revenues by $15 million and $21
million over the posted price in 2007 and 2006,
respectively.
Prior to
November 2005, we secured a three-year sales agreement, beginning in late 2002,
with a major oil company whereby we sold over 90% of our 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.
Utah - During 2007, our Utah light crude oil was sold under
multiple contracts with different purchasers for varying pricing terms, and in
some cases our realized price was further reduced by transportation charges. As
operator we deliver all produced volumes pursuant to these contracts, although
our working interest partners or royalty owners may take their respective
volumes in kind and market their own volumes. We experienced increasing
difficulty in locating additional buyers of our crude oil production from this
region in the latter part of 2006. Our Utah crude oil is a paraffinic crude and
can be processed efficiently by only a limited number of refineries. Increased
production of crude oil in the region, the ability of refiners to process other
higher sulfur crudes as a result of capital upgrades, as well as the increasing
availability of Canadian crude oil, put downward pressure on the sales price of
our crude oil.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract with
a refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery
expansion in Salt Lake City, which is expected in the first half of 2008, the
refiner will increase its total purchased volumes to 5,000 Bbl/D through June
30, 2013. Pricing under the contract, which includes transportation and gravity
adjustments, is at a fixed percentage of WTI, which was near the posted price at
the contract’s starting date. As global and regional prices of crude oil have
risen in 2007, we are receiving crude oil prices below the posted price,
although this posted price is thinly traded and does not necessarily indicate
the actual price at which a seller can market their crude oil. While our price
differentials have widened as the crude oil price increased, we are able to sell
100% of our crude oil to a refiner and avoid any field shut down due to the
inability of placing the crude. The margins on our Uinta crude allow us to
reinvest in drilling the field and to retain and increase the overall value of
the field. As of January 1, 2008 this contract is our only sales contract
for our Uinta oil.
From October 1, 2003 through April 30, 2006 we were able to sell our Utah crude oil at approximately $2.00 per
barrel below WTI, and from May 1, 2006 through September 30, 2006, we were selling the majority of our
Utah crude at approximately $9.00 per
barrel below WTI. Due to this lower pricing, and based on sales of 3,500 Bbl/D,
our revenues were lower by approximately $9.2 million in 2006 as compared
to 2005.
Berry
Petroleum Company - 2007 Form 10-K
Natural
Gas Marketing. We market
our produced natural gas from Colorado and Utah. Generally, natural gas is sold
at monthly index related prices plus an adjustment for transportation. Certain
volumes are sold at a daily spot related price. Approximately two-thirds of the pricing
of our natural gas is tied to the Panhandle Eastern Pipeline
(PEPL) index and the remaining volume to the
Colorado Interstate Gas
(CIG) Index; both indices are lower than
NYMEX Henry Hub prices.
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2007
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2006
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2005
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Annual average closing price per
MMBtu for:
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NYMEX
Henry Hub (HH) prompt month natural gas contract last
day
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$ |
6.86 |
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$ |
7.23 |
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$ |
8.62 |
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Rocky Mountain Questar
first-of-month indices (Uinta sales)
|
|
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3.69 |
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|
5.36 |
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6.73 |
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Rocky Mountain CIG first-of-month indices (DJ and
Piceance sales)
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|
3.97 |
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|
5.63 |
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6.95 |
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Mid-Continent
PEPL first-of-month indices (CO, KS, UT & WY
sales)
|
|
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5.99 |
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6.02 |
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7.29 |
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Average natural gas price per
MMBtu differential between NYMEX HH and:
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3.17 |
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1.87 |
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1.89 |
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2.89 |
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1.60 |
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1.67 |
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|
.87 |
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1.21 |
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1.33 |
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Gas Basis
Differential. Natural gas prices in the Rockies continue to be volatile
due to various factors, including takeaway pipeline capacity, supply volumes,
and regional demand issues. The basis differential between HH and CIG has
narrowed, as anticipated, upon the startup of the Rockies Express pipeline in
early 2008. We have contracted a total of 35,000 MMBtu/D on this pipeline under
two separate transactions to provide firm transport for our Piceance basin gas
production. The CIG basis differential per MMBtu, based upon first-of-month
values, averaged $2.89 below HH and ranged from $.51 to $5.31 below HH in 2007.
Although related to CIG, the actual basin price varies. Gas from the Piceance
basin traded slightly below the CIG price while Uinta basin gas sold for
approximately $.40 below CIG pricing. DJ Basin gas is priced using one of two
indices. Approximately two-thirds of our volumes from our DJ natural gas
properties is tied to the PEPL index for pricing and the remaining volumes to
CIG pricing. For that portion of the production with firm transportation on
either the Cheyenne Plains Pipeline or the KMIGT pipeline, pricing is based upon
the PEPL index which averaged approximately $.87 below the HH index before the
cost of transportation is considered. The remainder of the DJ Basin gas is sold
slightly above the CIG index price.
We have physical access to interstate
gas pipelines to move gas to or from market. To assure delivery of gas, we have
entered into long-term gas transportation contracts as follows:
Firm
Transportation Summary.
Name
|
From
|
To
|
Quantity (Avg.
MMBtu/D)
|
|
Term
|
|
December 31, 2007 base cost per
MMBtu
|
|
|
Remaining contractual obligation
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cheyenne
Plains Gas Pipeline
|
|
|
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Base cost
per MMBtu is a weighted average
cost.
|
(2)
Quantity varies by year, but averages 11,000 per day over the ten year
term.
|
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.
Berry
Petroleum Company - 2007 Form 10-K
Cogeneration
Steam Supply. As of December 31, 2007, approximately 60% of our proved
reserves, or 101.6 million barrels, consisted of heavy crude oil produced from
depths of less than 2,000 feet. In pursuing our goal of being a cost-efficient
heavy oil producer in California, we have consistently focused on minimizing our
steam cost. We believe one of the main methods to keep steam costs low is
through the ownership and efficient operation of three cogeneration facilities
located on our properties. Two of these cogeneration facilities, a 38 megawatt
(MW) and an 18 MW facility, are located in S. Midway. We also own a 42 MW
cogeneration facility which is located in the Placerita field. Cogeneration,
also called combined heat and power (CHP), extracts energy from the exhaust of a
turbine that would otherwise be wasted, to produce steam. This increases the
efficiency of the combined process and consumes less fuel than would be required
to produce the steam and electricity separately. The reduction in fuel use also
results in a corresponding reduction of greenhouse gas (GHG)
emissions.
Conventional
Steam Generation. In
addition to these cogeneration plants, we own 23 fully permitted conventional
boilers. The quantity of boilers operated at any point in time is dependent on
1) the steam volume required for us to achieve our targeted production and 2)
the price of natural gas compared to the realized price of crude oil sold.
Total barrels of steam per day (BSPD)
capacity as of December
31, 2007 is as
follows:
|
|
|
|
|
Steam
generation capacity of conventional boilers
|
|
|
|
|
Steam generation capacity of
cogeneration plants
|
|
|
|
|
Additional steam purchased under
contract with a third party
|
|
|
|
|
|
|
|
|
|
The average volume of steam injected
for the years ended December 31, 2007 and 2006 was 87,990 and 81,246 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. Our steam supply and flexibility are crucial for the
maximization of California thermally enhanced heavy oil
production, cost control and ultimate reserve oil recovery.
In 2007,
we have added additional steam capacity for our development projects at N.
Midway, primarily diatomite, and Poso Creek to achieve maximum production from
these properties. In 2008, we plan to add one additional 5,000 BSPD generator at
Poso Creek and three additional 5,000 BSPD generators on our diatomite producing
properties.
We operated most of our conventional
steam generators in 2007 to achieve our goal of increasing heavy oil production.
Approximately 62% of the volume of natural gas purchased to generate steam and
electricity is based upon SoCal Border indices. We pay
distribution/transportation charges for the delivery of gas to our various
locations where we consume gas for steam generation purposes. However, in some
cases this transportation cost is embedded in the price of gas. Approximately
26% of supply volume is purchased in Wyoming and moved to the Midway-Sunset field
using our firm transportation capacity on the Kern River Pipeline. This gas is
purchased based upon the Rocky Mountain Northwest Pipeline (NWPL) index. The
remaining 12% of supply volume is purchased based upon the PG&E Citygate
index and used in our Poso Creek steaming operations.
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Average SoCal Border Monthly
Index Price per MMBtu
|
|
$ |
6.38 |
|
|
$ |
6.29 |
|
|
$ |
7.37 |
|
Average Rocky Mountain NWPL
Monthly Index Price per MMBtu
|
|
|
3.95 |
|
|
|
5.66 |
|
|
|
6.96 |
|
Average PG&E Citygate Monthly Index Price per MMBtu
|
|
|
6.86 |
|
|
|
6.70 |
|
|
|
7.72 |
|
Berry
Petroleum Company - 2007 Form 10-K
We historically have been a net
purchaser of natural gas, and thus our net income was negatively impacted when
natural gas prices rose higher than its oil equivalent. In 2005, on a gas
balance basis, we achieved parity due to our eastern Colorado (DJ) gas
acquisition. Subsequent to 2005, we have been a net seller of gas and will
benefit operationally when gas prices are higher. We are a net seller of gas
with a balance between natural gas consumed and produced. The following table
shows our average 2007 and estimated average 2008 amount of production in excess
of consumption and hedged volumes (in average MMBtu/D):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,500 |
|
|
|
18,500 |
|
|
|
|
15,000 |
|
|
|
15,000 |
|
|
|
|
11,000 |
|
|
|
21,000 |
|
Total natural gas volumes
produced in operations
|
|
|
44,500 |
|
|
|
54,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,000 |
|
|
|
27,000 |
|
|
|
|
18,000 |
|
|
|
24,000 |
|
Total natural gas volumes
consumed in
operations
|
|
|
45,000 |
|
|
|
51,000 |
|
Less: Our estimate of approximate
natural gas volumes consumed to produce electricity
(2)
|
|
|
(24,000
|
) |
|
|
(21,000 |
) |
Total approximate natural gas
volumes consumed to produce steam
|
|
|
21,000 |
|
|
|
30,000 |
|
|
|
|
|
|
|
|
|
|
Natural
gas volumes hedged
|
|
|
15,000 |
|
|
|
18,000 |
|
|
|
|
|
|
|
|
|
|
Amount
of natural gas volumes produced in excess of volumes consumed to produce
steam and volumes hedged
|
|
|
8,500 |
|
|
|
6,500 |
|
(1) In 2008,
we will have additional conventional capacity at Poso Creek and diatomite
to increase our production from these
fields.
|
(2) We
estimate this volume based on electricity revenues divided by the gas
purchase price, including transportation, per MMBtu for the respective
period.
|
Generation.
The total annual average
electrical generation of our three cogeneration facilities is approximately 93
MW, of which we consume approximately 9 MW for use in our operations. Each
facility is centrally located on certain of our oil producing properties. Thus
the steam generated by the facility is capable of being delivered to numerous
wells that require steam for the EOR process. Our investment in our cogeneration
facilities has been for the express purpose of lowering the steam costs in our
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 our cogeneration plants, the price of natural
gas used for fuel in generating electricity and steam, and the terms of our
power contracts. Although we account for cogeneration costs as described above,
economically we view any profit or loss from the generation of electricity as a
decrease or increase, respectively, to our total cost of producing heavy oil in
California. DD&A related to our cogeneration facilities is allocated between
electricity operations and oil and gas operations using a similar allocation
method.
Sales Contracts.
Historically, we have sold electricity produced by our cogeneration
facilities, each of which is a Qualifying Facility (QF) under the Public
Utilities Regulatory Policy Act of 1978, as amended (PURPA), to two California
public utilities; Southern California Edison Company (Edison) and PG&E,
under long-term contracts approved by the California Public Utilities Commission
(CPUC). These contracts are referred to as standard offer (SO) contracts under
which we are paid an energy payment that reflects the utility’s Short Run
Avoided Cost (SRAC) of energy plus a capacity payment that reflects a recovery
of capital expenditures that would otherwise have been made by the utility.
During most periods natural gas is the marginal fuel for California utilities,
so this formula provides a hedge against our cost of gas to produce electricity
and steam in our cogeneration facilities. On September 20, 2007, the CPUC issued
a decision (SRAC Decision) that changes prospectively the way SRAC energy prices
will be determined for existing and new SO contracts and revises the capacity
prices paid under current SO1 contracts. The decision also requires California
utilities to offer new contracts for energy and as-available capacity (similar
to an SO1) and new contracts for energy and firm capacity (similar to an SO2)
for a term of up to ten years. The new pricing methodology provides for a
gradual transition of SRAC energy prices to market prices for electricity. Based
on our preliminary analysis, we do not believe that the proposed pricing changes
will materially affect us in 2008.
Berry
Petroleum Company - 2007 Form 10-K
In
December 2004, we executed a five-year SO1 contract with Edison for the
Placerita Unit 2 facility, and five-year SO1 contracts with PG&E for the
Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant to
these contracts, we are 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
SO1 contracts, and similar one-year SO1 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 adjust the prices retroactively to the
extent it was later determined that such prices did not comply with the
requirements of PURPA. To date, the CPUC has taken no final action based on this
court ruling. We
are currently analyzing whether to exercise our right under the SRAC Decision to
replace each of these three SO1 contracts prior to its scheduled termination
with one of the new SO contracts ordered by the SRAC Decision.
Based on the current pricing mechanism
for our electricity under the contracts, we expect that our electricity revenues
will be in the $50 million to $60 million range for 2008.
During
the California energy crisis in 2000 and 2001, we had two Power Purchase
Agreements with Edison and two with PG&E. Under these contracts,
we were paid under an SRAC formula which included pricing gas off of the
Southern California Border Spot Average. In various CPUC and court documents,
this price point is often referred to as Topock. The Topock compressor site is
located just inside the California border at Needles, California. On March 27,
2001, the CPUC issued a decision making certain changes in the
then SRAC formula, the most significant of which was changing the pricing
point from the Southern California Border to Malin (in northern California),
which resulted in a significant reduction in the price we were to be paid by
Edison and PG&E. The extreme disruption that this caused in the cogeneration
industry caused Edison to enter into settlement agreements with us and other
similarly situated gas fired QFs by which Edison nevertheless agreed to pay
using the Southern California Border pricing point from March 27th forward. The
CPUC approved the settlements. In various ongoing proceedings, the utilities
argued the revised SRAC formula should be retroactively applied to the period
from December 2000 to March 27, 2001. The CPUC has indicated in the past it did
not believe retroactive adjustment should be made. On February 7, 2008, the
CPUC Administrative Law Judge (ALJ) issued an order indicating that the ALJ
intended to deal with a pending remand on this issue and ordered the utilities
to report the number and identity of QF's still subject to this
unresolved issue. We expect we may be one of those QF's. The ALJ also
invited interested parties to propose solutions to the pending remand
dispute. We intend to vigorously oppose any retroactive application of the
March 27, 2001 decision and believe that any resolution of such dispute should
be immaterial to us.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
- |
|
|
|
6,500 |
|
|
|
|
|
|
|
16 |
|
|
|
4 |
|
|
|
6,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
4 |
|
|
|
6,700 |
|
|
|
|
|
|
|
37 |
|
|
|
- |
|
|
|
18,000 |
|
Competition. The oil and gas industry is highly
competitive. As an independent producer we have little control over the price we
receive for our crude oil and natural gas. As such, higher costs, fees and taxes
assessed at the producer level cannot necessarily be passed on to our customers.
In acquisition activities, competition is intense 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 we have, we believe we are in a
position to compete effectively due to our business strengths (identified on
page 4).
Employees. On December 31, 2007, we had 263 full-time employees, up
from 243 full-time employees on December 31, 2006.
Berry
Petroleum Company - 2007 Form 10-K
The following is a summary of the
developmental capital expenditures incurred during 2007 and 2006 and budgeted
capital expenditures for 2008 (in thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Budgeted)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
27,948 |
|
|
$ |
13,174 |
|
|
$ |
15,904 |
|
|
|
|
|
2,872 |
|
|
|
7,576 |
|
|
|
7,572 |
|
|
Facilities - cogeneration
|
|
|
- |
|
|
|
- |
|
|
|
415 |
|
|
|
|
|
- |
|
|
|
150 |
|
|
|
411 |
|
|
|
|
|
30,820 |
|
|
|
20,900 |
|
|
|
24,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,143 |
|
|
|
12,949 |
|
|
|
28,707 |
|
|
|
|
|
23,530 |
|
|
|
17,125 |
|
|
|
12,884 |
|
|
|
|
|
200 |
|
|
|
634 |
|
|
|
67 |
|
|
|
|
|
66,873 |
|
|
|
30,708 |
|
|
|
41,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,615 |
|
|
|
16,627 |
|
|
|
9,493 |
|
|
|
|
|
7,328 |
|
|
|
17,549 |
|
|
|
6,234 |
|
|
Facilities - cogeneration
|
|
|
2,850 |
|
|
|
604 |
|
|
|
177 |
|
|
|
|
|
850 |
|
|
|
483 |
|
|
|
- |
|
|
|
|
|
20,643 |
|
|
|
35,263 |
|
|
|
15,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,060 |
|
|
|
52,700 |
|
|
|
104,397 |
|
|
|
|
|
1,326 |
|
|
|
3,151 |
|
|
|
5,966 |
|
|
|
|
|
1,450 |
|
|
|
602 |
|
|
|
1,072 |
|
|
|
|
|
50,836 |
|
|
|
56,453 |
|
|
|
111,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93,900 |
|
|
|
103,921 |
|
|
|
36,654 |
|
|
|
|
|
16,776 |
|
|
|
15,298 |
|
|
|
3,486 |
|
|
|
|
|
- |
|
|
|
164 |
|
|
|
75 |
|
|
|
|
|
110,676 |
|
|
|
119,383 |
|
|
|
40,215 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,826 |
|
|
|
14,017 |
|
|
|
20,979 |
|
|
|
|
|
3,497 |
|
|
|
2,736 |
|
|
|
7,883 |
|
|
|
|
|
1,691 |
|
|
|
1,519 |
|
|
|
427 |
|
|
|
|
|
13,014 |
|
|
|
18,272 |
|
|
|
29,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,750 |
|
|
|
4,288 |
|
|
|
23,614 |
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
294,612 |
|
|
$ |
285,267 |
|
|
$ |
286,416 |
|
|
(1) Budgeted
capital expenditures may be adjusted for numerous reasons including, but
not limited to, oil and natural gas price levels and equipment
availability, working capital needs, permit and regulatory issues.
See Item
7 Management's Discussion and Analysis of Financial Condition and Results
of Operation.
|
(2)
Other Fixed Assets in 2006 were primarily made up of two drilling rig
purchases.
