form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
T Annual Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
fiscal year ended December 31,
2008
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
DELAWARE
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77-0079387
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(State
of incorporation or organization)
|
(I.R.S.
Employer Identification
Number)
|
1999
Broadway
Denver,
Colorado 80202
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code:
(303)
999- 4400
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, $0.01 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 £ NO T
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 £ NO T
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 T NO £
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. £
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 filerT
|
Accelerated
filer£
|
Non-accelerated
filer£
|
Smaller
reporting company£
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES £ NO T
As of
June 30, 2008, the aggregate market value of the voting and non-voting common
stock held by non-affiliates was $2,173,457,341. As of February 2, 2009, the
registrant had 42,782,521 shares of Class A Common Stock outstanding. The
registrant also had 1,797,784 shares of Class B Stock outstanding on February 2,
2009 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.
TABLE
OF CONTENTS
PART
I
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Page
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Item
1.
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3
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3
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5
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8
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9
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10
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10
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11
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12
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12
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13
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13
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Item
1A.
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15
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Item
1B.
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22
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Item
2.
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22
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Item
3.
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Item
4.
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23
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PART
II
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Item
5.
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24
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Item
6.
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27
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Item
7.
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28
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Item
7A.
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44
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Item
8.
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48
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50
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51
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52
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53
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Item
9.
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77
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Item
9A.
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77
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Item
9B.
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78
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PART
III
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Item
10.
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78
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Item
11.
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78
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Item
12.
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79
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Item
13.
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79
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Item
14.
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79
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PART
IV
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Item
15.
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80
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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. In 2008, we purchased and began operating properties in East Texas
(E. Texas). Also in 2008, we relocated our corporate headquarters to
Denver, Colorado and we have regional offices in Bakersfield, California and
Plano, Texas. Information contained in this report on Form 10-K reflects our
business during the year ended December 31, 2008 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, hedging summaries, 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. Information on our website is
not incorporated into this report. 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 the value of our business 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. 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, and
optimization technologies, as applicable. We also have large potential
hydrocarbon resources in place in the San Joaquin Valley, California
(diatomite); Piceance, Colorado; Uinta, Utah (Lake Canyon); and Cotton Valley
Trend in E. Texas. We have a proven track record of developing reserves and
establishing new businesses in the Rocky Mountain and E. Texas
regions.
Investing our
capital in a disciplined manner and maintaining a strong financial
position. 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 will allow us to capitalize on
investment opportunities in all commodity cycles. Our capital programs are
developed to be fully funded through internally generated cash flows while our
acquisitions have been primarily funded through debt. We hedge a significant
portion of our production and utilize long-term sales contracts whenever
possible to maintain a strong financial position and provide the cash flow
necessary for the development of our assets.
Acquiring
additional assets with significant growth
potential. We will continue to evaluate oil and
gas properties with proved reserves, probable reserves and/or acreage positions
that we believe contain substantial hydrocarbons which can be developed at
reasonable costs. In July 2008 we completed the acquisition of
natural gas producing properties in E. Texas for approximately $650
million. We will continue to review asset acquisitions that meet our
economic criteria with a primary focus on large repeatable development potential
in these regions.
Accumulating
significant acreage positions near our producing operations. We
have been successful in adding significant acreage positions in our producing
areas. This strategy allows us to leverage our operating and
technical expertise within the area and build on established core
operations.
Business
strengths.
Balanced high
quality asset portfolio with a long reserve
life. Since 2002, we have grown our asset base and
diversified our California heavy oil through a number of acquisitions in the
Rocky Mountain and East Texas regions that have significant growth
potential. Our diverse asset base provides us with the flexibility to reallocate
capital among our assets depending on fluctuations in natural gas and oil prices
as well as area economics. Our production based asset teams are focused around
S.Midway-Sunset, Southern California and DJ assets. Our resource based asset
teams are focused around diatomite, Piceance, Uinta and our newly acquired E.
Texas assets. Our base of legacy California assets provides us with a
steady stream of cash flow to fund our significant drilling inventory and the
appraisal of our prospects. Our wells are generally characterized by long
production lives and predictable performance.
Low-risk
multi-year drilling inventory in established resource
plays. Most of our drilling locations are located
in proven resource plays that possess low geologic risk leading to predictable
drilling results. Our historical drilling success rate for the three
years ended December 31, 2008 has averaged 98%.