Berry
Petroleum Company - 2007 Form 10-K
Production. The following table sets forth certain
information regarding production for the years ended December 31, as
indicated:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Net annual production:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
7,210 |
|
|
|
7,182 |
|
|
|
7,081 |
|
|
|
|
15,657 |
|
|
|
12,526 |
|
|
|
7,919 |
|
Total equivalent barrels (MBOE)
(2)
|
|
|
9,819 |
|
|
|
9,270 |
|
|
|
8,401 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) before
hedging
|
|
$ |
57.85 |
|
|
$ |
52.92 |
|
|
$ |
47.04 |
|
Oil (per Bbl) after
hedging
|
|
|
53.24 |
|
|
|
50.55 |
|
|
|
40.83 |
|
Gas (per Mcf) before
hedging
|
|
|
4.53 |
|
|
|
5.48 |
|
|
|
7.88 |
|
Gas (per Mcf) after
hedging
|
|
|
5.27 |
|
|
|
5.57 |
|
|
|
7.73 |
|
|
|
|
49.72 |
|
|
|
48.38 |
|
|
|
47.01 |
|
|
|
|
47.50 |
|
|
|
46.67 |
|
|
|
41.62 |
|
Average operating cost - oil and
gas production (per BOE)
|
|
|
14.38 |
|
|
|
12.69 |
|
|
|
11.79 |
|
Mbbl - Thousands of
barrels
Mcf - Thousand cubic
feet
MMcf - Million cubic
feet
BOE - Barrels of oil
equivalent
MBOE - Thousand barrels of oil
equivalent
(1) Net production
represents that owned by us and produced to our 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, 2007, our properties accounted for the
following developed and undeveloped acres:
|
|
|
Developed
Acres
|
|
|
Undeveloped
Acres
|
|
|
Total
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1) Includes
1,600 gross developed and 42,983 gross undeveloped acres at Lake Canyon. We have an
interest in 75% of the shallow rights and 25% of the deep rights, which is
reduced when the Tribe
participates.
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(2) Does not
include 125,000 gross (70,000 net) acres and 125,000 gross (23,000 net)
acres at Lake Canyon (shallow) and Lake Canyon (deep), respectively, which
we can earn upon fulfilling specific drilling obligations over a four year
contract period beginning in 2006.
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Gross acres represent acres in which we
have a working interest; net acres represent our aggregate working interests in
the gross acres.
As of December 31, 2007, we have 3,872 gross productive
wells (3,183 net). Gross wells represent the total number of wells in which we
have a working interest. Net wells represent the number of gross wells
multiplied by the percentages of the working interests owned by us. 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.
Berry
Petroleum Company - 2007 Form 10-K
Drilling
Activity. The following table sets forth certain
information regarding our drilling activities for the periods
indicated:
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2007
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2006
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2005
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Exploratory wells drilled
(1):
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Development wells
drilled:
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(1) 2005 does not
include one gross well drilled by our industry partner that was being evaluated
at December 31,
2005.
(2) 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.
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2007
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Gross
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Net
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Total productive wells
drilled:
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Dry
hole, abandonment and impairment. See Item 7 Management’s Discussion and
Analysis of Financial Condition and Results of Operation.
Company
Owned Drilling Rigs.
During 2005 and 2006, we purchased three drilling rigs, all of which are
operational. Owning these rigs has allowed us to successfully meet a portion of
our drilling needs in the Uinta and Piceance basins. As the rig market and our
rig requirements change, we evaluate the necessity to continue to own these rigs
and may dispose of one or all of such rigs over time. See Note 10 to the
financial statements.
Other.
At year end, we had two
subsidiaries accounted for under the equity method (see Note 1 to the financial
statements). We had no special purpose entities and no off-balance sheet debt.
See discussion of our related party transaction at Note 17 to the financial
statements.
Environmental and Other Regulations. We are committed to responsible
management of the environment and prudent health and safety policies, as these
areas relate to our operations. We strive to achieve the long-term goal of
sustainable development within the framework of sound environmental, health and
safety practices and standards. We strive to make environmental, health and
safety protection an integral part of all business activities, from the
acquisition and management of our resources to the decommissioning and
reclamation of our wells and facilities.
We have 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 our 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 our
operating costs. 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. We maintain insurance coverage that we
believe is customary in the industry although we are not fully insured against
all environmental or other risks.
Environmental
regulation. Our oil and
gas exploration, production and related operations are subject to numerous and
frequently changing federal, state, tribal and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Environmental laws and regulations may require the
acquisition of certain permits prior to or in connection with drilling
activities or other operations, restrict or prohibit the types, quantities and
concentration of substances that can be released into the environment including
releases in connection with drilling and production, restrict or prohibit
drilling activities or other operations that could impact wetlands, endangered
or threatened species or other protected areas or natural resources, require
remedial action to mitigate pollution from ongoing or former operations, such as
cleanup of environmental contamination, pit cleanups and plugging of abandoned
wells, and impose substantial liabilities for pollution resulting from our
operations. See Item 1A Risk Factors—"We are subject to complex federal, state,
regional, local and other laws and regulations that could give rise to
substantial liabilities from environmental contamination or otherwise adversely
affect our cost, manner or feasibility of doing
business."
Berry
Petroleum Company - 2007 Form 10-K
Regulation
of oil and gas. The oil
and gas industry, including our operations, is extensively regulated by numerous
federal, state and local authorities, and with respect to tribal lands, Native
American tribes.
These types of regulations include
requiring permits for the drilling of wells, the posting of drilling bonds and
the 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 the notifying of surface
owners and other third parties. Certain laws and regulations may limit the
amount of oil and natural gas we can produce from our wells or limit the number
of wells or the locations at which we can drill. We are also subject to various
laws and regulations pertaining to Native American tribal surface ownership, to
Native American oil and gas leases and other exploration agreements, fees,
taxes, or 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 Regulatory Commission (FERC) provided incentives for the
development of cogeneration facilities such as ours. A domestic electricity
generating project must be a QF under FERC regulations in order to benefit from
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 FERC determines that a competitive wholesale
electricity market is available to QFs in the service territory. Such a
determination has not been made for our service areas in California. This amendment does not affect any of
our current SO contracts. FERC issued an order on October 20, 2006 implementing this amendment to PURPA
and on December 20,
2006 issued a subsequent
order granting limited rehearing of the October 20, 2006 order. FERC regulations also permit
QFs and utilities to negotiate agreements for utility purchases of power at
rates lower than the utilities' avoided costs.
State
energy regulation. The
CPUC has broad authority to regulate both the rates charged by, and the
financial activities of, electric utilities operating in California 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 we, 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 we are not
subject to regulation by the CPUC, the CPUC's implementation of PURPA is
important to us.
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, results of operations
and financial condition. 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, working capital and payments on our debt and our ability to borrow
and raise additional capital. The amount we can borrow under our senior
unsecured revolving credit facility (see Note 6 to the financial statements) 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. The oil and
natural gas markets fluctuate widely, and we cannot predict future oil and
natural gas prices. Oil prices have recently been at historically high levels
and natural gas prices have been at high levels over the past several years when
compared to prior periods. Prices for oil and natural gas may fluctuate widely
in response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control, such as:
·
|
regional,
domestic and foreign supply and perceptions of supply of and demand for
oil and natural gas;
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·
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level
of consumer demand;
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·
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overall
domestic and global political and economic conditions, including those in
the Middle East and South America;
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·
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actions
of the Organization of Petroleum Exporting Countries and other
state-controlled oil companies relating to oil price and production
controls;
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·
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the
impact of increasing liquefied natural gas, or LNG, deliveries to the
United States;
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Berry
Petroleum Company - 2007 Form 10-K
·
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technological
advances affecting energy consumption and
supply;
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·
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domestic
and foreign governmental regulations and
taxation;
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·
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the
impact of energy conservation
efforts;
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·
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the
capacity, cost and availability of oil and natural gas pipelines and other
transportation facilities, and the proximity of these facilities to our
wells; and
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·
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the
price and availability of alternative
fuels.
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Our revenue, profitability and cash flow depend upon the prices and demand for
oil and natural gas, and a drop in prices can significantly affect our financial
results and impede our growth. In particular, declines in commodity prices
will:
·
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reduce
the amount of cash flow available to make capital expenditures or make
acquisitions;
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·
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reduce
the number of our drilling
locations;
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·
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negatively
impact the value of our reserves, because declines in oil and natural gas
prices would reduce the amount of oil and natural gas that we can produce
economically; and
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·
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limit
our ability to borrow money or raise additional
capital.
|
We have multiple hedges placed on our
oil and gas production. See Item 7A Quantitative and Qualitative Disclosures
About Market Risk.
Our
heavy crude in California may
be
less economic than lighter crude oil and natural gas. As of December 31, 2007, approximately 60% of our proved reserves, or
101.6 million barrels, consisted of
heavy oil. Light crude oil represented 9% and natural gas represented
31% of our oil and gas reserves. Heavy
crude oil sells for a discount to light crude oil, as more complex refining
equipment is required to convert heavy oil into high value products. We
currently sell our heavy crude oil in California under a long-term contract for
approximately $8.10 below WTI, the U.S. benchmark crude oil pricing.
Regional pricing can
influence commodity prices. Additionally, most of our crude oil in
California is produced using the enhanced oil
recovery process of steam injection. This process is more costly than primary
and secondary recovery methods.
A widening of
commodity differentials may adversely impact our revenues and our economics.
Our crude oil and natural gas are priced in the local markets where the
production occurs based on local or regional supply and demand factors. The
prices that we receive for our crude oil and natural gas production are
generally lower than the relevant benchmark prices, such as NYMEX, that are used
for calculating commodity derivative positions. The difference between the
benchmark price and the price we receive is called a differential. We cannot
accurately predict natural gas and crude oil differentials.
Price
differentials may widen in the future. Numerous factors may influence local
pricing, such as refinery capacity, pipeline capacity and specifications, upsets
in the mid-stream or downstream sectors of the industry, trade restrictions and
governmental regulations. We may be adversely impacted by a widening
differential on the products we sell. Our oil and natural gas hedges are based
on WTI or natural gas index prices, so we may be subject to basis risk if the
differential on the products we sell widens from those benchmarks and we do not
have a contract tied to those benchmarks. Additionally, insufficient pipeline
capacity or trucking capability and the lack of demand in any given operating
area may cause the differential to widen in that area compared to other oil and
natural gas producing areas. Increases in the differential between
the benchmark price for oil and natural gas and the wellhead price we receive
could adversely affect our financial condition.
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, trucking
capability 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 pipelines, 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
of gathering systems with sufficient capacity to handle local
production;
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·
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seasonal
fluctuations in local demand for
production;
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·
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local
and national natural gas storage
capacity;
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·
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interstate
pipeline capacity;
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·
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availability
and cost of natural gas transportation facilities;
and
|
·
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availability
and capacity of refineries.
|
Berry
Petroleum Company - 2007 Form 10-K
Utah - During 2007, our Utah light crude oil was sold under
multiple contracts with different purchasers for varying pricing terms, and in
some cases our realized price was further reduced by transportation charges. As
operator we deliver all produced volumes pursuant to these contracts, although
our working interest partners or royalty owners may take their respective
volumes in kind and market their own volumes. We experienced increasing
difficulty in locating additional buyers of our crude oil production from this
region in the latter part of 2006. Our Utah crude oil is a paraffinic crude and
can be processed efficiently by only a limited number of refineries. Increased
production of crude oil in the region, the ability of refiners to process other
higher sulfur crudes as a result of capital upgrades, as well as the increasing
availability of Canadian crude oil, put downward pressure on the sales price of
our crude oil.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract with
a refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery
expansion in Salt Lake City, which is expected in the first half of 2008, the
refiner will increase its total purchased volumes to 5,000 Bbl/D through June
30, 2013. Pricing under the contract, which includes transportation and gravity
adjustments, is at a fixed percentage of WTI, which was near the posted price at
the contract’s starting date. As global and regional prices of crude oil have
risen in 2007, we are receiving crude oil prices below the posted price,
although this posted price is thinly traded and does not necessarily indicate
the actual price at which a seller can market their crude oil. While our price
differentials have widened as the crude oil price increased, we are able to sell
100% of our crude oil to a refiner and avoid any field shut down due to the
inability of placing the crude. The margins on our Uinta crude allow us to
reinvest in drilling the field and to retain and increase the overall value of
the field. As of January 1, 2008 this contract is our only sales contract for
our Uinta oil.
We may not be
able to deliver minimum crude oil volumes required
by
our sales contract. Production volumes from our Uinta properties over the
next six years are uncertain and there is no assurance that we will be able to
consistently meet the minimum contractual requirement. Upon completion of the
refiner’s refinery expansion in Salt Lake City, which is expected in the first
half of 2008, the refiner will increase its total purchased volumes to 5,000
Bbl/D through June 30, 2013. During the term of the contract, the minimum number
of delivered barrels (“base daily volume”) is 3,200 Bbl/D increasing to 5,000
Bbl/D upon the certified completion of the refinery upgrade. In the event that
we cannot produce the necessary volume, we may need to purchase crude to meet
our contract requirements.
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, combined, provide approximately 35% of our steam
capacity. These facilities are dependent on reasonable power contracts for the
sale of electricity. If, for any reason, including if utilities that purchase
electricity from us are no longer required by regulation to enter into power
contracts with us, we were unable to enter into new or replacement contracts or
were to lose any 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 and availability of
equipment. The financial cost and timing of such new investment may adversely
affect our production, capital outlays and cash provided by operating
activities. We have power contracts which expire in 2009 covering our
electricity generation.
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 as a result the cost of steam for use in our oil and gas
operations.
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 necessary to 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. We have firm
transportation to move 12,000 MMBtu/D on the Kern River Pipeline from the
Rocky
Mountains to Kern County, CA, which accounts for approximately
one-quarter of our current requirement.
Our
use of oil and gas price and interest rate hedging contracts involves credit
risk and may limit future revenues from price increases or reduced expenses from
lower interest rates, as well as result in significant fluctuations in net
income and shareholders' equity. We use hedging transactions with
respect to a portion of our oil and gas production with the objective of
achieving a more predictable cash flow, and reducing our exposure to a
significant decline in the price of crude oil and natural gas. We also utilize
interest rate hedges to fix the rate on a portion of our variable rate
indebtedness, as only a portion of our total indebtedness has a fixed rate and
we are therefore exposed to fluctuations in interest rates. While the use of
hedging transactions limits the downside risk of price declines or rising
interest rates, as applicable, their use may also limit future revenues from
price increases or reduced expenses from lower interest rates, as applicable.
Hedging transactions also involve the risk that the counterparty may be unable
to satisfy its obligations.
Berry
Petroleum Company - 2007 Form 10-K
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, develop or to 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 to 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. It is not
possible to measure underground accumulations of oil or natural gas in an exact
way. Estimating
accumulations of oil and gas is a complex process that relies on subjective
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:
·
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quality
and quantity of available data;
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·
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interpretation
of that data; and
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·
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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.
Future commodity
price declines and/or increased
capital costs may result in a
write-down of our asset carrying values which could adversely affect our results
of operations and limit our ability to borrow funds. Declines
in oil and natural gas prices may result in our having to make substantial
downward adjustments to our estimated proved reserves. If this occurs, or if our
estimates of development costs increase, production data factors change or
drilling results deteriorate, accounting rules may require us to write down, as
a non-cash charge to earnings, the carrying value of our oil and natural gas
properties for impairments.
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
estimated prices 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. We may incur impairment charges in the future, which
could have a material adverse effect on our results of operations in the period
incurred and on our ability to borrow funds under our credit
facility.
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 of proved undeveloped acreage. Major and independent
oil and gas companies actively bid for desirable oil and gas properties, as well
as for the equipment, supplies, labor and services required to operate and
develop their properties. Some of these resources may be limited and have higher
prices due to current strong demand. Many of our competitors have financial
resources that are substantially greater than ours, which may adversely affect
our ability to compete within the industry.
Many of
our larger competitors not only drill for and produce oil and natural gas but
also carry on refining operations and market petroleum and other products on a
regional, national or worldwide basis. These companies may be able to pay more
for oil and natural gas properties and evaluate, bid for and purchase a greater
number of properties than our financial or human resources permit. In addition,
there is substantial competition for investment capital in the oil and gas
industry. These larger companies may have a greater ability to continue drilling
activities during periods of low oil and natural gas prices and to absorb the
burden of present and future federal, state, local and other laws and
regulations. Our inability to compete effectively with larger companies could
have a material adverse impact on our business activities, financial condition
and results of operations.
Berry
Petroleum Company - 2007 Form 10-K
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. Also, 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;
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·
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unexpected
drilling conditions;
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·
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pressure
or irregularities in formations;
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·
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equipment
failures or accidents;
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·
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adverse
weather conditions;
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·
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compliance
with governmental or landowner requirements;
and
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·
|
shortages
or delays in the availability of drilling rigs and the delivery of
equipment and/or services, including experienced
labor.
|
The
oil and gas business involves many operating risks that can cause substantial
losses; insurance will not protect us against all of these risks. These risks
include:
·
|
uncontrollable
flows of oil, gas, formation water or drilling
fluids;
|
·
|
pipe
or cement failures;
|
·
|
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. For instance, 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 insurance coverage we deem
appropriate 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, regional, local and other laws and regulations that
could give rise to substantial liabilities from environmental contamination or
otherwise adversely affect our cost, manner or feasibility of doing business.
All facets of our operations are regulated extensively at the federal,
state, regional 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 laws and regulations impose limitations on our
discharge of pollutants into the environment, establish standards for our
management, treatment, storage, transportation and disposal of hazardous
materials and of solid and hazardous wastes, and impose on us obligations to
investigate and remediate contamination in certain circumstances. We also must
satisfy, in some cases, federal and state requirements for providing
environmental assessments, environmental impact studies and/or plans of
development before we commence exploration and production activities.
Environmental and other requirements applicable to our operations generally have
become more stringent in recent years, and compliance with those requirements
more expensive. Frequently changing environmental and other governmental laws
and regulations have increased our costs to plan, design, drill, install,
operate and abandon oil and natural gas wells and other facilities, and may
impose substantial liabilities if we fail to comply with such
Berry
Petroleum Company - 2007 Form 10-K
regulations or for any contamination
resulting from our operations. Failure to comply with these laws and regulations
may also result in the suspension or termination of our operations and subject
us to administrative, civil and criminal penalties. Furthermore, our business,
results from operations and financial condition may be adversely affected by any
failure to comply with, or future changes to, these laws and
regulations.