Experienced
management and operational teams. Our core team of technical
staff and operating managers have broad industry experience, including
experience in heavy oil thermal recovery operations and 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.
Track record of
efficient proved reserve and production
growth. For the three years ended December 31,
2008, our proved reserves and production increased at an annualized compounded
rate of 25% and 12%, respectively. We apply our operational expertise
to improve the efficiency and profitability of our drilling projects. For
example, in the Piceance we have decreased our well drilling time from 40 days
in 2006 to under 10 days in 2008, while at the same time increasing our initial
production rates from 1,250 Mcfe/d to 1,350 Mcfe/d. We believe we can
continue to deliver strong and efficient growth through the drill bit by
exploiting our drilling inventory. We also plan to complement this drill bit
growth through selective and focused acquisitions.
Operational
control and financial flexibility. We
exercise operating control over approximately 99% of our proved reserve base. We
generally prefer to retain operating control over our properties, allowing us to
more effectively control operating costs, timing of development activities and
technological enhancements, marketing of production, and 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 of our capital budget. We finance our drilling budget primarily through our
internally generated operating cash flows.
Long Lived Proved
Reserves. 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, 2008) of
approximately 19 years as compared to 16.5 years at year end
2007. Our estimated proved reserves as of December 31, 2008 were 246
million BOE, of which 45% are heavy crude oil, 6% light crude oil and 49%
natural gas. We have a geographically diverse asset base with 45% of our proved
reserves located in California, 35% in the Rocky Mountains and 20% in East
Texas. Of our proved reserves 55% were proved developed, while proved
undeveloped reserves make up 45%of our proved total. The projected future
capital to develop these proved undeveloped reserves is $950 million at an
estimated cost of approximately $8.55 per BOE. Approximately 61% of the capital
to develop these reserves is expected to be expended in the next five
years.
We have
organized our operations into seven 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, DJ and
E. Texas. The following table sets forth the estimated quantities of proved
reserves and production attributable to our asset teams as of December 31,
2008.
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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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, 2008. D&M is an
independent oil and gas consulting firm. 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, 2008. 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 Operations.
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 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. In
E. Texas, natural gas produced from the Darco and Oakes properties is
transported intra-state on the Enbridge system to various market
points.
Crude Oil and
Natural Gas Marketing.
Economy.
Global and regional demand for crude oil and natural gas declined in the
latter part of 2008 as part of the overall economic recession. Oil is
a globally priced commodity and is priced according to the supply and demand of
crude oil and its products. The range of NYMEX light sweet crude
prices for 2008, based upon settlements, was a low of $33.87 and a high of
$145.29.
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2008
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2007
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2006
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Average
NYMEX settlement price for WTI
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Average
posted price for:
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Utah
40 degree API black wax (light) crude oil
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California
13 degree API heavy crude oil
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Average
crude price differential between WTI and:
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Utah
light 40 degree API black wax (light) crude oil
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California
13 degree API heavy crude oil
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The above
posting prices and differentials do not necessarily reflect the amounts paid or
received by us due to the contracts discussed below. In California the
differential on December 31, 2008 was $14.05 and ranged from a low of $12.31 to
a high of $14.96 per barrel during the year. On December 31, 2008 the
differential was $16.25 and ranged from a low of $13.75 to a high of $16.25 per
barrel during the year.
Oil Contracts.
We market our crude oil production to competing buyers which may be
independent or major oil refiners or third party marketers.
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 crude oil sales
contract with Big West of California (BWOC), 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.
In
December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and
its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter
11 of the United States Bankruptcy Code. Also in December 2008, BWOC
informed the Company that it was unable to receive the Company’s
production. We have entered into various short-term agreements with
other companies to sell our California oil production. Pricing and
volumes under these agreements vary with prices ranging from just above the
posted price for San Joaquin heavy oil to the posted price less a
discount. Beginning January 2009, our California crude oil daily
production was, on average, near levels achieved prior to BWOC’s Chapter 11
filing. BWOC is evaluating several options, including a sale of the
Bakersfield, California refinery. We recorded $38.5 million of bad
debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million
due from BWOC, $12.4 million represents December crude oil sales by the Company
and represents an administrative claim under the bankruptcy proceedings and
$26.1 million represents November crude oil sales which would have the same
priority as other general unsecured claims. BWOC will also be liable
to us for damages under this contract for any amounts received by us under our
short-term contracts which are less than what we would have otherwise received
from BWOC had they been able to accept our production. We have
guarantees from Big West Oil and from Flying J, Inc. in the amount of $75
million each, in the event that our claim is not fully collectible from BWOC.