In addition, we could also be liable
for the investigation or remediation of contamination, as well as other
liabilities concerning hazardous materials or contamination such as claims for
personal injury or property damage. Such liabilities may arise at many
locations, including properties in which we have an ownership interest but no
operational control, properties we formerly owned or operated and sites where
our wastes have been treated or disposed of, as well as at properties that we
currently own or operate, and may arise even where the contamination does not
result from any noncompliance with applicable environmental laws. Under a number
of environmental laws, such liabilities may also be joint and several, meaning
that we could be held responsible for more than our share of the liability
involved, or even the entire share. We have incurred expenses and penalties in
connection with remediation of contamination in the past, and we may do so in
the future. From time to time we have experienced accidental spills, leaks and
other discharges of contaminants at some of our properties, as have other
similarly situated oil and gas companies. Some of the properties that we have
acquired, or in which we may hold an interest but not operational control, may
have past or ongoing contamination for which we may be held responsible. Some of
our operations are in environmentally sensitive areas that may provide habitat
for endangered or threatened species, and other protected areas, and our
operations in such areas must satisfy additional regulatory requirements.
Moreover, public interest in environmental protection has increased in recent
years, and environmental organizations have opposed certain drilling projects
and/or access to prospective lands and have filed litigation to attempt to stop
such projects, including decisions by the Bureau of Land Management regarding
several leases in Utah that we have been awarded.
Our activities are also 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 federal, 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 that are more expensive than we have anticipated could
have a negative effect on our ability to explore or develop our 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.
Recent
and future environmental regulations, including additional federal and state
restrictions on greenhouse gas emissions that may be passed in response to
climate change concerns, may increase our operating costs and also reduce the
demand for the oil and natural gas we produce. On September 27, 2006,
California’s governor signed into law the “California Global Warming Solutions
Act of 2006” Assembly Bill (AB) 32, which establishes a statewide cap on GHG
that will reduce the state’s GHG emissions to 1990 levels by 2020. The
California Air Resources Board (“ARB”) has been designated as the lead agency to
establish and adopt regulations to implement AB 32 by January 1, 2012. Other
state agencies are involved in this effort. ARB is working on mandatory
reporting regulations and early action measures to reduce GHG emissions prior to
the 2012 date. A number of our personnel are involved in monitoring the
establishment of these regulations through industry trade groups and other
organizations in which we are a member. Similar laws and regulations may be
adopted by other states in which we operate or by the federal government. The
oil and natural gas industry is a direct source of certain greenhouse gas
emissions, such as carbon dioxide and methane, and future restrictions on such
emissions could impact our future operations. It is not possible, at this time,
to estimate accurately how regulations to be adopted by ARB or that may be
adopted by others to address GHG emissions would impact our
business.
Furthermore, we benefit from federal
energy laws and regulations that relieve our cogeneration plants, all of which
are QFs, from compliance with extensive federal and state regulations that
control the financial structure of electricity generating plants, as well as the
prices and terms on which electricity may be sold by those plants. These federal
energy regulations also require that electric utilities purchase electricity
generated by our cogeneration plants at a price based on the purchasing
utility's avoided cost, and that the utility sell back-up power to us 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 wholesale
electricity market is available to QFs in its service territory. FERC issued an
order on October 20,
2006 implementing this
amendment to PURPA and on December 20, 2006 issued a subsequent order granting
limited rehearing of the October 20, 2006 order. Any contracts in effect at the time of
such determination would not be affected. Such a determination has not been made
for our service areas in California; however, one of the California utilities has indicated that an
application for relief will be filed upon the implementation of certain changes
to the California electricity markets. Those market
changes are not expected to occur until late in 2008. While the granting of
an application for relief by FERC would not affect any of our current SO
contracts, it could limit the availability of future contracts pursuant to
PURPA. FERC regulations
also permit QFs and utilities to negotiate agreements for utility purchases of
power at rates different than the utilities' avoided
costs.
Berry
Petroleum Company - 2007 Form 10-K
A change in the
jurisdictional characterization of some of our assets by federal, state or local
regulatory agencies or a change in policy by those agencies may result in
increased regulation of our assets, which may cause our revenues to decline and
operating expenses to increase. Our
natural gas gathering operations are generally exempt from FERC regulation under
the Natural Gas Act of 1938, or NGA, but FERC regulation still affects our
gathering operations. FERC has recently proposed to require major non-interstate
pipelines, including natural gas gathering pipelines (to comply with certain
Internet posting requirements) with the goal of promoting transparency in the
interstate natural gas market. The proposed rule would exclude from the posting
requirement non-interstate pipelines flowing annually ten million MMBtus or less
of gas, lying entirely upstream of a processing plant or delivering more than
95% of their gas directly to end users. FERC has not yet issued a final rule on
that proposed rulemaking. We may experience an increase in costs if the rule is
adopted as proposed.
Other
FERC regulations may indirectly impact our gathering and natural gas production
and sales operations. FERC’s policies and practices across the range of its
natural gas regulatory activities (including, for example, its policies on open
access transportation, gas quality, ratemaking, capacity release and market
center promotion) may affect access to natural gas transportation. In recent
years, FERC has pursued pro-competitive policies in its regulation of interstate
natural gas pipelines. However, we cannot assure you that FERC will continue
this approach as it considers matters such as pipeline rates and rules and
policies that may affect rights of access to transportation
capacity.
Section
1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC
as a natural gas company under the NGA. We believe that the natural gas
pipelines in our gathering systems meet the traditional tests FERC has used to
establish a pipeline’s status as a gatherer not subject to regulation as a
natural gas company. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering services is subject to
change based on future determinations by FERC, the courts, or Congress.
Accordingly the classification and regulation of some of our natural gas
gathering facilities may be subject to change based on future determinations by
FERC, the courts, or Congress.
Should we
fail to comply with all applicable FERC administered statutes, rules,
regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, or EP Act 2005, FERC has civil penalty
authority under the NGA to impose penalties for current violations of up to $1
million per day for each violation and disgorgement of profits associated with
any violation.
State
regulation of natural gas gathering facilities and intrastate transportation
pipelines generally includes various safety, environmental and, in some
circumstances, nondiscriminatory take and common purchaser requirements, and
complaint-based rate regulation. Natural gas gathering may receive greater
regulatory scrutiny at the state level because in recent years FERC has
permitted interstate pipeline transmission companies to transfer their gathering
facilities to unregulated affiliates. Our gathering operations could be
adversely affected in the future should they become subject to the application
of state or federal regulation of rates and services. These operations may also
be, or become subject to, safety and operational regulations relating to the
design, installation, testing, construction, operation, replacement and
management of such facilities. Other state regulations may not directly apply to
our business, but may nonetheless affect the availability of natural gas for
purchase, processing and sale, including state regulation of production rates
and maximum daily production allowable from natural gas wells. Additional rules
and legislation pertaining to these matters are considered or adopted from time
to time. We cannot predict what effect, if any, such changes might have on our
operations, but the industry could be required to incur additional capital
expenditures and increased costs depending on future legislative and regulatory
changes. Other state and local regulations also may affect our
business.
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 properties with additional
development potential and properties with minimal production at acquisition but
significant growth potential, 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.
Berry
Petroleum Company - 2007 Form 10-K
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.
Any acquisition involves
potential risks, including, among other things:
·
|
the
validity of our assumptions about reserves, future production, the future
prices of oil and natural gas, revenues and costs, including
synergies;
|
·
|
an
inability to integrate successfully the properties and businesses we
acquire;
|
·
|
a
decrease in our liquidity to the extent we use a significant portion of
our available cash or borrowing capacity to finance
acquisitions;
|
·
|
a
significant increase in our interest expense or financial leverage if we
incur debt to finance acquisitions;
|
·
|
the
assumption of unknown liabilities, losses or costs for which we are not
indemnified or for which our indemnity is
inadequate;
|
·
|
the
diversion of management’s attention from other business
concerns;
|
·
|
an
inability to hire, train or retain qualified personnel to manage and
operate our growing business and
assets;
|
·
|
unforeseen
difficulties encountered in operating in new geographic areas;
and
|
·
|
customer
or key employee losses at the acquired
businesses.
|
Our
decision to acquire a property or business will depend in part on the evaluation
of data obtained from production reports and engineering studies, geophysical
and geological analyses and seismic and other information, the results of which
are often inconclusive and subject to various interpretations.
Also, our
reviews of acquired properties are inherently incomplete because it generally is
not feasible to perform an in-depth review of the individual properties involved
in each acquisition. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential problems. Inspections may not always be performed on
every well, and environmental problems, such as ground water contamination, are
not necessarily observable even when an inspection is undertaken.
If third-party
pipelines interconnected to our natural gas wells and gathering facilities
become partially or fully unavailable to transport our natural gas, our results
of operations and financial condition could be adversely affected.We
depend upon third party pipelines that provide delivery options from our wells
and gathering facilities. Since we do not own or operate these pipelines, their
continuing operation in their current manner is not within our
control. If any of these third-party pipelines become partially or
fully unavailable to transport our natural gas, or if the gas quality
specifications for their pipelines change so as to restrict our ability to
deliver natural gas to those pipelines, our revenues and cash available for
distribution could be adversely affected.
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 and professionals, 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.
Berry
Petroleum Company - 2007 Form 10-K
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, rig
availability and access to our drilling locations utilizing available roads. As
of December 31,
2007, we own three
drilling rigs, two of which are drilling on our properties, and have additional
contract commitments on another three drilling rigs. See contractual obligations
in Item 7 Management’s Discussion and Analysis of Financial Condition and
Results of Operation.
We
may incur losses as a result of title deficiencies. We acquire from third parties, or
directly from the mineral fee owners, working and revenue interests in the oil
and natural gas leaseholds and estates upon which we will perform our
exploration activities. The existence of a material title deficiency can reduce
the value or render a property worthless thus adversely affecting the results of
our operations and financial condition. Title insurance covering mineral
leaseholds is not always available and when available is not always obtained. As
is customary in our industry, we rely upon the judgment of staff and independent
landmen who perform the field work of examining records in the appropriate
governmental offices and abstract facilities before attempting to acquire or
place under lease a specific mineral interest and/or undertake drilling
activities. We, in some cases, perform curative work to correct deficiencies in
the marketability of the title to us. In cases involving title problems, the
amount paid for affected oil and natural gas leases or estates can be generally
lost, and a prospect can become undrillable.
None.
Information required by Item 2
Properties is included under Item 1 Business.
While we are, from time to time, a
party to certain lawsuits in the ordinary course of business, we do not believe
any of such existing lawsuits will have a material adverse effect on our
operations, financial condition, or liquidity.
No matters were submitted to a vote of
security holders during the most recently ended fiscal
quarter.
Executive
Officers. Listed below are the names, ages (as of
December 31,
2007) and positions of our
executive officers and their business experience during at least the past five
years. All our officers are reappointed 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, 54, 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 acted
as the director designated to serve as the presiding director at executive
sessions of the Board in the absences of the Chairman and as liaison between the
independent directors and the CEO. Mr. Heinemann joined the 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.
Berry
Petroleum Company - 2007 Form 10-K
RALPH J. GOEHRING, 51, has been
Executive Vice President and Chief Financial Officer since June 2004. Mr.
Goehring served as Senior Vice President from April 1997 to June 2004, has been
Chief Financial Officer since March 1992, and was Manager of Taxation from
September 1987 until March 1992. In December 2007, Mr. Goehring announced his
intention to retire from his role and duties of Chief Financial Officer in mid
2008. Mr. Goehring’s employment with Berry is expected to conclude by the end of
2008. Mr. Goehring is also an Assistant
Secretary.
MICHAEL DUGINSKI, 41, has been
Executive Vice President and Chief Operating Officer since September 2007. Mr.
Duginski served as Executive Vice President of Corporate Development and
California from October 2005 to August 2007; he
acted as Senior Vice President of Corporate Development from June 2004 through
October 2005 and as Vice President of Corporate Development from February 2002
through June 2004. Mr. Duginski, a mechanical engineer, was previously employed
by 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.
DAN ANDERSON, 45, has been Vice
President of Rocky Mountains Production since October 2005. Mr. Anderson was
Rocky Mountains Manager of Engineering from August 2003 through October 2005.
Previously, Mr. Anderson served as a Senior Staff Petroleum Engineer with
Williams Production RMT from August 2001 through August 2003. He also was a
Senior Staff Engineer with Barrett Resources from October 2000 through August
2001.
WALTER B. AYERS, 64, has acted as Vice
President of Human Resources since May 2006. Mr. Ayers was previously
a private consultant to the energy industry from January 2002 until his
employment with us. Mr. Ayers served as a Manager of Human Resources for
Mobil Oil Corporation from June 1965 until
December 2000.
GEORGE T. CRAWFORD, 47, has been Vice
President of California Production since October 2005. Mr. Crawford served as
Vice President of Production from December 2000 through October 2005 and as
Manager of Production from January 1999 to December 2000. Mr. Crawford, a
petroleum engineer, previously served as the Production Engineering Supervisor
for Atlantic Richfield Corp. (ARCO) from 1989 to 1998, with numerous engineering
and operational assignments, including Production Engineering Supervisor,
Planning and Evaluation Consultant and Operations
Superintendent.
BRUCE S. KELSO, 52, has been Vice
President of Rocky Mountains Exploration since October 2005. Mr. Kelso served as
Rocky Mountains Exploration Manager from August 2003 through October 2005. Mr.
Kelso, a petroleum geologist, previously acted as a Senior Staff Geologist
assigned to Rocky Mountain assets with Williams Production RMT,
from January 2002 through August 2003. He previously held the position of Vice
President of Exploration and Development at Redstone Resources, Inc. from 2000
to 2001.
SHAWN M.
CANADAY, 32, has held the position of Controller since March 2007. Mr. Canaday
served as Treasurer from December 2004 to February 2007 and as 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 Chevron and in
public accounting. Mr. Canaday is also an Assistant Secretary.
KENNETH A. OLSON, 52, has been
Corporate Secretary since December 1985 and was Treasurer from August 1988 until
December 2004.
STEVEN B. WILSON, 44, has been
Treasurer since March 2007. Mr. Wilson was Controller or Assistant Controller
from November 2003 to February 2007. Before joining us in November 2003, he
served as the vice president of finance and administration for Accela, Inc., a
software development company, for three years. Prior to that, he held finance
functions in select companies and in public accounting. Mr. Wilson is also an
Assistant Secretary.
PART
II
Item 5. Market for the Registrant’s Common Equity, Related
Shareholder Matters and Issuer Purchases of Equity
Securities
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 $.50 per share preference in the event of liquidation
or dissolution. Further, each share of Class B Stock is convertible into one
share of Common Stock at the option of the holder.
In November 1999, we 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
Petroleum Company - 2007 Form 10-K
Our 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 2007 and 2006 are shown
below:
|
|
2007
|
|
|
2006
|
|
|
|
Price Range |
|
|
Dividends
|
|
|
Price Range |
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Per
Share
|
|
|
High
|
|
|
Low
|
|
|
Per
Share
|
|
|
|
$ |
31.54 |
|
|
$ |
27.63 |
|
|
$ |
.075 |
|
|
$ |
39.98 |
|
|
$ |
28.60 |
|
|
$ |
.065 |
|
|
|
|
41.08 |
|
|
|
30.41 |
|
|
|
.075 |
|
|
|
39.00 |
|
|
|
27.27 |
|
|
|
.065 |
|
|
|
|
41.06 |
|
|
|
31.03 |
|
|
|
.075 |
|
|
|
35.77 |
|
|
|
26.07 |
|
|
|
.095 |
|
|
|
|
49.39 |
|
|
|
39.30 |
|
|
|
.075 |
|
|
|
33.69 |
|
|
|
25.71 |
|
|
|
.075 |
|
|
|
|
|
|
|
|
|
|
|
$ |
.300 |
|
|
|
|
|
|
|
|
|
|
$ |
.300 |
|
|
|
February 1,
2008
|
|
December 31,
2007
|
|
December 31,
2006
|
|
Berry’s Common Stock closing price per
share as reported on NYSE Composite Transaction Reporting
System
|
|
|
|
|
|
|
|
|
|
|
The number of holders of record of our
Common Stock was 547 as of February 1, 2008. There was one Class B Shareholder of
record as of February 1,
2008.
Dividends.
Our regular annual
dividend is currently $.30 per share, payable quarterly in March, June,
September and December. We paid a special dividend of $.02 per share on
September 29,
2006 and increased our
regular quarterly dividend by 15%, from $.065 to $.075 per share beginning with
the September 2006 dividend.
Since our formation in 1985 through
December 31,
2007, we have paid
dividends on our Common Stock for 73 consecutive quarters and previous to that
for eight consecutive semi-annual periods. We intend to continue the payment of
dividends, although future dividend payments will depend upon our level of
earnings, operating cash flow, capital commitments, financial covenants and
other relevant factors. Dividend payments are limited by covenants in our 1)
credit facility to the greater of $20 million or 75% of net income, and 2) bond
indenture of up to $20 million annually irrespective of our coverage ratio or
net income if we have exhausted our restricted payments basket, and up to $10
million in the event we are in a non-payment default.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not
approved by security holders
|
|
|
|
|
|
|
Issuer
Purchases of Equity Securities.
In June
2005, we announced that our Board of Directors authorized a share repurchase
program for up to an aggregate of $50 million of our outstanding Class A Common
Stock. From June 2005 through December 31, 2007, we repurchased 818,000 shares
in the open market for approximately $25 million. Our repurchase plan expired
and no shares were repurchased in 2007.
Berry
Petroleum Company - 2007 Form 10-K
Performance Graph
This graph shall not be deemed “filed”
for purposes of Section 18 of the Securities and Exchange Act of 1934 (the
“Exchange Act”) or otherwise subject to the liabilities of that section, nor
shall it be deemed incorporated by reference in any filing under the Securities
Act of 1933 or the Exchange Act, regardless of any general incorporation
language in such filing.
Total
returns assume $100 invested on December 31, 2002 in shares of Berry Petroleum
Company, the Russell 2000, the Standard & Poors 500 Index (S&P 500) and
a Peer Group, assuming reinvestment of dividends for each measurement period.