While we believe that we may recover some or all of the amounts due from BWOC,
the data received from the bankruptcy proceedings to date has not provided us
with adequate data from which to make a conclusion that any amounts will be
collected nor as to whether BWOC will assume or reject our
contract.
Utah - On
February 27, 2007, we entered into a multi-staged crude oil sales contract
through June 30, 2013 with a refiner for the purchase of our Uinta light crude
oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1,
2007. After partial completion of its refinery expansion in Salt Lake City in
March 2008, the refiner increased its total purchase volumes to 5,000
Bbl/D. Pricing under the contract, which includes transportation and
gravity adjustments, is at a fixed percentage of WTI, and ranges between $10 and
$15 at WTI prices between $40 and $60. While the contractual
differentials under this contract may be less favorable at times than the posted
differential, demand for the Company’s 40 degree black wax (light) crude oil can
vary seasonally and this contract provides a stable outlet for the Company’s
crude oil.
Natural Gas
Marketing. We market our produced natural gas from Colorado, Utah and
Texas. 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 Rocky Mountain
natural gas production is tied to the Panhandle Eastern Pipeline (PEPL) index
and the remaining volume to the Colorado Interstate Gas (CIG)
Index. E. Texas gas is priced using a formula containing the Houston
Ship Channel, Texas Eastern-East Texas, and NGPL TX-OK indices.
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2008
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2007
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2006
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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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Rocky
Mountain Questar first-of-month indices (Uinta
sales)
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Rocky
Mountain CIG first-of-month indices (DJ, WY and Piceance
sales)
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Mid-Continent
PEPL first-of-month indices (DJ and Piceance sales)
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Texas
Eastern- East Texas
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Average
natural gas price per MMBtu differential between NYMEX HH
and:
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Texas
Eastern- East Texas
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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 narrowed,
as anticipated, upon the startup of the Rockies Express pipeline in early 2008.
However, the differential started to widen again during the second quarter of
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 gas
production. The CIG basis differential per MMBtu, based upon first-of-month
values, averaged $2.81 below HH and ranged from $0.93 to $6.62 below HH in 2008.
Although related to CIG, the actual price varies. Gas from Piceance traded
slightly below the CIG price while Uinta gas sold for approximately $0.15 below
CIG pricing. DJ gas is priced using one of two indices. During 2008,
approximately two-thirds of our volumes from our DJ natural gas properties was
tied to the PEPL index for pricing and the remaining volumes to CIG
pricing. Beginning in 2009, we have increased firm transportation on
the Cheyenne Plains Pipeline which brings our PEPL priced gas to about
three-quarters of our production. For that portion of the production
with firm transportation on either the Cheyenne Plains Pipeline or the KMIGT
pipeline, pricing is based upon the PEPL index which averaged approximately
$1.96 below the HH index before the cost of transportation is considered. The
remainder of DJ gas is sold slightly above the CIG index price. For E. Texas,
the Texas Eastern - East Texas index averaged $0.58 below HH and ranged from
$0.34 to $0.94 below HH in 2008.
We have
physical access to interstate gas pipelines to move gas to or from market. To
assure delivery of gas, we have entered into long-term gas transportation
contracts as follows:
Firm
Transportation Summary.
Pipeline
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From
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To
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Quantity (Avg. MMBtu/D)
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Term
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December 31, 2008 demand charge per
MMBtu
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Remaining contractual obligation (in
thousands)
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12,000 |
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$ |
0.6407 |
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$ |
12,160 |
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25,000 |
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1.1153 |
(1) |
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93,288 |
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10,000 |
|
|
|
|
1.07694 |
(1) |
|
|
36,032 |
|
|
|
|
|
|
2,500 |
|
|
|
|
0.174 |
|
|
|
529 |
|
|
|
|
|
|
2,859 |
|
|
|
|
0.174 |
|
|
|
681 |
|
|
|
|
|
|
5,000 |
|
|
|
|
0.257 |
|
|
|
6,488 |
|
|
|
|
|
|
2,500 |
|
|
|
|
0.227 |
|
|
|
1,001 |
|
Cheyenne Plains Gas
Pipeline
|
|
|
|
|
12,000 |
(2) |
|
|
|
0.34 |
|
|
|
14,892 |
|
|
|
|
|
|
71,859 |
|
|
|
|
|
|
|
$ |
165,071 |
|
(1)
|
Base cost per MMBtu is a
weighted average cost.