The information shown is historical and is not necessarily indicative of future
performance. The 15 companies which make up the Peer Group are as follows: Bill
Barrett Corp., Cabot Oil & Gas Corp., Cimarex Energy Co., Comstock Resources
Inc., Denbury Resources Inc., Encore Acquisition Co., Forest Oil Corp.,
Petrohawk Energy Corp., Plains Exploration & Production Co., Quicksilver
Resources Inc., Range Resources Corp., St. Mary Land & Exploration Co.,
Stone Energy Corp., Swift Energy Co. and Whiting Petroleum Corp.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/02 |
|
|
|
12/03 |
|
|
|
12/04 |
|
|
|
12/05 |
|
|
|
12/06 |
|
|
|
12/07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Berry
Petroleum Company
|
|
|
100.00 |
|
|
|
122.01 |
|
|
|
292.22 |
|
|
|
353.92 |
|
|
|
387.58 |
|
|
|
560.32 |
|
S&P
500
|
|
|
100.00 |
|
|
|
128.68 |
|
|
|
142.69 |
|
|
|
149.70 |
|
|
|
173.34 |
|
|
|
182.87 |
|
Russell
2000
|
|
|
100.00 |
|
|
|
147.25 |
|
|
|
174.24 |
|
|
|
182.18 |
|
|
|
215.64 |
|
|
|
212.26 |
|
Peer
Group
|
|
|
100.00 |
|
|
|
133.23 |
|
|
|
201.44 |
|
|
|
299.34 |
|
|
|
302.82 |
|
|
|
439.43 |
|
Berry
Petroleum Company - 2007 Form 10-K
The following table sets forth certain
financial information and is qualified in its entirety by reference to the
historical financial statements and notes thereto included in Item 8 Financial
Statements and Supplementary Data. The Statements of Income and Balance Sheet
data included in this table for each of the five years in the period ended
December 31,
2007 were derived from the
audited financial statements and the accompanying notes to those financial
statements (in thousands, except per share, per BOE and % data).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
467,400 |
|
|
$ |
430,497 |
|
|
$ |
349,691 |
|
|
$ |
226,876 |
|
|
$ |
135,848 |
|
|
|
|
55,619 |
|
|
|
52,932 |
|
|
|
55,230 |
|
|
|
47,644 |
|
|
|
44,200 |
|
|
|
|
54,173 |
|
|
|
97 |
|
|
|
130 |
|
|
|
410 |
|
|
|
570 |
|
Operating costs -
oil and gas production
|
|
|
141,218 |
|
|
|
117,624 |
|
|
|
99,066 |
|
|
|
73,838 |
|
|
|
57,830 |
|
Operating costs -
electricity generation
|
|
|
45,980 |
|
|
|
48,281 |
|
|
|
55,086 |
|
|
|
46,191 |
|
|
|
42,351 |
|
|
|
|
17,215 |
|
|
|
14,674 |
|
|
|
11,506 |
|
|
|
6,431 |
|
|
|
3,097 |
|
General and
administrative expenses (G&A)
|
|
|
40,210 |
|
|
|
36,841 |
|
|
|
21,396 |
|
|
|
22,504 |
|
|
|
14,495 |
|
Depreciation,
depletion & amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93,691 |
|
|
|
67,668 |
|
|
|
38,150 |
|
|
|
29,752 |
|
|
|
17,258 |
|
|
|
|
3,568 |
|
|
|
3,343 |
|
|
|
3,260 |
|
|
|
3,490 |
|
|
|
3,256 |
|
|
|
|
129,928 |
|
|
|
107,943 |
|
|
|
112,356 |
|
|
|
69,187 |
|
|
|
32,363 |
|
Basic net income per
share
|
|
|
2.95 |
|
|
|
2.46 |
|
|
|
2.55 |
|
|
|
1.58 |
|
|
|
.74 |
|
Diluted net income
per share
|
|
$
|
2.89 |
|
|
$ |
2.41 |
|
|
$ |
2.50 |
|
|
$ |
1.54 |
|
|
$ |
.73 |
|
Weighted average
number of shares outstanding (basic)
|
|
|
44,075 |
|
|
|
43,948 |
|
|
|
44,082 |
|
|
|
43,788 |
|
|
|
43,544 |
|
Weighted average
number of shares outstanding (diluted)
|
|
|
44,906 |
|
|
|
44,774 |
|
|
|
44,980 |
|
|
|
44,940 |
|
|
|
44,062 |
|
Working
capital
(deficit)
|
|
$ |
(110,350 |
) |
|
$ |
(116,594 |
) |
|
$ |
(54,757 |
) |
|
$ |
(3,840 |
) |
|
$ |
(3,540 |
) |
|
|
|
1,452,106 |
|
|
|
1,198,997 |
|
|
|
635,051 |
|
|
|
412,104 |
|
|
|
340,377 |
|
|
|
|
445,000 |
|
|
|
390,000 |
|
|
|
75,000 |
|
|
|
28,000 |
|
|
|
50,000 |
|
|
|
|
459,974 |
|
|
|
427,700 |
|
|
|
334,210 |
|
|
|
263,086 |
|
|
|
197,338 |
|
|
|
|
.30 |
|
|
|
.30 |
|
|
|
.30 |
|
|
|
.26 |
|
|
|
.24 |
|
Cash flow from
operations
|
|
|
248,279 |
|
|
|
243,229 |
|
|
|
187,780 |
|
|
|
124,613 |
|
|
|
64,825 |
|
Exploration and
development of oil and gas properties
|
|
|
281,702 |
|
|
|
265,110 |
|
|
|
118,718 |
|
|
|
71,556 |
|
|
|
41,061 |
|
Property/facility
acquisitions
|
|
|
56,247 |
|
|
|
257,840 |
|
|
|
112,249 |
|
|
|
2,845 |
|
|
|
48,579 |
|
Additions to
vehicles, drilling rigs and other fixed
assets
|
|
$ |
3,565 |
|
|
$ |
21,306 |
|
|
$ |
11,762 |
|
|
$ |
669 |
|
|
$ |
494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
producing operations (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price
before hedging
|
|
$ |
49.72 |
|
|
$ |
48.38 |
|
|
$ |
47.01 |
|
|
$ |
33.64 |
|
|
$ |
24.48 |
|
Average sales price
after hedging
|
|
|
47.50 |
|
|
|
46.67 |
|
|
|
41.62 |
|
|
|
30.32 |
|
|
|
22.52 |
|
Average operating
costs - oil and gas production
|
|
|
14.38 |
|
|
|
12.69 |
|
|
|
11.79 |
|
|
|
10.09 |
|
|
|
9.57 |
|
|
|
|
1.75 |
|
|
|
1.58 |
|
|
|
1.37 |
|
|
|
.86 |
|
|
|
.51 |
|
|
|
|
4.09 |
|
|
|
3.98 |
|
|
|
2.55 |
|
|
|
2.99 |
|
|
|
2.40 |
|
DD&A - oil and
gas production
|
|
$ |
9.54 |
|
|
$ |
7.30 |
|
|
$ |
4.54 |
|
|
$ |
3.96 |
|
|
$ |
2.86 |
|
|
|
|
9,819 |
|
|
|
9,270 |
|
|
|
8,401 |
|
|
|
7,517 |
|
|
|
6,040 |
|
|
|
|
779 |
|
|
|
757 |
|
|
|
741 |
|
|
|
776 |
|
|
|
767 |
|
Total proved
reserves (BOE)
|
|
|
169,179 |
|
|
|
150,262 |
|
|
|
126,285 |
|
|
|
109,836 |
|
|
|
109,920 |
|
|
|
$ |
2,419,506 |
|
|
$ |
1,182,268 |
|
|
$ |
1,251,380 |
|
|
$ |
686,748 |
|
|
$ |
528,220 |
|
Year end average BOE
price for PV10 purposes
|
|
$ |
66.27 |
|
|
$ |
41.23 |
|
|
$ |
48.21 |
|
|
$ |
29.87 |
|
|
$ |
25.89 |
|
Return on average
shareholders' equity
|
|
|
29.18
|
% |
|
|
28.33
|
% |
|
|
37.63
|
% |
|
|
31.06
|
% |
|
|
17.50
|
% |
Return on average
capital employed
|
|
|
16.01
|
% |
|
|
18.21
|
% |
|
|
32.74
|
% |
|
|
26.29
|
% |
|
|
15.44
|
% |
(1) See
Supplemental Information About Oil & Gas Producing
Activities.
Berry
Petroleum Company - 2007 Form 10-K
Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operation
|
Overview. We seek to increase shareholder value
through consistent growth in our production and reserves, both through the drill
bit and acquisitions. We strive to operate our properties in an efficient manner
to maximize the cash flow and earnings of our assets. The strategies to
accomplish these goals include:
·
|
Developing
our existing resource base
|
·
|
Acquiring
additional assets with significant growth
potential
|
·
|
Utilizing
joint ventures with respected partners to enter new
basins
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
Notable Items in
2007.
·
|
Achieved
record production which averaged 26,902 BOE/D, up 6% from
2006
|
·
|
Achieved
record cash from operating activities of $248 million, up 2% from
2006
|
·
|
Achieved
record net income of $130 million, up 20% from
2006
|
·
|
Added
35.4 million BOE of proved reserves before production ending 2007 at a
record 169.2 million BOE
|
·
|
Achieved
a reserve replacement rate of 293%
|
·
|
Expended
$341 million of capital expenditures, of which $285 million was for
development and $56 million for
acquisitions
|
·
|
Modified
steam injection and new well fracturing techniques at N. Midway diatomite,
increasing production from existing wells and decreasing the steam oil
ratio to six to one
|
·
|
Started
drilling the next 50 well expansion on our N. Midway diatomite
asset
|
·
|
Accomplished
a 15 day drilling record on a mesa location and significantly
reduced the overall number of days and drilling costs in
Piceance
|
·
|
Completed
47 gross (27 net) Piceance basin operated wells which increased net
production to average 10,200 MMcf/D for the full year and 14,600 MMcf/D in
the fourth quarter
|
·
|
Achieved a
record production average of 2,400 Bbl/D at Poso Creek by
drilling an additional 70 wells
|
·
|
Drilled
18 horizontal wells at deeper depths at S. Midway to reduce the natural
decline and identify additional resource
opportunities
|
·
|
Entered
into a long-term crude oil sales contract for our Uinta basin, Utah
production
|
·
|
Entered
into a long-term firm transportation contract on the Rockies Express
pipeline for our Colorado natural gas
production
|
·
|
Sold
Montalvo, California assets with proceeds of approximately $61
million
|
Notable
Items and Expectations for 2008.
·
|
Targeting
over 10% net average production growth to achieve between 29,500 and
30,500 BOE/D
|
·
|
Targeting
an increase in 2008 year end proved reserves to between 180 to 190
MMBOE
|
·
|
Expecting
a 2008 capital expenditure program of $295 million to be funded wholly
from operating cash flow
|
·
|
Drilling
approximately 120 wells at N. Midway diatomite and targeting production to
increase to 2,200 Bbl/D average for the year for an increase of
122%
|
·
|
Executing
a 60 gross (35 net) well drilling program at the Piceance and expecting
production to average 21.6 MMcf/D in
2008
|
·
|
Drilling
28 wells at Poso Creek targeting an average annual production of 3,270
Bbl/D with an average year end exit rate of over 3,500
Bbl/D
|
·
|
Continuing
our appraisal of the Lake Canyon resource potential in the Uinta basin by
drilling four Green River wells, three exploratory wells, and participate
in deep Wasatch wells
|
Overview
of the Fourth Quarter of 2007. We achieved record average production of 28,023 BOE/D in the fourth quarter of 2007, up 4%
from an average of 26,873 BOE/D in the third quarter of 2007. We had net income
of $32.3 million, or $.71 per diluted share and net cash from operations was
$63.7 million. In
December, we entered into a second long-term (ten year) firm
transportation contract for our Colorado natural gas production. This
contract is for 25,000
MMBtu/D on the REX pipeline and provides us assurance of significant deliverability of our increasing gas production in the
Piceance basin. We recognized a $2.9 million pretax
gain on the sale of stock (see Note 17 to the financial statements) and we had a
pretax impairment charge of $3.3 million associated with our Coyote Flats,
Utah asset.
Berry
Petroleum Company - 2007 Form 10-K
View to 2008.
Our challenge for 2008 is to grow our business through improved execution
in a rapidly changing price and high cost environment while adding significant
reserves through the drill bit. We have an extensive inventory of development
drilling in several basins, and expect our program to be the most influenced by
production and reserve growth on our diatomite asset and our properties in the
Piceance basin. Our goal is to achieve at least a 10% increase in production and
a 10% increase in reserves at a very competitive finding and development cost.
Our $295 million capital program is designed to achieve these targets while
being funded entirely out of our cash flow from operations. We expect no
increase in debt in 2008 unless we are successful in acquiring assets and/or WTI
pricing averages below $75 per barrel. We will continue to evaluate acquisition
opportunities that fit our growth strategy. Our previously announced plans to
proceed with a master limited partnership for certain of our assets is currently
on hold due to the unfavorable capital market conditions. We will continue to
monitor the economic conditions relevant to a successful offering.
Capital
expenditures. Our capital
expenditures for 2007 totaled $341 million consisting of $285 million for
development and other assets and $56 million for acquisitions. We also
capitalized $18 million of interest. We funded these items from $248 million of
operating cash flow, $72 million from asset sale proceeds and the balance from
additional borrowings. This compares to our total capital expenditures in 2006
of $544 million, which consisted of $258 million of acquisitions, $286 million
in development and other assets. Also, we capitalized $9 million of interest in
2006.
Excluding the acquisition of new
properties, in 2008 we have a developmental capital program of approximately
$295 million which we expect to fund wholly out of operating cash flow and based
on WTI pricing to average over $75 per barrel. We are proceeding with this
program, but may revise our plans due to lower commodity price expectations,
equipment availability, permitting or other factors.
Our 2008 capital program allows us to
continue high activity levels and as a result, we are targeting 2008 production
to average between 29,500 BOE/D to 30,500 BOE/D. In 2008, we expect production
to be approximately 60% heavy oil, 10% light oil and 30% natural gas. We have
secured the necessary equipment and are currently meeting permit requirements to
achieve the 2008 program.
Development,
Exploitation and Exploration Activity. We drilled 442 gross (339 net) wells
during 2007, realizing a gross success rate of 98 percent. As of December 31, 2007, we have four rigs drilling on our
properties under long-term contracts and have one additional rig that began
operating in early 2008.
Drilling
Activity. The following table sets forth certain
information regarding drilling activities for the year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
47 |
|
|
|
47 |
|
|
|
|
49 |
|
|
|
49 |
|
|
|
|
101 |
|
|
|
101 |
|
|
|
|
86 |
|
|
|
29 |
|
|
|
|
50 |
|
|
|
48 |
|
|
|
|
109 |
|
|
|
65 |
|
|
|
|
442 |
|
|
|
339 |
|
(1) Includes 7
gross wells (4.6 net wells) that were dry holes in
2007.
|
Net
Oil and Gas Producing Properties at December
31, 2007.
Name,
State
|
|
% Average Working
Interest
|
|
|
Total Net
Acres
|
|
|
Proved Reserves (BOE) in
millions
|
|
|
Proved Developed Reserves (BOE)
in millions
|
|
|
% of Total Proved
Reserves
|
|
|
Proved Undeveloped Reserves (BOE)
in millions
|
|
|
% of Total Proved
Reserves
|
|
|
Average Depth of Producing
Reservoir (feet)
|
|
|
|
|
97 |
|
|
|
2,241 |
|
|
|
52.4 |
|
|
|
46.1 |
|
|
|
27 |
% |
|
|
6.3 |
|
|
|
4 |
% |
|
|
1,700 |
|
|
|
|
100 |
|
|
|
36,636 |
|
|
|
23.5 |
|
|
|
11.7 |
|
|
|
7 |
|
|
|
11.8 |
|
|
|
7 |
|
|
|
6,000 |
|
|
|
|
100 |
|
|
|
1,373 |
|
|
|
26.3 |
|
|
|
13.3 |
|
|
|
8 |
|
|
|
13.0 |
|
|
|
7 |
|
|
|
1,200 |
|
|
|
|
47 |
|
|
|
67,453 |
|
|
|
21.1 |
|
|
|
13.4 |
|
|
|
8 |
|
|
|
7.7 |
|
|
|
5 |
|
|
|
2,600 |
|
|
|
|
100 |
|
|
|
1,898 |
|
|
|
22.8 |
|
|
|
12.1 |
|
|
|
7 |
|
|
|
10.7 |
|
|
|
6 |
|
|
|
1,500 |
|
|
|
|
32 |
|
|
|
3,157 |
|
|
|
23.1 |
|
|
|
6.2 |
|
|
|
4 |
|
|
|
16.9 |
|
|
|
10 |
|
|
|
9,300 |
|
|
|
|
|
|
|
|
112,758 |
|
|
|
169.2 |
|
|
|
102.8 |
|
|
|
61 |
% |
|
|
66.4 |
|
|
|
39 |
% |
|
|
|
|
Berry
Petroleum Company - 2007 Form 10-K
Our asset base has changed considerably
since early 2003. As of December 31, 2007, we had 169.2 MMBOE of proved reserves
and have abundant drilling inventories at several of our core areas. Generally,
our California assets are mature (our diatomite
resource play and our Poso Creek properties are the exceptions) and generate
more cash flow from operations than is required to reinvest in these assets. We
have high capital needs in the Piceance, Uinta and the DJ basins, where we have
large undeveloped resources. We anticipate spending most of our operating cash
flow over the next several years in converting the recoverable hydrocarbons to
production, cash flow and earnings.
Properties
We have
six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset
including diatomite (N. Midway), Southern California including Poso Creek and
Placerita (S. Cal), Piceance, Uinta and DJ.
|
S.
Midway - We own and operate working interests in 38 properties,
including 23 owned in fee. Production from this field relies on thermal
EOR methods, primarily cyclic steaming to place steam effectively into the
remaining oil column. This is our most mature thermally enhanced
asset.
2007
- Production averaged approximately 9,600 Bbl/D in 2007. We completed 18
horizontal wells at deeper depths which slowed the natural decline of
these assets. These wells targeted resource opportunities below our
existing horizontal wells and along the edge of the reservoir. Of these
infill wells, 25 were drilled to delineate and assess the resource base of
a Berry legacy asset at Ethel D.
2008
- Capital is focused on adding 15 horizontal wells below existing
horizontal wells, drilling ten vertical steam injection locations to place
steam continuously along the edge of the reservoir, and further
development at Ethel D including the initiation of a pilot steam
flood.
N.
Midway - In November 2006, we announced our plans to commence
full scale development of our diatomite project in California based on the
performance of a two-year pilot program. We expect this development will
increase production by up to 8,500 Bbl/D by 2011. As we develop the
fairway, we will also appraise the potential of recovering additional
reserves in the outer portions of our acreage in subsequent development
phases. We believe that the development is similar to other
California fields.
2007
- Production from the diatomite project averaged approximately 990 Bbl/D
in 2007 through implementation of a modified steam injection plan and new
well fracturing techniques. Production continued to increase throughout
the year primarily as a result of cyclic steaming. We initiated the next
phase of our development program in the fairway of the asset in the latter
part of the third quarter and expect to be bringing these wells on
production in the first quarter of 2008. Installation of the necessary
infrastructure, including steam generation equipment and fluid processing
facilities, is also in progress.
2008
- Capital is focused on drilling approximately 120 wells, completing major
infrastructure upgrades that will support future development, increasing
steam injection and further refinement of our thermal recovery techniques
including the testing of a horizontal well concept.
|
Berry
Petroleum Company - 2007 Form 10-K
S. Cal -
We acquired the Poso Creek properties in the San Joaquin Valley basin in
early 2003 and have proceeded with a successful thermal EOR redevelopment. In
the Placerita field in the Los Angeles basin, we own and operate working
interests in thirteen properties, including nine leases and four fee properties.
Production relies on thermal recovery methods, primarily steam
flooding.
2007 -
Poso Creek responded favorably to steam flood injection and our accelerated
infill drilling program performed solidly above plan. Production increased to
over 2,400 Bbl/D in 2007 from less than 1,000 Bbl/D in 2006. We drilled over 70
wells and installed a third steam generator during the year. We expect continued
production improvement as these wells are cyclically steamed, the additional
steam flood patterns are brought on line and the balance of the infill wells are
drilled and completed.
2008 -
Capital is directed at a 28 well drilling program at Poso Creek and further
expansion of the steam flood including the installation of the fourth steam
generator. The expected year end average exit rate at Poso Creek is over 3,500
Bbl/D.
Piceance -
In the first half of 2006, we made two separate acquisitions in the Piceance
basin in Colorado, targeting the Williams Fork section of the Mesaverde
formation. We acquired a 50% working interest in 6,300 gross acres in the Garden
Gulch property and a 5% non-operating working interest on 6,300 gross acres and
a net operating working interest of 95% in 4,300 gross acres in the North
Parachute Ranch property. We spent $312 million to acquire a majority
working interest in several blocks of undeveloped acreage located in the
Grand Valley field. We believe we have accumulated a sizable resource
base with over 1,000 drilling locations which will allow us to add significant
proved reserves over the next five years.
2007 - Production averaged
10,200 MMcf/D in 2007. We operated a four rig drilling program for most of the
year and drilled 39 gross (19 net) wells at Garden Gulch and 8 gross (8 net) at
North Parachute. Significant progress was made in the last half of 2007 in
reducing the days required to drill wells on our Piceance asset. During the
fourth quarter drilling days on our mesa wells averaged 16 days on Garden Gulch
and 19 days in North Parachute and we are confident we can maintain this
efficiency and expect improved economics as a result. Additionally, we continued
to expand the infrastructure needed to support our operations, and have acquired
additional firm transportation for future sales out of this region.
2008 - We plan to operate a four rig program
with our capital directed
at drilling 46 gross (23
net) wells in Garden Gulch and 13 gross (12 net) wells in North Parachute,
constructing the necessary expansion of our gathering and water handling
facilities, and continued expansion of our road infrastructure including the
construction of a new access road to our mesa acreage on the Old Mountain block
of North Parachute.
Uinta
- The Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of approximately 26,000 undeveloped gross
acres which include federal, tribal and private
leases. We are targeting
the Green
River formation that
produces both light oil and natural gas. Along with an industry partner, we hold a
169,000 gross acre block
in the Lake Canyon
project, which is located immediately west of our
Brundage Canyon producing properties. We will drill and operate the shallow
wells, targeting light oil and natural gas in the
Green River formation and retain up to a 75%
working interest. Our partner will drill and operate deep wells that will target hydrocarbons in the Mesaverde
and Wasatch formations. We 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 our and our partner’s participation.
2007 -
During 2007 the refinery capacity for our black wax crude improved from the
constraints experienced during 2006. In February 2007, we signed a six year oil
contract with a refiner, allowing us to deliver 3,200 Bbl/D starting in July
2007 with up to 5,000 Bbl/D through June 30, 2013 upon the certified completion
of its refinery upgrade expected in the first half of 2008. Deliveries under
this contract has allowed us to sell all of our crude oil production in the
Uinta Basin and has stabilized our realized sales price and reduced
transportation costs.
In 2007
we drilled 50 gross (48 net) wells in the Uinta project which included 39 gross
(39 net) wells at Brundage Canyon, six wells testing the Ashley Forest acreage
to the south, and five wells at Lake Canyon targeting the Green River
formation. In addition, we participated in the drilling of one Lake
Canyon Wasatch well with our industry partner. Average daily production during
2007 from all Uinta basin assets was approximately 5,700 net BOE/D. At the end
of 2007, we had one drilling rig operating in the basin.
2008 - Capital at Brundage Canyon is directed at drilling 44 additional wells targeting
high graded locations across the field and further delineation wells on our
Ashley Forest acreage to the south. We are also
evaluating the feasibility of waterflooding Brundage Canyon to further improve recovery and
anticipate installing a waterflood pilot late this year. The Ashley Forest EIS
continues to progress and we anticipate approval in the first quarter of 2009.
Capital at Lake Canyon is directed at the continued appraisal of our acreage
with the drilling of four wells targeting the Green River, and three exploratory
wells targeting both Green River and Wasatch potential and to participate with
our industry partner in deep Wasatch wells.
Berry
Petroleum Company - 2007 Form 10-K
DJ - In 2005, we made three
acquisitions for approximately $111 million establishing a core area
in the Niobrara gas producing assets in Yuma County in northeastern Colorado, where we have a working interest
averaging approximately 52%. This acquisition in the Tri-State region (Eastern Colorado, western Kansas and southwestern Nebraska) totaled approximately 100,000 net producing
acres and 315,000 net total acres. Our other two acquisitions in the region
consisted of undeveloped prospective acreage where our working interests range
from 40% to 50%. Our Yuma County Niobrara projects
provide sustainable and steady cash flow resulting from low capital development
costs, modest production declines and long-life reserves.
2007 - We drilled over 100 successful
Niobrara development wells in Yuma County adding production from both proved
undeveloped and probable reserves. We continued to expand our
compression and gathering infrastructure and acquired an additional 37 square miles of 3-D seismic data in Colorado. Average daily production in the DJ in
2007 was 18,700 net MMcf/D. We determined that our position in a portion of the
Tri-State acreage was not sizable enough for us to continue with its
development, thus we wrote down $4.6 million of our Tri-State acreage
carrying value in connection with the sale of these properties, which we believe approximates fair
value as of December 31, 2007 based on available information.
2008 - Capital is directed at drilling 86 gross (37 net) Niobrara wells, installing pumping units on 145
gross (45 net) wells, and installing associated compression, gathering and water
disposal facilities. Over 75 square miles of 3-D seismic acquisition in
Yuma County is planned for early 2008.
Obstacles
and Risks to Accomplishment of Strategies and Goals. See Item 1A Risk Factors for a
detailed discussion of factors that affect our business, financial condition and
results of operations.
|
Revenues. Approximately 80% of our
revenues are generated through the sale of oil and natural gas production
under either negotiated contracts or spot gas purchase contracts at market
prices. The remaining 20% of our revenues are primarily derived from
electricity sales from cogeneration facilities which supply approximately
35% of our steam requirement for use in our California thermal heavy oil operations. We
have invested in these facilities for the purpose of lowering our steam
costs which are significant in the production of heavy crude oil.
Sales
of oil and gas were up 9% in 2007 compared to 2006 and up 23% from 2005.
This improvement was due to an overall increase in both oil and gas
production levels and increased oil prices. Improvements in production
volume reflect the successful results of capital investments. While
improvement in oil prices during 2007 were due to a tighter supply and
demand balance, natural gas prices decreased as a result of the impact of
high storage levels and mild weather conditions in the U.S. Oil and
natural gas prices contributed roughly 3% of the revenue increase and the
increase in production volumes contributed the other 6%. Approximately 70%
of our oil and gas sales volumes in 2007 were crude oil, with 83% of the
crude oil being heavy oil produced in California which was sold under
contracts based on the higher of WTI minus a fixed differential or the
average posted price plus a premium. Our oil contracts allowed us to
improve our California revenues over the posted price by approximately $15
million, $21 million and $41 million in 2007, 2006 and 2005,
respectively.
|
The following companywide results are
in millions (except per share data) for the years ended December
31:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
$ |
385 |
|
|
$ |
360 |
|
|
$ |
289 |
|
|
|
|
82 |
|
|
|
70 |
|
|
|
61 |
|
Total sales of oil and
gas
|
|
$ |
467 |
|
|
$ |
430 |
|
|
$ |
350 |
|
|
|
|
56 |
|
|
|
53 |
|
|
|
55 |
|
|
|
|
54 |
|
|
|
1 |
|
|
|
- |
|
Interest and other income,
net
|
|
|
6 |
|
|
|
2 |
|
|
|
2 |
|
Total revenues and other
income
|
|
$ |
583 |
|
|
$ |
486 |
|
|
$ |
407 |
|
|
|
$ |
130 |
|
|
$ |
108 |
|
|
$ |
112 |
|
Earnings per share
(diluted)
|
|
$ |
2.89 |
|
|
$ |
2.41 |
|
|
$ |
2.50 |
|
Berry
Petroleum Company - 2007 Form 10-K
The following companywide results are
in millions (except per share data) for the three months
ended:
|
|
December 31,
2007
|
|
|
December 31,
2006
|
|
|
September 30,
2007
|
|
|
|
$ |
109 |
|
|
$ |
84 |
|
|
$ |
100 |
|
|
|
|
24 |
|
|
|
18 |
|
|
|
19 |
|
Total
sales of oil and gas
|
|
$ |
133 |
|
|
$ |
102 |
|
|
$ |
119 |
|
|
|
|
15 |
|
|
|
13 |
|
|
|
12 |
|
|
|
|
2 |
|
|
|
- |
|
|
|
1 |
|
Interest
and other income, net
|
|
|
3 |
|
|
|
1 |
|
|
|
1 |
|
Total
revenues and other income
|
|
$ |
153 |
|
|
$ |
116 |
|
|
$ |
133 |
|
|
|
$ |
32 |
|
|
$ |
19 |
|
|
$ |
27 |
|
Net
income per share (diluted)
|
|
$ |
.71 |
|
|
$ |
.43 |
|
|
$ |
.60 |
|
Oil
Contracts. See Item 1
Business.
Hedging. See Item 7A Quantitative and
Qualitative Disclosures about Market Risk and Note 15 to the financial
statements.
Berry
Petroleum Company - 2007 Form 10-K
Operating
data. The following table
is for the years ended December 31:
|
|
|
2007
|
%
|
|
2006
|
%
|
|
2005
|
%
|
Oil and
Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
|
|
Light Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
|
|
Total Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Production
(Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage increase from prior
year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price
before hedging
|
|
|
|
|
|
|
|
|
|
|
Average sales price
after hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price sensitive
royalties
|
|
|
|
|
|
|
|
|
|
|
Gravity differential and
other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average oil sales price after
hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Henry Hub price per
MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location, quality differentials
and other
|
|
|
|
|
|
|
|
|
|
|
Average gas sales price after
hedging
|
|
|
|
|
|
|
|
|
|
|
Berry
Petroleum Company - 2007 Form 10-K
The following table is for the three
months ended:
|
|
|
December 31,
2007
|
%
|
|
December 31,
2006
|
%
|
|
September 30,
2007
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
15,806
|
59
|
Light Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
3,675
|
14
|
Total Oil Production
(Bbl/D)
|
|
|
|
|
|
|
|
|
19,481
|
73
|
Natural Gas Production
(Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,873
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price
before hedging
|
|
|
|
|
|
|
|
|
|
|
Average sales price
after hedging
|
|
|
|
|
|
|
|
|
47.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75.15
|
|
Price sensitive
royalties
|
|
|
|
|
|
|
|
|
(5.50
|
)
|
Gravity differential and
other
|
|
|
|
|
|
|
|
|
(9.56
|
)
|
|
|
|
|
|
|
|
|
|
(4.37
|
)
|
Average oil sales price after
hedging
|
|
|
|
|
|
|
|
|
55.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Henry Hub price per
MMBtu
|
|
|
|
|
|
|
|
|
6.24
|
|
|
|
|
|
|
|
|
|
|
.31
|
|
|
|
|
|
|
|
|
|
|
1.07
|
|
Location, quality differentials
and other
|
|
|
|
|
|
|
|
|
(3.06
|
)
|
Average gas sales price after
hedging
|
|
|
|
|
|
|
|
|
4.56
|
|
Electricity. We consume natural gas
as fuel to operate our three cogeneration facilities which are intended to
provide an efficient and secure long-term supply of steam necessary for the
cost-effective production of heavy oil. We sell our electricity to utilities
under standard offer contracts based on "avoided cost" or SRAC pricing approved
by the CPUC and under which our revenues are currently linked to the cost of
natural gas. Natural gas index prices are the primary determinant of our
electricity sales price based on the current pricing formula under these
contracts. The correlation between electricity sales and natural gas prices
allows us to manage our cost of producing steam more effectively. Revenues were
up and operating costs were down in the year ended 2007 from the year ended 2006
due to 2% higher electricity prices and 6% lower natural gas prices,
respectively. In 2007, our electricity operations improved partially from the
lower cost of our firm transportation natural gas we purchased. We purchase and
transport 12,000 average MMBtu/D on the Kern River Pipeline under our firm
transportation contract and use this gas to produce conventional and
cogeneration steam in the Midway-Sunset field. The differential between
Rocky Mountain gas prices and Southern California Border prices increased
during 2007 compared to 2006 allowing us to purchase a portion of our gas at
prices less than the Southern California Border price. As our electricity
revenue are linked to Southern California Border prices, the fuel we purchased
at lower Rocky Mountain prices was the primary contributor to the increase in
our electricity margin in 2007.
Berry
Petroleum Company - 2007 Form 10-K
We purchased approximately 38 MMBtu/D
as fuel for use in our cogeneration facilities in the year ended December 31, 2007. On September 20, 2007, the CPUC issued
a decision (SRAC Decision) that changes prospectively the way SRAC energy prices will be determined for
existing and new SO contracts and revises the capacity prices paid under current
SO1 contracts. Based on our preliminary analysis, we do not believe that the
proposed pricing changes will materially affect us in 2008. The following table is for the years
ended December 31:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
|
$ |
55.6 |
|
|
$ |
52.9 |
|
|
$ |
55.2 |
|
Operating costs (in
millions)
|
|
$ |
46.0 |
|
|
$ |
48.3 |
|
|
$ |
55.1 |
|
Decrease to total oil and gas
operating expenses per barrel
|
|
$ |
.98 |
|
|
$ |
.50 |
|
|
$ |
.02 |
|
Electric power produced -
MWh/D
|
|
|
2,133 |
|
|
|
2,074 |
|
|
|
2,030 |
|
Electric power sold -
MWh/D
|
|
|
1,932 |
|
|
|
1,867 |
|
|
|
1,834 |
|
Average sales price/MWh (no
hedging was in place)
|
|
$ |
78.62 |
|
|
$ |
77.13 |
|
|
$ |
82.73 |
|
Fuel gas cost/MMBtu (including
transportation)
|
|
$ |
6.08 |
|
|
$ |
6.44 |
|
|
$ |
7.72 |
|
The following table is for the three
months ended:
|
|
December 31,
2007
|
|
|
December 31,
2006
|
|
|
September 30,
2007
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
|
$ |
14.9 |
|
|
$ |
13.5 |
|
|
$ |
12.3 |
|
Operating costs (in
millions)
|
|
$ |
11.0 |
|
|
$ |
12.1 |
|
|
$ |
9.8 |
|
Electric power produced -
MWh/D
|
|
|
2,099 |
|
|
|
2,093 |
|
|
|
2,257 |
|
Electric power sold -
MWh/D
|
|
|
2,077 |
|
|
|
1,861 |
|
|
|
2,077 |
|
|
|
$ |
78.98 |
|
|
$ |
75.05 |
|
|
$ |
71.28 |
|
Fuel gas cost/MMBtu (including
transportation)
|
|
$ |
6.10 |
|
|
$ |
6.44 |
|
|
$ |
5.07 |
|
Royalties.
A price-sensitive royalty burdens certain of our S. Midway properties which
produced approximately 2,900 BOE/D in 2007. This royalty is 75% of the amount of
the heavy oil posted price above a base price which was $15.79 in 2007. This
base price escalates at 2% annually, thus the threshold price is $16.11 per
barrel in 2008. Liabilities payable for these royalties were $36 million,
$36 million and $29 million in the years ended December 31, 2007,
2006 and 2005, respectively. Because our interest in the revenue varies
according to crude prices, the continuing development on this property will
depend on its future profitability.
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 ended
December 31:
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
2007
|
|
2006
|
Change
|
|
2007
|
|
2006
|
|
Change
|
Operating costs - oil and gas
production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A - oil and gas
production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our total operating costs, production
taxes, G&A and interest expenses for 2007, stated on a unit-of-production
basis, increased 18% over 2006. The changes were primarily related to the
following items:
Berry
Petroleum Company - 2007 Form 10-K
|
·
|
Operating costs: Our operating
costs increased primarily due to higher contract services and labor costs,
higher compression, gathering, and dehydration costs and higher steam
costs resulting from higher volumes of injected steam. The following table
presents steam information:
|
|
2007
|
2006
|
Change
|
|
Average volume of steam injected
(Bbl/D)
|
|
|
|
|
Fuel gas cost/MMBtu (including
transportation)
|
|
|
|
|
As we
remain in a strong commodity price environment, we anticipate that cost
pressures within our industry may continue due to greater field activity and
rising service costs in general. Based on current plans, we are targeting
average steam injection in 2008 of approximately 110,000 BSPD or a 25% increase
compared to 2007.
|
·
|
Production
taxes: Our production taxes have increased over the last year as the value
of our oil and natural gas has increased. Severance taxes, which are
prevalent in Utah and Colorado, are directly related to the field sales
price of the commodity. In California, our production is burdened with ad
valorem taxes on our total proved reserves. We expect production taxes to
track oil and gas prices generally.
|
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE in 2007 by 31%
from 2006. Over the past year this increase has resulted from an increase
in capital spending in fields with higher drilling and leasehold
acquisition costs, which is in line with our expectations. Additionally,
DD&A may continue to trend higher as a certain portion of our interest
cost related to our Piceance basin acquisitions is capitalized into
the basis of the assets. We anticipate a portion will continue to be
capitalized over the next several years until our probable reserves have
been recategorized to proved
reserves.
|
|
·
|
General
and administrative: Approximately 70% of our G&A is related to
compensation. The primary reason for the increase in G&A during 2007
was an 8% increase in employee headcount to accelerate the
development of our assets and our competitive compensation practices to
attract and retain our personnel.
|
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured money
market line of credit and senior subordinated notes, was $459 million
at December 31, 2007 compared to $406 million at December 31, 2006.