|
(2)
|
Volume
increase to 15,000 MMBtu/D starting January 1, 2009 for remaining life of
contract.
|
Berry has
signed a binding precedent agreement with El Paso Corporation for an average of
35,000 MMBtu/D of firm transportation on the proposed Ruby Pipeline from Opal,
WY to Malin, OR. While it is not certain that this new line will be
constructed, the expectation is that the project will proceed and be in service
in 2011. As part of this agreement and in order to access the Ruby
pipeline, we also secured firm transportation from Piceance to
Opal.
Royalties.
See Item 7A Quantitative and Qualitative Disclosures about Market
Risk.
Hedging.
See Item 7A Quantitative and Qualitative Disclosures about Market Risk
and Note 18 to the financial statements.
Concentration of
Credit Risks. See Note 5 to the financial statements.
Cogeneration
Steam Supply. As of December 31, 2008, approximately 45% of our proved
reserves, or 109 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.
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, 2008 is as
follows:
Steam
generation capacity of conventional boilers
|
|
|
87,070 |
|
Steam
generation capacity of cogeneration plants
|
|
|
42,789 |
|
Additional
steam purchased under contract with a third party
|
|
|
2,100 |
|
|
|
|
131,959 |
|
The
average volume of steam injected for the years ended December 31, 2008 and 2007
was 99,908 BSPD and 87,990 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 2008,
we added additional steam capacity for our development projects at N. Midway,
primarily diatomite, and Poso Creek to achieve maximum production from these
properties. In 2009, 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 2008 to achieve our goal
of increasing heavy oil production. Approximately 75% of the volume of natural
gas purchased to generate steam and electricity is based upon California
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 25% of supply volume is purchased in the Rockies 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.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Average
SoCal Border Monthly Index Price per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Rocky Mountain NWPL Monthly Index Price per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
PG&E Citygate Monthly Index Price per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior to
2005, we were a net purchaser of natural gas, and thus our net income was
negatively impacted when natural gas prices increased. In 2005, our production
and consumption became balanced due to our eastern Colorado (DJ) gas
acquisition. Subsequent to 2005, we have been a net seller of gas and benefit
operationally when gas prices increase. However, our consumption of
natural gas provides a form of natural hedge as our revenues received from
natural gas sales are partially offset by operating cost increases in California
when natural gas prices rise. The following table shows our average
2008 and estimated average 2009 amount of production in excess of consumption
and hedged volumes (in average MMBtu/D):
|
|
2008
|
|
|
Estimated
2009
|
|
Approximate
Natural gas volumes produced in operations
|
|
|
|
|
|
|
|
|
Approximate
Natural gas consumed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
natural gas volumes consumed in operations
|
|
|
|
|
|
|
|
|
Less:
Our estimate of approximate natural gas volumes consumed to produce
electricity (2)
|
|
|
|
|
|
|
|
|
Total
approximate natural gas volumes consumed to produce
steam
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas volumes hedged
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
of natural gas volumes produced in excess of volumes consumed to produce
steam and volumes hedged
|
|
|
|
|
|
|
|
|
(1)
|
In 2009, 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 the historical allocation of fuel costs to
electricity.
|
Generation.
The total annual average electrical generation of our three cogeneration
facilities is approximately 83 MW, of which we consume approximately 8 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 the way SRAC
energy prices will be determined for existing and new Standard Offer (SO)
contracts and revises the capacity prices paid under current SO1 contracts. At
this time, there is no certainty as to the final formula of the SRAC Decision
nor the effective date of the SRAC Decision nor whether its terms will be
applied retroactively and if so, for what period.
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, as
they did in the SRAC decision. 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. However, given the
proceedings described above on the SRAC Decision, it is possible that some
resolution of this element of retroactivity may be resolved concurrently,
although there is no pending ruling. Our SO2 contract for the
Placerita Unit 1 Facility is scheduled to terminate on March 31, 2009 and we are
negotiating an interim contract that will become effective on April 1,
2009. The payment provisions of this interim contract are expected to
be similar to the payment provisions ordered in the SRAC
Decision. The Company intends to enter into new standard contracts
with Edison and PG&E for all three facilities as soon as the ongoing
challenges are resolved and the CPUC has approved the terms of the new standard
contracts.
Based on
the current pricing mechanism for our electricity under the contracts, we expect
that our electricity revenues will be in the $40 million to $60 million range
for 2009.
At the
time of the California energy crisis in 2000 and 2001, we had two electricity
sales agreements with Edison and two with PG&E. Under these contracts, we
were paid under an SRAC formula that priced gas off of Topock. On March 27,
2001, the CPUC issued a decision making certain changes in the SRAC formula
applicable at that time, the most significant of which was changing the pricing
point to Malin, which resulted in a significant reduction in the price we were
to be paid by Edison and PG&E. We thereafter entered into a settlement
agreement with Edison by which Edison nevertheless agreed to pay using Topock
from March 27th forward. The CPUC approved the settlement. However, 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 were identified as an affected
QF by PG&E but not by Edison. The ALJ also invited interested
parties to propose solutions to the pending remand dispute. As no resolution was
proposed, on January 26, 2009, the ALJ issued a ruling in this matter in which
he proposed a settlement in lieu of continued litigation over this
issue. A briefing schedule has been established as to his proposed
settlement and out of that briefing will come some determination of whether
litigation will continue.
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
|
|
|
|
|
|
|
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|
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, 2008, we
had 303 full-time employees, up from 263 full-time employees on December 31,
2007.
Capital
Expenditures Summary (Excluding Acquisitions).
The
following is a summary of the developmental capital expenditures incurred during
2008 and 2007 and budgeted capital expenditures for 2009 (in
thousands):
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Budgeted)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S.
Midway Asset Team
|
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|
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|
|
Facilities
- cogeneration
|
|
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|
Facilities
- cogeneration
|
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|
|
(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.
|
Production. The following table sets
forth certain information regarding production for the years ended December 31,
as indicated:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Net
annual production: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
equivalent barrels (MBOE) (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) before hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) after hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(per Mcf) before hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(per Mcf) after hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
operating cost - oil and gas production (per BOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008,
our properties accounted for the following developed and undeveloped
acres:
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,322 |
|
|
|
5,322 |
|
|
|
653 |
|
|
|
653 |
|
|
|
5,975 |
|
|
|
5,975 |
|
|
|
|
89,110 |
|
|
|
70,575 |
|
|
|
105,714 |
|
|
|
59,691 |
|
|
|
194,824 |
|
|
|
130,266 |
|
|
|
|
- |
|
|
|
- |
|
|
|
62,810 |
|
|
|
61,856 |
|
|
|
62,810 |
|
|
|
61,856 |
|
|
|
|
4,794 |
|
|
|
4,523 |
|
|
|
- |
|
|
|
- |
|
|
|
4,794 |
|
|
|
4,523 |
|
|
|
|
39,280 |
|
|
|
36,635 |
|
|
|
183,176 |
|
|
|
77,779 |
|
|
|
222,456 |
|
|
|
114,414 |
|
|
|
|
3,520 |
|
|
|
539 |
|
|
|
1,746 |
|
|
|
276 |
|
|
|
5,266 |
|
|
|
815 |
|
|
|
|
40 |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
40 |
|
|
|
3 |
|
|
|
|
142,066 |
|
|
|
117,597 |
|
|
|
354,099 |
|
|
|
200,255 |
|
|
|
496,165 |
|
|
|
317,852 |
|
(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 Ute Tribe participates.
|
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, 2008, we have 4,093 gross productive wells (3,316 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.
Drilling Activity. The following table sets
forth certain information regarding our drilling activities for the periods
indicated:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
2 |
|
|
|
5 |
|
|
|
3 |
|
|
|
7 |
|
|
|
3 |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
|
|
1 |
|
Development
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
443 |
|
|
|
374 |
|
|
|
411 |
|
|
|
314 |
|
|
|
532 |
|
|
|
356 |
|
|
|
|
6 |
|
|
|
5 |
|
|
|
7 |
|
|
|
5 |
|
|
|
7 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
446 |
|
|
|
376 |
|
|
|
416 |
|
|
|
317 |
|
|
|
539 |
|
|
|
359 |
|
|
|
|
6 |
|
|
|
5 |
|
|
|
7 |
|
|
|
5 |
|
|
|
12 |
|
|
|
6 |
|
(1)
|
A dry well is a well found to
be incapable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas
well.