Average borrowings in 2007 increased primarily due to our final payment on
our Piceance acquisition. For the year ended December 31, 2007, $18
million of interest cost has been capitalized and we expect to capitalize
approximately $20 million of interest cost during the full year of
2008.
|
The following table presents
information about our operating expenses for the three months
ended:
|
|
Amount per
BOE
|
|
|
Amount (in
thousands)
|
|
|
|
December 31,
2007
|
|
|
December 31,
2006
|
|
|
September 30,
2007
|
|
|
December 31,
2007
|
|
|
December 31,
2006
|
|
|
September
30, 2007
|
|
Operating costs - oil and gas
production
|
|
$ |
14.70 |
|
|
$ |
13.69 |
|
|
$ |
13.75 |
|
|
$ |
37,889 |
|
|
$ |
33,804 |
|
|
$ |
33,995 |
|
|
|
|
1.91 |
|
|
|
1.15 |
|
|
|
1.76 |
|
|
|
4,918 |
|
|
|
2,840 |
|
|
|
4,344 |
|
DD&A - oil and gas
production
|
|
|
10.94 |
|
|
|
8.24 |
|
|
|
9.45 |
|
|
|
28,212 |
|
|
|
20,335 |
|
|
|
23,356 |
|
|
|
|
4.24 |
|
|
|
4.55 |
|
|
|
3.78 |
|
|
|
10,918 |
|
|
|
11,231 |
|
|
|
9,333 |
|
|
|
|
1.43 |
|
|
|
1.27 |
|
|
|
1.75 |
|
|
|
3,693 |
|
|
|
3,503 |
|
|
|
4,326 |
|
|
|
$ |
33.22 |
|
|
$ |
28.90 |
|
|
$ |
30.49 |
|
|
$ |
85,630 |
|
|
$ |
71,713 |
|
|
$ |
75,354 |
|
|
December 31,
2007
|
December 31,
2006
|
Change
|
September 30,
2007
|
Change
|
Average volume of steam injected
(Bbl/D)
|
|
|
|
88,711
|
|
Fuel gas cost/MMBtu (including
transportation)
|
|
|
|
$
5.07
|
|
Berry
Petroleum Company - 2007 Form 10-K
The following table presents
information about our operating expenses for each of the years ended December
31:
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
2006
|
|
2005
|
Change
|
|
2006
|
|
2005
|
|
Change
|
Operating costs - oil and gas
production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A - oil and gas
production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our total operating costs, production
taxes, G&A and interest expenses for 2006, stated on a unit-of-production
basis, increased 27% over 2005. The changes were primarily related to the
following items:
|
·
|
Operating
costs: Operating costs in 2006 were 8% higher than 2005 due to an increase
in well servicing activities and higher cost of goods and services in
general. We installed additional steam generators in California and as a
result of the increased steam injection, our crude oil production on these
properties increased. The cost of our steaming operations varies depending
on the cost of natural gas used as fuel and the volume of steam injected.
The following table presents steam
information:
|
|
2006
|
2005
|
Change
|
|
Average volume of steam injected
(Bbl/D)
|
|
|
|
|
Fuel gas cost/MMBtu (including
transportation)
|
|
|
|
|
|
·
|
Production
taxes: During 2006 our production taxes increased as a result of higher
assessed values on our properties, increased production and higher
investment in mineral interests.
|
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE in 2006 due to
large increases in capital spending since 2005 and particularly more
extensive development in fields with higher drilling costs. Higher
leasehold acquisition costs in 2003 through 2006 are expected to increase
our DD&A expense over the life of these assets as development
increases. Our capital program experienced cost pressures in our labor and
for goods and services commensurate with other energy developers. As these
costs increase, our DD&A rates per BOE will also
increase.
|
|
·
|
General
and administrative: Approximately two-thirds of our G&A is
compensation or compensation related costs. Our employee headcount
increased 16% in 2006 as we added an important new core asset into our
portfolio and as we strengthened our talent base. Other items increasing
our G&A in 2006 were contributions to fund the opposition of
Proposition 87 in California, increased travel and consulting costs and a
generally higher level of activity.
|
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured money
market line of credit and senior subordinated notes, was $406 million
at December 31, 2006 compared to $87 million at December 31, 2005.
Average borrowings in 2006 increased as a result of our Piceance basin
acquisitions during 2006 and capital expenditures program. A certain
portion of our interest cost related to our Piceance basin acquisition and
joint venture has been capitalized into the basis of the assets. For the
year ended December 31, 2006, $9.3 million was
capitalized.
|
Estimated
2008 Oil and Gas Operating, G&A and Interest Expenses. We estimate our 2008 production volume
will range between 29,500 BOE/D and 30,500 BOE/D. Based on WTI of $75 and NYMEX
HH of $7.50 MMBtu, we expect our expenses to be within the following
ranges:
|
|
Amount per
BOE
|
|
|
|
Anticipated
|
|
|
|
|
|
|
|
range in
2008
|
|
2007
|
|
2006
|
|
Operating costs-oil and gas
production (1)
|
|
|
16.00
to 17.50
|
|
|
|
|
|
|
|
|
|
|
1.75
to 2.25
|
|
|
|
|
|
|
|
|
|
|
9.75
to 10.75
|
|
|
|
|
|
|
|
|
|
|
4.00
to 4.50
|
|
|
|
|
|
|
|
|
|
|
1.25
to 1.50
|
|
|
|
|
|
|
|
|
|
|
32.75
to 36.50
|
|
|
|
|
|
|
|
(1) We expect
operating costs to increase in 2008 as compared to 2007 due to higher projected
natural gas costs.
Berry
Petroleum Company - 2007 Form 10-K
Dry
hole, abandonment, impairment and exploration. In 2007 we had dry hole, abandonment
and impairment charges of $13.7 million consisting primarily of a $4.6 million
writedown of a portion of our Tri-State acreage in connection with the current
and pending sale of these properties, a $3.3 million impairment of our Coyote
Flats prospect to reflect its fair value in conjunction with the preparation of
our year end reserve estimates, a $2.9 million writedown of our Bakken
properties sold in September 2007, and other dry hole charges of $2.2 million.
We incurred exploration costs of $.7 million in 2007 compared to $3.8 million
and $3.6 million in 2006 and 2005, respectively. These costs consist primarily
of geological and geophysical costs in the DJ basin. We are projecting
geological and geophysical costs in 2008 of between $2 million and $3 million.
In 2006 we incurred $8.3 million of dry
hole, abandonment and impairment consisting primarily of two Coyote Flats, Utah
wells for $5.2 million, our 25% share in an exploration well (located in the
Lake Canyon project area of the Uinta basin) drilled for approximately $1.6
million net to our interest, four wells in Bakken and four wells in the DJ basin
for $1.5 million. For the year ended 2005, costs of $5.7 million were incurred
on the following: one exploratory well on the Coyote Flats prospect, one well on
the Midway-Sunset property, two exploratory wells on northern Brundage Canyon in
the Uinta basin, and impairment of $2.5 million on the remaining carrying value
of our Illinois and eastern Kansas prospective CBM acreage were charged to expense.
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 which utilizes
certain methods, including cyclic steam and steam flood recovery methods for
heavy oil. We don’t expect to generate the EOR tax credit for 2008, due to
current oil prices. As of December 31, 2007 we have approximately $24 million of
federal and $18 million of state (California) EOR tax credit carryforwards
available to reduce future cash income taxes. The EOR credits will begin to
expire, if unused, in 2024 and 2015 for federal and California purposes,
respectively.
We experienced an effective tax rate of
38%, 39% and 31% in 2007, 2006 and 2005, respectively. The rate is lower than
our combined federal and state statutory tax rate of 40% primarily due to
certain business incentives. In anticipation of the continued full EOR credit
phase out in 2008, we expect our effective tax rate to approximate 38%, given
the current oil price environment. See Note 9 to the financial statements for
further information.
Commodity
derivatives. In March 2006, we took a charge
for the change in fair market value of our natural gas derivatives put in place
to protect our Piceance basin acquisition future cash flows. These gas
derivatives did not qualify for hedge accounting under SFAS 133 because the
price index in the derivative instrument did not correlate closely with the item
being hedged. The pre-tax charge of $4.8 million represented the change in
fair market value over the life of the contract, resulting from an increase in
natural gas prices from the date of the derivative to March 31, 2006. In May 2006, we entered into
basis swaps with natural gas volumes to match the volumes on our NYMEX Henry Hub
collars that were placed on March 1, 2006. The combination of the derivative
instruments entered into on March 1, 2006 (described above) and the basis swaps
were designated as cash flow hedges in accordance with SFAS 133. Thus the
unrealized net gain of $5.6 million on the Statements of Income in 2006
under the caption "Commodity derivatives" is primarily the change in fair value
of the derivative instrument caused by changes in forward price curves prior to
designating these instruments as cash flow hedges. Post May 2006 changes in
the marked-to-market fair values are reflected in Other Comprehensive
Income.
Asset
dispositions. We have
significantly increased and strengthened our portfolio of assets since 2002 and
expect to continue to make acquisitions. We anticipate that we will dispose of
certain properties or assets over time. The assets most likely for disposition
will be those that do not fit or complement our strategic growth plan, that are
not contributing satisfactory economic returns given the profile of the assets,
or that we believe the development potential will not be meaningful to us as a
whole. We divested several assets in 2007. Proceeds from these sales contributed
to the funding of our capital program. Net oil and gas properties and equipment
classified as held for sale is $1.4 million as of December 31, 2007 in accordance with SFAS No. 144. See
Note 2 to the financial statements.
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. Total new proved reserves include revisions of previous
estimates, improved recovery, extensions and discoveries, and purchase of
reserves in place. This measure is important because it is an indication of
growth in proved reserves and thus may impact our market value. We believe our
calculation of this measure is substantially similar to how other companies
compute the reserve replacement rate. See Item 8 Supplemental Information About
Oil & Gas Producing Activities (unaudited).
Financial
Condition, Liquidity and Capital Resources. Substantial capital is
required to replace and grow reserves. We achieve reserve replacement and growth
primarily through successful development and exploration drilling and the
acquisition of properties. Fluctuations in commodity prices, production rates
and operating expenses have been the primary reason for changes in our cash flow
from operating activities. In 2006, we revised our senior unsecured revolving
credit facility to increase our maximum credit amount under the facility to
$750 million and in 2007 we increased our borrowing base from $500 million
to $550 million. On October 24, 2006, we completed the sale of $200 million
of ten year 8.25% senior subordinated notes and paid down our borrowings under
our facility by $141 million. As of December 31, 2007, we had total borrowings
under the senior
Berry
Petroleum Company - 2007 Form 10-K
unsecured
revolving credit facility and senior unsecured money market line of credit of
$259 million and $200 million under our senior subordinated notes. See
Item 7A Quantitative and Qualitative Disclosures About Market Risk for
discussion of interest rate sensitivity.
Capital
Expenditures. We establish a capital budget for each
calendar year based on our development opportunities and the expected cash flow
from operations for that year. Acquisitions are typically debt financed. We may
revise our capital budget during the year as a result of acquisitions and/or
drilling outcomes or significant changes in cash flow. Excess cash generated
from operations is expected to be applied toward acquisitions, debt reduction or
other corporate purposes.
In 2008, we have a capital program of
approximately $295 million, excluding acquisitions. Our 2008 expenditures will
be directed toward developing reserves, increasing oil and gas production and
exploration opportunities. For 2008, we plan to invest approximately $118
million, or 40%, in our heavy crude oil assets, and $175 million, or 59%, in our
natural gas and light oil assets. Approximately two-thirds of the capital budget
is focused on converting probable and possible reserves into proved reserves and
on our appraisal and exploratory projects, while the other one-third is for the
development of our proved undeveloped reserves and facility
costs.
Dividends. Our regular annual dividend is
currently $.30 per share, payable quarterly in March, June, September and
December.
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. Combined crude oil and natural gas prices increased
in 2007 (see graphs on pages 32 and 33) and we increased production by 6%.
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 senior unsecured revolving 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 May
2007, we sold our non-core West Montalvo assets in Ventura County, California.
The sale proceeds were approximately $61 million and we recognized a $52 million
pretax gain on the sale, including post closing adjustments. Production from the
property was approximately 700 BOE/D, which is less than 3% of average 2007
production and, as of December 31, 2006, the property had 7 million BOE of
proved reserves, which is less than 5% of the 2006 year end total of 150 million
BOE. Separately,
during the second quarter we paid the third and final installment of
approximately $54 million for the North Parachute Ranch property located in the
Piceance basin.
The table below compares financial
condition, liquidity and capital resources changes as of and for the years ended
December 31 (in millions, except for production and average prices):
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
Average production
(BOE/D)
|
|
|
26,902 |
|
|
|
25,398 |
|
|
|
6 |
% |
Average oil and gas sales prices,
per BOE after hedging
|
|
$ |
47.50 |
|
|
$ |
46.67 |
|
|
|
2 |
% |
Net cash provided by operating
activities
|
|
$ |
248 |
|
|
$ |
243 |
|
|
|
2 |
% |
|
|
$ |
(110 |
) |
|
$ |
(117 |
) |
|
|
6 |
% |
|
|
$ |
467 |
|
|
$ |
430 |
|
|
|
9 |
% |
|
|
$ |
459 |
|
|
$ |
406 |
|
|
|
13 |
% |
Capital expenditures, including
acquisitions and deposits on acquisitions
|
|
$ |
338 |
|
|
$ |
523 |
|
|
|
(35 |
%) |
|
|
$ |
13.3 |
|
|
$ |
13.2 |
|
|
|
1 |
% |
The table below compares financial
condition, liquidity and capital resources changes as of and for the three
months ended (in millions, except for production and average prices):
|
|
December 31,
2007
|
|
|
December 31,
2006
|
|
|
Change
|
|
|
September 30,
2007
|
|
|
Change
|
|
Average production
(BOE/D)
|
|
|
28,023 |
|
|
|
26,889 |
|
|
|
4 |
% |
|
|
26,873 |
|
|
|
4 |
% |
Average oil and gas sales prices,
per BOE after hedging
|
|
$ |
52.31 |
|
|
$ |
42.00 |
|
|
|
25 |
% |
|
$ |
47.93 |
|
|
|
9 |
% |
Net cash provided by operating
activities
|
|
$ |
64 |
|
|
$ |
58 |
|
|
|
10 |
% |
|
$ |
93 |
|
|
|
(31 |
%) |
|
|
$ |
(110 |
) |
|
$ |
(117 |
) |
|
|
6 |
% |
|
$ |
(91 |
) |
|
|
(21 |
%) |
|
|
$ |
133 |
|
|
$ |
102 |
|
|
|
30 |
% |
|
$ |
119 |
|
|
|
12 |
% |
|
|
$ |
459 |
|
|
$ |
406 |
|
|
|
13 |
% |
|
$ |
440 |
|
|
|
4 |
% |
Capital expenditures, including
acquisitions and deposits on acquisitions
|
|
$ |
76 |
|
|
$ |
127 |
|
|
|
(40 |
%) |
|
$ |
63 |
|
|
|
21 |
% |
|
|
$ |
3.3 |
|
|
$ |
3.3 |
|
|
|
- |
% |
|
$ |
3.4 |
|
|
|
(3 |
%) |
Berry
Petroleum Company - 2007 Form 10-K
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.
Contractual
Obligations.
Our contractual obligations as of
December 31,
2007 are as follows (in
thousands):
|
|
Total
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
Long-term debt and
interest
|
|
$ |
649,658 |
|
|
$ |
36,336 |
|
|
$ |
31,029 |
|
|
$ |
31,029 |
|
|
$ |
268,764 |
|
|
$ |
16,500 |
|
|
$ |
266,000 |
|
|
|
|
36,426 |
|
|
|
1,456 |
|
|
|
1,456 |
|
|
|
1,456 |
|
|
|
1,456 |
|
|
|
1,456 |
|
|
|
29,146 |
|
Operating lease
obligations
|
|
|
12,407 |
|
|
|
1,690 |
|
|
|
1,374 |
|
|
|
1,357 |
|
|
|
1,357 |
|
|
|
1,357 |
|
|
|
5,272 |
|
Drilling and rig
obligations
|
|
|
74,749 |
|
|
|
23,559 |
|
|
|
18,817 |
|
|
|
7,353 |
|
|
|
25,020 |
|
|
|
- |
|
|
|
- |
|
|
|
|
173,243 |
|
|
|
15,206 |
|
|
|
19,545 |
|
|
|
19,544 |
|
|
|
19,545 |
|
|
|
19,054 |
|
|
|
80,349 |
|
|
|
$ |
946,483 |
|
|
$ |
78,247 |
|
|
$ |
72,221 |
|
|
$ |
60,739 |
|
|
$ |
316,142 |
|
|
$ |
38,367 |
|
|
$ |
380,767 |
|
Long-term
debt and interest - Our
credit facility borrowings and related interest of approximately 5.9% can be
paid before its maturity date without significant penalty. Our bond notes and
related interest of 8.25% mature in November 2016, but are not redeemable until
November 1,
2011 and are not
redeemable without any premium until November 1, 2014.
Operating
leases - We lease
corporate and field offices in California, Colorado and Texas. Rent expense with respect to our
lease commitments for the years ended December 31, 2007, 2006 and 2005 was $1.5 million, $1
million and $.6 million, respectively. In 2006, we purchased an airplane for
business travel which was subsequently sold and contracted under a ten year
operating lease beginning December 2006.
Drilling
obligations - Starting in
2006, we began to participate in the drilling of over 16 gross wells on our
Lake Canyon prospect over the four year contract.
Our minimum obligation under our exploration and development agreement is $9.6
million, and as of December 31, 2007 the remaining obligation is $5.4
million. Also included above, under our June 2006 joint venture agreement in the
Piceance basin we are required to have 120 wells drilled by February 2011 to
avoid penalties of $.2 million per well or a maximum of $24 million. As of
December 31,
2007 we have drilled 12 of
these wells.
Drilling
rig obligations - We are
obligated in operating lease agreements for the use of multiple drilling rigs.
Firm
natural gas transportation
- We have one firm transportation contract which provides us additional
flexibility in securing our natural gas supply for California operations. This allows us to
potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in
California. We have seven long-term
transportation contracts on four different pipelines to provide us with physical
access to move gas from our producing areas to various
markets.
Other Obligations. We
adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of December 31, 2007, we had a
gross liability for uncertain tax benefits of $12 million of which $9.1
million, if recognized, would affect the effective tax rate. We recognize
potential accrued interest and penalties related to unrecognized tax benefits in
income tax expense, which is consistent with the recognition of these items
in prior reporting periods. As of December 31, 2007, we had accrued
approximately $1.1 million of interest related to our uncertain tax
positions. Due to
the uncertainty about the periods in which examinations will be completed and
limited information related to current audits, we are not able to make
reasonably reliable estimates of the periods in which cash settlements will
occur with taxing authorities for the noncurrent
liabilities.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract with
a refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D on July 1, 2007. Upon completion of its refinery
expansion in Salt Lake City, which is expected in the first half of 2008, the
refiner will increase its total purchased volumes to 5,000 Bbl/D through June
30, 2013. Pricing under the contract, which includes transportation and gravity
adjustments, is at a fixed percentage of WTI, which was near the posted price at
the contract’s starting date.