|
|
|
2008
|
|
|
|
|
|
|
|
|
Total
productive wells drilled:
|
|
|
|
|
|
|
|
|
|
248 |
|
|
|
245 |
|
|
|
|
198 |
|
|
|
131 |
|
Dry hole,
abandonment and impairment. See Item 7 Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
Company owned
drilling rigs. During 2005 and 2006, we purchased three drilling
rigs. Owning these rigs allowed us to successfully meet a portion of
our drilling needs in Uinta and Piceance. Two of these rigs are
leased to a drilling rig operator on a short-term basis and are not currently
drilling on the Company's properties and one rig is idle. As the rig
market and our rig requirements change, we continue to evaluate the ownership of
these rigs and $4.2 million related to the disposal and impairment of certain
drilling rigs and related equipment,was recorded in 2008. See Note 13 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
20 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."
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 us, 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 the price received for our oil
and gas production. 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. 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. 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;
|
|
·
|
level
of consumer demand;
|
|
·
|
overall
domestic and global political and economic
conditions
|
|
·
|
technological
advances affecting energy consumption and
supply;
|
|
·
|
domestic
and foreign governmental regulations and
taxation;
|
|
·
|
the
impact of energy conservation
efforts;
|
|
·
|
the
capacity, cost and availability of oil and natural gas pipelines and other
transportation facilities,
|
|
·
|
the
price and availability of alternative
fuels.
|
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:
|
·
|
reduce
the amount of cash flow available to make capital expenditures or make
acquisitions;
|
|
·
|
reduce
the number of our drilling
locations;
|
|
·
|
increase
the likelihood of refinery default;
|
|
·
|
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
|
|
·
|
limit
our ability to borrow money or raise additional
capital.
|
Our level of
indebtedness may limit our financial flexibility. As of December 31, 2008
our total debt was $1.16 billion which is comprised of $200 million outstanding
on our 8.25% senior subordinated notes due 2016 and $957 million drawn under our
credit facilities.
Our level
of indebtedness affects our operations in several ways, including the
following:
|
•
|
a
portion of our cash flows from operating activities must be used to
service our indebtedness and is not available for other
purposes;
|
|
•
|
we
may be at a competitive disadvantage as compared to similar companies that
have less debt;
|
|
•
|
the
covenants contained in the agreements governing our outstanding
indebtedness and future indebtedness may limit our ability to borrow
additional funds, pay dividends and make certain investments and may also
affect our flexibility in planning for, and reacting to, changes in the
economy and in our industry;
|
|
•
|
additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes may have higher costs
and more restrictive covenants; and
|
|
•
|
changes
in the credit ratings of our debt may negatively affect the cost, terms,
conditions and availability of future financing, and lower ratings may
increase the interest rate and fees we pay on our revolving bank credit
facility.
|
A higher
level of indebtedness increases the risk that we may default on our obligations.
Our ability to meet our debt obligations and to reduce our level of indebtedness
depends on our future performance. General economic conditions, oil and natural
gas prices and financial, business and other factors affect our operations and
our future performance. Many of these factors are beyond our control. We may not
be able to generate sufficient cash flow to pay the interest on our debt, and
future working capital, borrowings or equity financing may not be available to
pay or refinance such debt. Factors that will affect our ability to raise cash
through an offering of our capital stock or a refinancing of our debt include
financial market conditions, the value of our assets and our performance at the
time we need capital.
The borrowing
base under our credit facility may be insufficient to fund our outstanding
debt. The amount we are able to borrow under our senior
secured credit facility is determined based on the value of our proved oil and
gas reserves and is based on oil and natural gas price assumptions which vary by
individual lender. Our borrowing base is subject to redetermination
twice each year in April and October with the option for one additional
redetermination each year. Should there be a deficiency in the amount
of our borrowing base in comparison to our outstanding debt under the facility
we would be required to repay any such deficiency
in two equal installments, 90 and 180 days after the
redetermination.
Our heavy crude
in California may be less
economic than lighter
crude oil and natural gas. As of December 31, 2008,
approximately 45% of our proved reserves, or 109 million barrels, consisted of
heavy oil. Light crude oil represented 6% and natural gas represented 49% 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. Additionally, most of our crude oil in California is produced
using the enhanced oil recovery process of steam injection. This
process is generally more costly than primary and secondary recovery
methods.