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.
Berry
Petroleum Company - 2007 Form 10-K
A critical accounting policy is one
that is important to the portrayal of our 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. We believe
the following accounting policies are critical policies.
Successful
Efforts Method of Accounting. We account for our 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. Our 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 our 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 our estimated
reserve quantities, increases in future cost estimates or depressed crude oil or
natural gas prices could cause us to reduce the carrying amounts of our
properties. We perform an impairment analysis of our proved properties annually,
or when current events or circumstances indicate that carrying amount may not be
recoverable, by comparing the future undiscounted net revenue 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 our estimates of crude oil and natural gas reserves, future
crude oil and natural gas prices and costs to extract these reserves. For our
unproved properties, we perform 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. We follow 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, we may
designate a derivative instrument as hedging the exposure to changes 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. Our policy is to assess hedge effectiveness at the end
of each calendar quarter.
Income
Taxes. We
compute income taxes in accordance with SFAS No. 109, Accounting for Income Taxes
as
interpreted by FIN 48, Accounting
for Uncertainty in 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 our 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, our federal and state income tax
returns are generally not filed before the financial statements are prepared.
Therefore, we estimate the tax basis of our 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.
We may generate EOR tax credits from the production of our heavy crude oil in
California which may result in a deferred tax asset. We believe that these
credits will be fully utilized in future years and consequently have 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
Berry
Petroleum Company - 2007 Form 10-K
effective
tax rate. FIN 48 clarifies the accounting for
income taxes by prescribing the minimum recognition threshold an uncertain tax
position is required to meet before tax benefits associated with such uncertain
tax positions are recognized in the financial statements. FIN 48 also provides
guidance on derecognition, measurement, classification, interest and penalties,
accounting in interim periods, disclosure and transition. FIN 48 excludes income
taxes from the scope of SFAS No. 5, Accounting for
Contingencies. FIN 48 also
requires that amounts recognized in the Balance Sheet related to uncertain tax
positions be classified as a current or noncurrent liability, based upon the
expected timing of the payment to a taxing authority.
Asset
Retirement Obligations. We have 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 our asset retirement
obligations (ARO) was prepared in accordance with SFAS
No. 143, Accounting for
Asset Retirement Obligations, which requires us to record the fair
value of liabilities for retirement obligations of long-lived assets. Estimating
the future ARO requires management to make estimates
and judgments regarding timing, current estimates of plugging and abandonment
costs, as well as to determine what constitutes adequate remediation. We
obtained estimates from third parties and used the present value of estimated
cash flows related to our 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 our assets, the ultimate costs to retire our wells
may vary significantly from previous estimates.
Environmental
Remediation Liability. We review, on a quarterly basis, our
estimates of costs of the cleanup of various sites including sites in which
governmental agencies have designated us 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, and the interpretation of laws and regulations, which can be
interpreted differently by regulators or courts of law. Our experience and the
experience of other companies in dealing with similar matters influence the
decision of management as to how it intends to respond to a particular matter. A
change in estimate could impact our oil and gas operating costs and the
liability, if applicable, recorded on our Balance Sheet.
Accounting
for Business Combinations. We have 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 may 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 the 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 acquired
and liabilities assumed at the time of acquisition. Consequently, we have not
recognized any goodwill from any of our business combinations.
Stock-Based
Compensation. We adopted SFAS No. 123(R) to account for our stock
option plan beginning January 1, 2006. This standard requires us 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. We previously
adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based
Compensation effective January 1, 2004. The modified prospective
method was selected as described in SFAS 148, Accounting for Stock-Based
Compensation—Transition and Disclosure. Under this method, we recognize
stock option compensation expense as if we had applied the fair value method to
account for unvested stock options from the 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 our
stock. We use 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
Berry
Petroleum Company - 2007 Form 10-K
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. Our
investment in our cogeneration facilities has been for the express purpose of
lowering steam costs in our 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. We
allocate steam costs to our 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 capital costs of the cogeneration facilities is
allocated to DD&A-oil and gas production.
Capitalized
Interest. Interest
incurred on funds borrowed to finance exploration and certain acquisition and
development activities is capitalized. To qualify for interest capitalization,
the costs incurred must relate to the acquisition of unproved reserves, drilling
of wells to prove up the reserves and the installation of the necessary
pipelines and facilities to make the property ready for production. Such
capitalized interest is included in oil and gas properties, buildings and
equipment. Capitalized interest is added into the depreciable base of our assets
and is expensed on a units of production basis over the life of the respective
project.
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. 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, we adopted this
statement beginning January 1, 2006. We previously adopted the fair value
recognition provisions of SFAS No. 123, Accounting for
Stock-Based Compensation.
Accordingly, the adoption of SFAS No. 123(R) using the modified prospective
method did not have a material impact on our condensed financial statements for
the year ended December
31, 2006.
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 principles, 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 became effective for our
fiscal year beginning January 1, 2006. The adoption of SFAS No. 154 had
no effect to our financial position and result of
operations.
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
became effective for our fiscal year beginning January 1, 2007. While there was no impact on our
financial statements as of December 31, 2007, based on our existing derivatives, we
may experience a financial impact depending on the nature and extent of any new
derivative instruments entered into after the effective date of SFAS No.
155.
In June 2006, the Financial Accounting
Standards Board (FASB) issued Interpretation (FIN) No. 48,
Accounting for
Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109,
Accounting for Income Taxes. This interpretation requires that
realization of an uncertain income tax position must be “more likely than not”
(i.e. greater than 50% likelihood of receiving a benefit) before it can be
recognized in the financial statements. Further, this interpretation prescribes
the benefit to be recorded in the financial statements as the amount most likely
to be realized assuming a review by tax authorities having all relevant
information and applying current conventions. This interpretation also clarifies
the financial statement classification of tax-related penalties and interest and
sets forth new disclosures regarding unrecognized tax benefits. We adopted this
interpretation in the first quarter of 2007. See Note 9.
In September 2006, SFAS No. 157,
Fair
Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
SFAS No. 157 will become effective for our fiscal year beginning
January 1,
2008, and we are currently assessing the
effect this statement may have on our financial statements. . However, we do not believe that the
implementation of SFAS 157 will have a material impact on our financial
statements.
In September 2006, Staff Accounting
Bulletin (“SAB”) No. 108, Considering the
Effects of Prior Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements was issued by the Securities
and Exchange Commission. Registrants must quantify the impact
on current period financial statements of correcting all misstatements,
including both those occurring in the current period and the effect of reversing
those that have accumulated from prior periods. This SAB was adopted at December 31, 2006. The adoption of SAB No. 108 had no effect on our financial position or on our results of operations.
Berry
Petroleum Company - 2007 Form 10-K
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities, which permits an entity to measure
certain financial assets and financial liabilities at fair value. The objective
of SFAS No. 159 is to improve financial reporting by allowing entities to
mitigate volatility in reported earnings caused by the measurement of related
assets and liabilities using different attributes, without having to apply
complex hedge accounting provisions. Under SFAS No. 159, entities that elect the
fair value option (by instrument) will report unrealized gains and losses in
earnings at each subsequent reporting date. The fair value option election is
irrevocable, unless a new election date occurs. SFAS No. 159 establishes
presentation and disclosure requirements to help financial statement users
understand the effect of the entity’s election on its earnings, but does not
eliminate disclosure requirements of other accounting standards. Assets and
liabilities that are measured at fair value must be displayed on the face of the
Balance Sheet. This statement is effective beginning January 1, 2008 and we do
not expect this Statement to have a material effect on our financial
statements.
In April
2007, the FASB issued a FASB Staff Position to amend FASB Interpretation 39,
Offsetting of Amounts Related to Certain
Contracts. FIN 39-1 states that a reporting entity that is party to a
master netting arrangement can offset fair value amounts recognized for the
right to reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative
instruments that have been offset under the same master netting arrangement in
accordance with paragraph 10 of Interpretation 39. FIN 39-1 will become
effective for our fiscal year beginning January 1, 2008 and will have no effect
on our financial statements as we do not post collateral under our hedging
agreements.
In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements. SFAS 160 was issued to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary (formerly called minority interests) and for the deconsolidation of a
subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity
in the consolidated financial statements. We do not expect the adoption of SFAS
160 to have a material effect on our financial statements and related
disclosures. The effective date of this Statement is the same as that of the
related Statement 141(R).
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which
improves the information that a reporting entity provides in its financial
reports about a business combination and its effects. This Statement establishes
principles and requirements for how the acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree. The Statement also recognizes
and measures the goodwill acquired in the business combination or a gain from a
bargain purchase and determines what information to disclose to enable
users of the financial statements to evaluate the nature and financial effects
of the business combination. This Statement applies prospectively to
business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008. An entity may not apply it before that date. We may experience a
financial statement impact depending on the nature and extent of any new
business combinations entered into after the effective date of SFAS No.
141(R).
Item 7A. Quantitative
and Qualitative Disclosures About Market
Risk
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As discussed in Note 15 to the
financial statements, to minimize the effect of a downturn in oil and gas prices
and to protect our profitability and the economics of our development plans, we
enter into crude oil and natural gas hedge contracts from time to time. The
terms of contracts depend on various factors, including management's view of
future crude oil and natural gas prices, acquisition economics on purchased
assets and our future financial commitments. This price hedging program is
designed to moderate the effects of a severe crude oil and natural gas price
downturn while allowing us to participate in any commodity price increases. In
California, we benefit from lower natural gas
pricing as we are a consumer of natural gas in our operations and elsewhere we
benefit from higher natural gas pricing. We have hedged, and may hedge in the
future both natural gas purchases and sales as determined appropriate by
management. Management regularly monitors the crude oil and natural gas markets
and our financial commitments to determine if, when, and at what level, some
form of crude oil and/or natural gas hedging and/or basis adjustments or other
price protection is appropriate in accordance with policy established by our
board of directors.
Currently, our hedges are in the form
of swaps and collars. However, we may use a variety of hedge instruments in the
future to hedge WTI or the index gas price. We have crude oil sales contracts in
place which are priced based on a correlation to WTI. Natural gas (for
cogeneration and conventional steaming operations) is purchased at the SoCal
border price and we sell our produced gas in Colorado and Utah at the CIG, PEPL and Questar index prices,
respectively.
Berry
Petroleum Company - 2007 Form 10-K
The following table summarizes our hedge
positions as of December 31, 2007:
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Prices
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Per
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Crude Oil
Sales (NYMEX WTI) Collars
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Natural Gas
Sales (NYMEX HH TO CIG) Basis
Swaps
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Natural Gas Sales (NYMEX HH)
Swaps
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Natural Gas
Sales (NYMEX HH) Collars
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Crude
Oil Sales (NYMEX WTI) Swaps
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Payments to our counterparties are
triggered when the monthly average prices are above the swap or ceiling price in
the case of our crude oil and natural gas sales hedges and below the swap price
for our natural gas sales basis hedge positions. Conversely, payments from our
counterparties are received when the monthly average prices are below the swap
or floor price for our crude oil and natural gas sales hedges and above the swap
price for our natural gas sales basis hedge positions.
As of February 26, 2008, we entered into gas swaps for 15,400
MMBtu/D at $8.50 for the full year of 2009 and basis swaps on the same volumes
for average prices of $1.17, $1.12, $.97 and $1.05 for the first, second, third
and fourth quarters of 2009, respectively.
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below our floor prices which
range from $47.50 to $80.00 per barrel while still participating in any oil
price increase up to the ceiling prices which range from $70.00 to $91.00 per
barrel on the volumes indicated above, and if 2) gas prices decline below
our floor prices which range from $7.50 to $8.00 per MMBtu while still
participating in any gas price increase up to the ceiling prices, which range
from $8.40 to $9.50 per MMBtu on the respective volumes. These hedges improve
our financial flexibility by locking in significant revenues and cash flow upon
a substantial decline in crude oil or natural gas prices, including certain
basis differentials. It also allows us to develop our long-lived assets and
pursue exploitation opportunities with greater confidence in the projected
economic outcomes and allows us to borrow a higher amount under our senior
unsecured revolving credit facility.
While we have designated our hedges as
cash flow hedges in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, it is possible that a portion of the
hedge related to the movement in the WTI to California heavy crude oil price differential may
be determined to be ineffective. Likewise, we may have some ineffectiveness in
our natural gas hedges due to the movement of HH pricing as compared to actual
sales points. If this occurs, the ineffective portion will directly impact net
income rather than being reported as Other Comprehensive Income (Loss). If the differential were to change
significantly, it is possible that our hedges, when marked-to-market, could have
a material impact on earnings in any given quarter and, thus, add increased
volatility to our 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.
Berry
Petroleum Company - 2007 Form 10-K
We entered into derivative contracts
(natural gas swaps and collar contracts) in March 2006 that did not qualify for
hedge accounting under SFAS 133 because the price index for the location in the
derivative instrument did not correlate closely with the item being hedged.
These contracts were recorded in the first quarter of 2006 at their fair value
on the Balance Sheet and we recognized an unrealized net loss of approximately
$4.8 million on the Statements of Income under the caption “Commodity
derivatives.” We entered into natural gas basis swaps on the same volumes and
maturity dates as the previous hedges in May 2006 which allowed for these
derivatives to be designated as cash flow hedges going forward, causing an
unrealized net gain of $5.6 million to be recognized in the second quarter of
2006. The difference of $.8 million was recorded in other comprehensive income
at the date the hedges were designated.
Additionally, in June 2006 and July
2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility. These interest rate swaps have been designated as cash flow
hedges.
The related cash flow impact of all of
our derivative activities are reflected as cash flows from operating
activities.
Irrespective of the unrealized gains
reflected in Other Comprehensive Income, 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, 2007, Accumulated Other Comprehensive Loss,
net of income taxes, consisted of $121 million of unrealized losses from our
crude oil and natural gas hedges. Deferred net losses recorded in Accumulated
Other Comprehensive Loss at December 31, 2007 are expected to be reclassified to
earnings over the life of the contracts. 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 our hedging activities, we utilize
multiple counterparties on our hedges and monitor each counterparty's credit
rating.
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Net reduction of sales of oil and
gas revenue due to hedging activities (in
millions)
|
|
$ |
21.8 |
|
|
$ |
15.7 |
|
|
$ |
45.3 |
|
Net reduction of cost of gas due
to hedging activities (in millions)
|
|
$ |
- |
|
|
$ |
1.6 |
|
|
$ |
5.0 |
|
Net reduction in revenue per BOE
due to hedging activities
|
|
$ |
2.21 |
|
|
$ |
1.71 |
|
|
$ |
5.39 |
|
Based on NYMEX futures prices as of
December 31,
2007 (WTI $88.34; HH
$7.81), we would expect to make pre-tax future cash payments or to receive
payments over the remaining term of our crude oil and natural gas hedges in
place as follows:
|
|
|
|
Impact
of percent change in futures prices
|
|
|
|
12/31/07
|
|
on
earnings
|
|
|
|
|
NYMEX Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+10%
|
|
|
+20%
|
|
Average WTI Futures Price (2008 -
2011)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average HH Futures Price
(2008)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil gain/(loss) (in
millions)
|
|
|
|
|
|
|
)
|
|
|
)
|
|
|
|
|
|
|
Natural Gas gain/(loss) (in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 (WTI $93.71; HH
$7.81)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Rates. Our exposure to
changes in interest rates results primarily from long-term debt. In October
2006, we issued $200 million of 8.25% senior subordinated notes due 2016 in a
public offering. Total long-term debt outstanding at December 31, 2007 and 2006 was $445 million and $390
million, respectively. Interest on amounts borrowed under our revolving credit
facility is charged at LIBOR plus 1.0% to 1.75%, with the exception of the $100
million of principal for which we have a hedge in place to fix the interest rate
at approximately 5.5% plus the senior unsecured revolving credit facility’s
margin through June 30,
2011. Based on year end
2007 credit facility borrowings, a 1% change in interest rates would have a $1
million after tax impact on our financial statements.
Berry
Petroleum Company - 2007 Form 10-K
Item 8. Financial
Statements and Supplementary
Data
|
|
Page
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting
Firm
|
48
|
Balance
Sheets at December 31, 2007 and 2006
|
49
|
Statements
of Income for the Years Ended December 31, 2007, 2006 and
2005
|
50
|
Statements
of Comprehensive Income for the Years Ended December 31, 2007, 2006 and
2005
|
50
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2007, 2006 and
2005
|
51
|
Statements
of Cash Flows for the Years Ended December 31, 2007, 2006 and
2005
|
52
|
Notes
to the Financial Statements
|
51
|
Supplemental
Information About Oil & Gas Producing Activities
(unaudited)
|
70
|
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.
Berry
Petroleum Company - 2007 Form 10-K
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholders of Berry Petroleum Company:
In our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Berry Petroleum
Company at December 31, 2007 and 2006, and the results of its operations and its
cash flows for each of the three years in the period ended December 31,
2007 in conformity
with accounting principles generally accepted in the United States of
America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2007, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible
for these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Management's Report on Internal
Control over Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial statements and on the
Company's internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over
financial reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our
opinions.
As
discussed in Note 2 of the consolidated financial statements, during the year
ended December 31, 2007, Berry Petroleum Company changed the manner in which it
accounts for uncertain tax positions.