Purchasers of our crude oil and natural gas may become
insolvent. We have significant
concentrations of credit risk with the purchasers of our crude oil and natural
gas. We have had a long-term contract to sell all of our heavy crude
oil in California for approximately $8.10 below WTI, the U.S. benchmark crude
oil pricing, with Big West of California (BWOC). On December 22,
2008, Flying J, Inc. and its wholly owned subsidiary Big West Oil and
its wholly owned subsidiary BWOC each filed for bankruptcy protection under
Chapter 11 of the United States Bankruptcy Code. Also in December
2008, BWOC informed the Company that it was unable to receive the Company’s
production. We have entered into various currently short-term
agreements with other companies to sell our California oil
production. Pricing and volumes under these agreements vary with
prices ranging from just above the posted price for San Joaquin heavy oil to the
posted price less a discount. BWOC is evaluating several options, including a
sale of the Bakersfield, California refinery. We recorded $38.5 million of bad
debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million
due from BWOC, $12.4 million represents December crude oil sales by the Company
and represents an administrative claim under the bankruptcy proceedings and
$26.1 million represents November crude oil sales which would have the same
priority as other general unsecured claims. BWOC will also be liable
to us for damages under this contract. While we also have guarantees
from Big West Oil and from Flying J, Inc. in the amount of $75 million each, the
information received from the bankruptcy proceedings to date has not provided us
with adequate data from which to make a conclusion that any amounts will be
collected nor whether BWOC will assume or reject our
agreement.
Additionally,
all of our crude oil in Utah is sold under a long-term contract to a single
refiner. Under the standard credit terms with our refiners, we may
not know that a refiner will be unable to make payment to us until 50 days of
our production has been delivered to them. If our purchasers become
insolvent, we may not be able to collect any of the amounts owed to
us.
We may be unable
to meet our drilling obligations. We have drilling
obligations in both the Piceance assets in Colorado and our Lake Canyon asset in
Utah. In the Piceance basin, we must drill 91 additional wells by
February 2011 to avoid penalties of $0.2 million per well and loss of related
leases. In Lake Canyon, we must drill an additional 7 wells by
November 2009 to avoid the loss of related leases. Our ability to
meet these commitments depends on the capital resources available to us to fund
our drilling activities and the commodity price environment which affects the
economics of these projects.
Our financial
counterparties may be unable to satisfy their obligations. We rely on financial
institutions to fund their obligations under our senior secured credit facility
and make payments to us under our hedging agreements. If one or more
of our financial counterparties becomes insolvent, they may not be able to meet
their commitment to fund future borrowings under our credit facility which would
reduce our liquidity. Additionally, at current commodity prices, a
significant portion of our cash flow over the next two years will come from
payments from our counterparties on our commodity hedging
contracts. If our counterparties are not able to make these payments,
our cash flow will be reduced.
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 may not be
able to 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.
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 five years are
uncertain and there is no assurance that we will be able to consistently meet
the minimum contractual requirement. After partial completion of its refinery
expansion in Salt Lake City in March 2008, the refiner increased its total
purchased volumes to 5,000 Bbl/D. During the term of the contract, the minimum
number of delivered barrels (“base daily volume”) is 5,000 Bbl/D. In the event
that we cannot produce the necessary volume, we may need to purchase crude to
meet our contract requirements. Current gross oil production from our Uinta
properties is approximately 3,800 Bbl/D.
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 32% 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. All of our power contracts 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. All of our electricity sales
contracts in place with the utilities are currently scheduled to terminate in
2009 and while we intend to enter into future contacts with the utilities all of
the terms of such contracts are not known. Additionally legal and
regulatory decisions (especially related to the pricing of electricity under the
contracts such as the SRAC Decision and the pending issues as to effective dates
on retroactivity), can by reducing our electricity revenues 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
15,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern
County, CA, which accounts for approximately one-third 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.
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:
|
·
|
quality
and quantity of available data;
|
|
·
|
interpretation
of that data; and
|
|
·
|
accuracy
of various mandated economic
assumptions.
|
Any
significant variance could materially affect the quantities and present value of
our reserves. In addition, we may adjust estimates of proved reserves to reflect
production history, results of development and exploration and prevailing oil
and gas prices.
In
accordance with SEC requirements, we base the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
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. While we did not have any impairment charges in
2008, it is possible that declining commodity prices could prompt an impairment
in the future. 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.