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
February 26, 2008
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
December 31,
2007
and 2006
(In Thousands,
Except Share Information)
ASSETS
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
316 |
|
|
$ |
416 |
|
|
|
|
58 |
|
|
|
665 |
|
|
|
|
117,038 |
|
|
|
67,905 |
|
|
|
|
28,547 |
|
|
|
- |
|
Fair value of
derivatives
|
|
|
2,109 |
|
|
|
7,349 |
|
|
|
|
1,394 |
|
|
|
8,870 |
|
Prepaid expenses and
other
|
|
|
11,557 |
|
|
|
13,604 |
|
|
|
|
161,019 |
|
|
|
98,809 |
|
Oil and gas properties
(successful efforts basis), buildings and equipment,
net
|
|
|
1,275,091 |
|
|
|
1,080,631 |
|
Fair value of
derivatives
|
|
|
- |
|
|
|
2,356 |
|
|
|
|
15,996 |
|
|
|
17,201 |
|
|
|
$ |
1,452,106 |
|
|
$ |
1,198,997 |
|
LIABILITIES AND SHAREHOLDERS'
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
90,354 |
|
|
$ |
69,914 |
|
Property acquisition
payable
|
|
|
- |
|
|
|
54,400 |
|
Revenue and
royalties payable
|
|
|
47,181 |
|
|
|
45,845 |
|
|
|
|
21,653 |
|
|
|
20,415 |
|
|
|
|
14,300 |
|
|
|
16,000 |
|
|
|
|
2,591 |
|
|
|
- |
|
|
|
|
- |
|
|
|
745 |
|
Other current liabilities
|
|
|
- |
|
|
|
- |
|
Fair value of
derivatives
|
|
|
95,290 |
|
|
|
8,084 |
|
Total current
liabilities
|
|
|
271,369 |
|
|
|
215,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
128,824 |
|
|
|
103,515 |
|
|
|
|
445,000 |
|
|
|
390,000 |
|
|
|
|
36,426 |
|
|
|
26,135 |
|
|
|
|
398 |
|
|
|
1,437 |
|
Other long-term liabilities
|
|
|
1,657 |
|
|
|
- |
|
Fair value of
derivatives
|
|
|
108,458 |
|
|
|
34,807 |
|
|
|
|
720,763 |
|
|
|
555,894 |
|
Commitments and contingencies
(Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock,
$.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
- |
|
|
|
- |
|
Capital stock, $.01
par value:
|
|
|
|
|
|
|
|
|
Class A Common
Stock, 100,000,000 shares authorized; 42,583,002 shares issued and
outstanding (42,098,551 in 2006)
|
|
|
425 |
|
|
|
421 |
|
Class B Stock,
3,000,000 shares authorized; 1,797,784 shares issued and outstanding
(liquidation preference of $899) (1,797,784 in
2006)
|
|
|
18 |
|
|
|
18 |
|
Capital in excess of par
value
|
|
|
66,590 |
|
|
|
50,166 |
|
Accumulated other comprehensive
loss
|
|
|
(120,704
|
) |
|
|
(19,977
|
) |
|
|
|
513,645 |
|
|
|
397,072 |
|
Total shareholders'
equity
|
|
|
459,974 |
|
|
|
427,700 |
|
|
|
$ |
1,452,106 |
|
|
$ |
1,198,997 |
|
The accompanying notes are an integral
part of these financial statements.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Years ended
December 31,
2007,
2006 and 2005
(In Thousands,
Except Per Share Data)
|
|
2007
|
|
2006
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other
income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs -
oil and gas production
|
|
|
|
|
|
|
|
|
|
|
Operating costs -
electricity generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion & amortization - oil and gas
production
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion & amortization - electricity
generation
|
|
|
|
|
|
|
|
|
|
|
General and
administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry hole,
abandonment, impairment and exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income
taxes
|
|
|
|
|
|
|
|
|
|
|
Provision for income
taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per
share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per
share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares
of capital stock outstanding (used to calculate basic net income per
share)
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive
securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares
of capital stock used to calculate diluted net income per
share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statements of Comprehensive
Income
|
|
|
Years Ended December 31, 2007, 2006 and
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on
derivatives, net of income taxes of ($66,627), $7,647, and ($16,677),
respectively
|
|
|
|
|
|
|
|
|
|
|
Reclassification of realized
gains (losses) on derivatives included in net income, net of income taxes
of ($524), ($4,712) and $1,081, respectively
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Years Ended
December 31,
2007,
2006 and 2005
(In Thousands,
Except Per Share Data)
|
|
|
|
|
|
|
|
|
Capital
in Excess of Par Value
|
|
|
|
|
|
Accumulated Other
Comprehensive
|
|
|
|
|
Balances at January 1, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares repurchased and retired
(217,800 shares)
|
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
Stock-based compensation (294,358
shares)
|
|
|
|
|
|
|
|
|
|
)
|
|
|
|
|
|
|
|
|
)
|
Tax
impact of stock option exercises
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred director fees - stock
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared - $.30
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares repurchased and retired
(600,200 shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation (498,939
shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax
impact of stock option exercises
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred director fees - stock
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared - $.30
per share, including RSU dividend equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain on
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation (484,451
shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax
impact of stock option exercises
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred director fees - stock
compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared - $.30
per share, including RSU dividend equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative
effect of accounting change from adoption of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Years Ended
December 31,
2007,
2006 and 2005
(In
Thousands)
Cash flows from operating
activities:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
$ |
129,928 |
|
|
$ |
107,943 |
|
|
$ |
112,356 |
|
Depreciation,
depletion and amortization
|
|
|
97,259 |
|
|
|
71,011 |
|
|
|
41,410 |
|
|
|
|
12,951 |
|
|
|
8,253 |
|
|
|
5,705 |
|
|
|
|
574 |
|
|
|
(109
|
) |
|
|
- |
|
Stock-based
compensation expense
|
|
|
8,200 |
|
|
|
6,436 |
|
|
|
1,703 |
|
|
|
|
62,465 |
|
|
|
51,666 |
|
|
|
20,847 |
|
|
|
|
(54,173
|
) |
|
|
(97
|
) |
|
|
(130
|
) |
|
|
|
3,561 |
|
|
|
544 |
|
|
|
408 |
|
Cash paid for abandonment
|
|
|
(1,188
|
) |
|
|
606 |
|
|
|
(1,381
|
) |
Increase in current
assets other than cash, cash equivalents and short-term
investments
|
|
|
(47,876
|
) |
|
|
(16,338
|
) |
|
|
(26,717
|
) |
Increase in current
liabilities other than line of credit
|
|
|
36,578 |
|
|
|
13,314 |
|
|
|
33,579 |
|
Net cash provided by operating
activities
|
|
|
248,279 |
|
|
|
243,229 |
|
|
|
187,780 |
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
development of oil and gas properties
|
|
|
(281,702
|
) |
|
|
(265,110
|
) |
|
|
(118,718
|
) |
|
|
|
(56,247
|
) |
|
|
(257,840
|
) |
|
|
(112,249
|
) |
Additions to
vehicles, drilling rigs and other fixed
assets
|
|
|
(3,565
|
) |
|
|
(21,306
|
) |
|
|
(11,762
|
) |
|
|
|
(18,104
|
) |
|
|
(9,339
|
) |
|
|
- |
|
Proceeds from sale
of assets
|
|
|
72,405 |
|
|
|
4,812 |
|
|
|
130 |
|
Net cash used in investing
activities
|
|
|
(287,213
|
) |
|
|
(548,783
|
) |
|
|
(242,599
|
) |
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from
issuances on line of credit
|
|
|
395,150 |
|
|
|
327,250 |
|
|
|
18,000 |
|
Payments on line of
credit
|
|
|
(396,850
|
) |
|
|
(322,750
|
) |
|
|
(6,500
|
) |
Proceeds from
issuance of long-term debt
|
|
|
229,300 |
|
|
|
569,700 |
|
|
|
144,000 |
|
Payments on
long-term debt
|
|
|
(174,300
|
) |
|
|
(254,700
|
) |
|
|
(97,000
|
) |
|
|
|
(13,292
|
) |
|
|
(13,177
|
) |
|
|
(13,228
|
) |
|
|
|
(9,400
|
) |
|
|
15,246 |
|
|
|
1,921 |
|
|
|
|
- |
|
|
|
(18,713
|
) |
|
|
(6,314
|
) |
Proceeds from stock
option exercises
|
|
|
5,178 |
|
|
|
3,156 |
|
|
|
- |
|
|
|
|
3,049 |
|
|
|
3,444 |
|
|
|
- |
|
|
|
|
(1
|
) |
|
|
(5,476
|
) |
|
|
(760
|
) |
Net cash provided by financing
activities
|
|
|
38,834 |
|
|
|
303,980 |
|
|
|
40,119 |
|
Net decrease in cash and cash
equivalents
|
|
|
(100
|
) |
|
|
(1,574
|
) |
|
|
(14,700
|
) |
Cash and cash equivalents at
beginning of year
|
|
|
416 |
|
|
|
1,990 |
|
|
|
16,690 |
|
Cash and cash equivalents at end
of year
|
|
$ |
316 |
|
|
$ |
416 |
|
|
$ |
1,990 |
|
Supplemental disclosures of cash
flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
33,945 |
|
|
$ |
15,019 |
|
|
$ |
5,275 |
|
|
|
$ |
6,715 |
|
|
$ |
18,148 |
|
|
$ |
26,544 |
|
Supplemental non-cash
activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in fair value
of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current (net of
income taxes of ($36,562), $4,188, and ($3,631),
respectively)
|
|
$ |
(54,844 |
) |
|
$ |
6,282 |
|
|
$ |
(5,446 |
) |
Non-current (net of
income taxes of ($30,589), ($1,252), and ($11,965),
respectively)
|
|
|
(45,883
|
) |
|
|
(1,879
|
) |
|
|
(17,947
|
) |
Net increase (decrease) to
accumulated other comprehensive income
|
|
$ |
(100,727 |
) |
|
$ |
4,403 |
|
|
$ |
(23,393 |
) |
Non-cash financing activity:
Property acquired for debt
|
|
$ |
- |
|
|
$ |
54,000 |
|
|
$ |
- |
|
The accompanying notes are an integral
part of these financial statements.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Notes to the
Financial Statements
We are an
independent energy company engaged in the production, development, acquisition,
exploitation and exploration of crude oil and natural gas. We have invested in
cogeneration facilities which provide steam required for the extraction of heavy
oil and which generates electricity for sale.
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 - We
consider all highly liquid investments purchased with a remaining maturity of
three months or less to be cash equivalents. Our cash management process
provides for the daily funding of checks as they are presented to the bank.
Included in accounts payable at December 31, 2007 and 2006 is $7.8 million and $17.2
million, respectively, representing outstanding checks in excess of the bank
balance (book overdraft).
Short-term
investments - Short-term
investments consist principally of United States treasury notes and corporate notes
with remaining maturities of more than three months at the date of acquisition
and are carried at fair value. We utilize specific identification in computing
realized gains and losses on investments sold.
Accounts
receivable - Trade
accounts receivable are recorded at the invoiced amount. We do not have any
off-balance-sheet credit exposure related to our customers. We assess credit
risk and allowance for doubtful accounts on a customer specific basis. As of
December 31,
2007 and 2006, we do not
have an allowance for doubtful accounts.
Income
taxes - We compute income
taxes in accordance with SFAS No. 109, Accounting for
Income Taxes as
interpreted by FIN 48, Accounting
for Uncertainty in 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 our financial statements. This difference will result in
taxable income or deductions in future years when the reported amount of the
asset or liability is recovered or settled, respectively. A valuation allowance
is recognized if it is determined that deferred tax assets may not be fully
utilized in future periods. FIN 48
also requires that amounts recognized in the Balance Sheet related to uncertain
tax positions be classified as a current or noncurrent liability, based upon the
expected timing of the payment to a taxing authority.
Derivatives - To
minimize the effect of a downturn in oil and gas prices and protect our
profitability and the economics of our development plans, from time to time we
enter into crude oil and natural gas hedge contracts. 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.
Settlements are recognized on the Statements of Income under the caption “Sales
of oil and gas”. 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 derivative contracts
that do not qualify for hedge accounting under SFAS No. 133, the contracts are
recorded at fair value on the Balance Sheet with the corresponding unrealized
gain or loss on the Statements of Income under the caption “Commodity
derivatives.” 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. We measure 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. A regression analysis is used to
determine whether the relationship is considered to be highly effective
retrospectively and prospectively. Actual effectiveness of the hedge will be
calculated against the underlying cumulatively using the dollar offset
method at the end of each quarter. 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, will be 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 our crude oil and natural gas sales and in operating expenses for hedges
related to our natural gas consumption. The resulting cash flows are reported as
cash flows from operating activities. See Note 15 - Hedging.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Notes to the
Financial Statements
2.
|
Summary of
Significant Accounting Policies (Cont'd)
|
Assets held
for sale - We consider an
asset to be held for sale when management approves and commits to a formal plan
to actively market an asset for sale. Upon designation as held for sale, the
carrying value of the asset is recorded at the lower of the carrying value or
its estimated fair value, less costs to sell. Once an asset is determined to be
“held for sale”, we no longer record DD&A on the property. We anticipate
that we will dispose of certain properties or assets over time. The assets most
likely for disposition will be those that do not fit or complement our strategic
growth plan, that are not contributing satisfactory economic returns given the
profile of the assets, or that we believe the development potential will not be
meaningful to our company as a whole. Proceeds from these sales will contribute
to the funding of our capital program. Net oil and gas properties and equipment
classified as held for sale is $1.4 million and $8.9 million as of December 31, 2007 and 2006, respectively, in accordance
with SFAS No. 144.
Leases - We
entered into two separate three year lease agreements on two company owned
drilling rigs. Each agreement has a three year purchase option in favor of the
lessee. The agreements were signed in 2005 and 2006 and are accounted for as
direct financing leases as defined by SFAS No. 13,
Accounting for Leases, and
included in other long term assets on the Balance Sheet. We routinely enter into noncancelable
lease agreements for premises and equipment used in the normal course of
business. In addition to minimum rental payments, certain of these leases
require additional payments to reimburse the lessors for operating expenses such
as real estate taxes, maintenance, utilities and insurance. Rental expense is
recorded on a straight-line basis.
Oil and gas
properties, buildings and equipment - We account for our 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 will be expensed as dry holes. All exploratory wells are
evaluated for economic viability within one year of well completion and the
related capitalized costs are reviewed quarterly. Exploratory wells that
discover potentially economic reserves in areas where a major capital
expenditure would be required before production could begin, and where the
economic viability of that major capital expenditure depends upon the successful
completion of further exploratory work in the area, remain capitalized if the
well found a sufficient quantity of reserves to justify its completion as a
producing well and we are 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.
In accordance with SFAS No. 144,
Accounting for the
Impairment or Disposal of Long-Lived Assets, we group assets at the field level
and periodically review the carrying value of our property and equipment to test
whether current events or circumstances indicate such carrying value may not be
recoverable. If the tests indicate that the carrying value of the asset is
greater than the estimated future undiscounted cash flows to be generated by
such asset, then an impairment adjustment needs to be recognized. Such
adjustment consists of the amount by which the carrying value of such asset
exceeds its fair value. We generally measure fair value by considering sale
prices for similar assets or by discounting estimated future cash flows from
such asset using an appropriate discount rate. Considerable management judgment
is necessary to estimate the fair value of assets, and accordingly, actual
results could vary significantly from such estimates. When assets are sold, the
applicable costs and accumulated depreciation and depletion are removed from the
accounts and any gain or loss is included in income. Expenditures for
maintenance and repairs are expensed as incurred.
Asset
retirement obligations (ARO) - We have 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 our ARO is prepared in accordance with SFAS
No. 143, Accounting for
Asset Retirement Obligations. Under this standard, we record the
fair value of the future abandonment as capitalized abandonment costs in Oil and
Gas Properties with an offsetting abandonment liability. We obtain estimates
from third parties and use the present value of estimated cash flows related to
the ARO to determine the fair value. The
capitalized abandonment costs are amortized with other property costs using the
units-of-production method. We increase the liability monthly by recording
accretion expense using our credit adjusted interest rate. Accretion expense is
included in DD&A in our financial statements.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Notes to the
Financial Statements
2.
|
Summary of
Significant Accounting Policies (Cont'd)
|
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. The electricity and natural gas we produce and use in our
operations are not included in revenues. Revenues from crude oil and natural gas
production from properties in which we have an interest with other producers are
recognized on the basis of our 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 - Our
investment in cogeneration facilities has been for the express purpose of
lowering steam costs in our heavy oil operations and securing operating control
of the respective steam generation. Such cogeneration operations produce
electricity and steam. We allocate steam costs to our 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,
2007, 2006 and 2005 was
$5.0 million, $5.3 million and $5.7 million, respectively.
Shipping
and handling costs -
Shipping and handling costs, consisting primarily of natural gas transportation
costs, are included in either "Operating costs - oil and gas production" or
"Operating costs - electricity generation,” as applicable. Natural gas
transportation costs included in these categories were $6.7 million, $6.8
million and $5.8 million for 2007, 2006 and 2005, respectively. Additionally,
the transportation costs in the Uinta basin were $1.4 million and $1.1 million
in 2007 and 2006, respectively.
Production
taxes - Consist primarily
of severance, production and ad valorem taxes.
Stock-based
compensation - We adopted
SFAS No. 123(R) beginning January 1, 2006. We previously adopted the fair value
recognition provisions of SFAS No. 123, Accounting for
Stock-Based Compensation
effective January 1,
2004. The implementation
of FAS123(R) did not have a material impact on us. The modified prospective
method was selected as described in SFAS 148, Accounting for
Stock-Based Compensation - Transition and Disclosure. Under this method, we recognize stock
option compensation expense as if we had applied the fair value method to
account for unvested stock options from the original effective date. We
recognize stock option compensation expense from the date of grant to the
vesting date.
In accounting for the income tax benefits associated with employee exercises of
share-based payments, we have elected to adopt the alternative simplified method
as permitted by FASB Staff Position (“FSP”) No. FAS 123(R)-3, Accounting for the Tax Effects of Share-Based Payment
Awards. FSP No. FAS 123(R)-3 permits the adoption of either the
transition guidance described in SFAS No. 123(R) or the alternative simplified
method specified in FSP No. FAS 123(R)-3 to account for the income tax effects
of share-based payment awards. In determining when additional tax benefits
associated with share-based payment exercises are recognized, we follow the
ordering of deductions under the tax law, which allows deductions for
share-based payment exercises to be utilized before previously existing net
operating loss carryforwards. In computing dilutive shares under the treasury
stock method, we do not reduce the tax benefit within the calculation for the
amount of deferred tax assets.
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). Our 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. Nonqualified
stock options totaling 855,000, 499,000, and 23,000 were excluded from the
calculation of diluted net income per common share for 2007, 2006 and 2005,
respectively, because they were antidilutive. The
assumed proceeds in the treasury stock calculation include proceeds received for
the grant price and the tax windfall/shortfall amounts recognized in the
financial statements.
Environmental
expenditures - We review,
on a quarterly basis, our estimates of costs of the cleanup of various sites,
including sites in which governmental agencies have designated us 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.
Subsidiaries - We
have two subsidiaries which serve to gather and transport natural gas in our
Lake Canyon and Brundage Canyon fields. These subsidiaries are
accounted for using the equity method and our net investment in these entities
is included under the caption “Other assets” on our Balance Sheet.
Berry
Petroleum Company - 2007 Form 10-K
BERRY PETROLEUM
COMPANY
Notes to the
Financial Statements
2.
|
Summary of
Significant Accounting Policies (Cont'd)
|
Accounting
for business combinations - We have accounted for
all of our 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. We have not recognized any goodwill
from any business combinations.