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;
|
|
·
|
unexpected
drilling conditions;
|
|
·
|
pressure
or irregularities in formations;
|
|
·
|
equipment
failures or accidents;
|
|
·
|
adverse
weather conditions;
|
|
·
|
compliance
with governmental or landowner requirements;
and
|
|
·
|
shortages
or delays in the availability of drilling rigs and the delivery of
equipment and/or services, 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 Uinta
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 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 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
greenhouse gases (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.
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.
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 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.
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.
Item 4. Submission of Matters to a Vote of Security
Holders
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, 2008) 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,
55, 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.
DAVID D. WOLF,
38, has been Executive Vice President and Chief Financial Officer since August
2008. Mr. Wolf was previously employed by JPMorgan from 1995 to 2008
where he served as a Managing Director in JPMorgan's Oil and Gas
Group.
MICHAEL DUGINSKI,
42, 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,
46, 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, a petroleum engineer,
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. He
previously held various engineering and management positions with Santa Fe
Snyder Corporation and Conoco, Inc. from 1985 to 2000.
WALTER B. AYERS,
65, 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.
SHAWN M.
CANADAY, 33, has held the position of Vice President and Controller since June
2008 and was Interim Chief Financial Officer from June 2008 until August
2008. Mr. Canaday served as Controller from February 2007 to
June 2008, 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.
GEORGE T. CRAWFORD,
48, 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,
53, 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.
KENNETH
A. OLSON, 53, has been Corporate Secretary since December 1985 and was
Treasurer from August 1988 until December 2004.
STEVEN B. WILSON,
45, 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 $0.50 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 8 to the
financial statements.
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
2008 and 2007 are shown below:
|
|
2008
|
|
|
2007
|
|
|
|
Price Range
|
|
|
Dividends
|
|
|
Price Range
|
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Per Share
|
|
|
High
|
|
|
Low
|
|
|
Per Share
|
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|
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|
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|
|
|
|
|
February 2, 2009
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
Berry’s
Common Stock closing price per share as reported on NYSE Composite
Transaction Reporting System
|
|
$ |
7.36 |
|
|
$ |
7.56 |
|
|
$ |
44.45 |
|
The
number of holders of record of our Common Stock was 544 as of February 2, 2009.
There was one Class B Shareholder of record as of February 2, 2009.
Dividends.
Our regular annual dividend is currently $0.30 per share, payable
quarterly in March, June, September and December. We increased our regular
quarterly dividend by 15%, from $0.065 to $0.075 per share beginning with the
September 2006 dividend.
Since our
formation in 1985 through December 31, 2008, we have paid dividends on our
Common Stock for 77 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.
Plan category
|
|
Number
of securities to be issued upon exercise of outstanding
options, warrants and
rights
|
|
|
Weighted
average exercise price of outstanding options, warrants and rights
|
|
|
Number
of securities remaining available for future issuance
|
|
Equity
compensation plans approved by security holders
|
|
|
3,389,097 |
|
|
$ |
25.16 |
|
|
|
412,025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2006 we repurchased 818,000 shares in
the open market for approximately $25 million. Our repurchase plan expired in
2006 and no shares were repurchased in 2007 or 2008.
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, 2003 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.
*$100
invested on 12/31/03 in stock & index-including reinvestment of
dividends.
Fiscal
year ending December 31.
Copyright
ã 2009 S&P, a
division of the McGraw-Hill Companies Inc. All rights reserved.
|
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12/03
|
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12/04
|
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12/05
|
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12/06
|
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12/07
|
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12/08
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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, 2008 were derived from the audited
financial statements and the accompanying notes to those financial statements
(in thousands, except per share, per BOE and % data).
|
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2008
|
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2007
|
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2006
|
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2005
|
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2004
|
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Audited
Financial Information
|
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Gain
(loss) on sale of assets (1)
|
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Operating
costs - oil and gas production
|
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Operating
costs - electricity generation
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General
and administrative expenses (G&A)
|
|
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Depreciation,
depletion & amortization (DD&A)
|
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Basic
net income per share
|
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Diluted
net income per share
|
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Weighted
average number of shares outstanding (basic)
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|
Weighted
average number of shares outstanding (diluted)
|
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|
Working
capital (deficit)
|
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Cash
flow from operations
|
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|
Exploration
and development of oil and gas properties
|
|
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|
Property/facility
acquisitions (1)
|
|
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|
Additions
to vehicles, drilling rigs and other fixed assets
|
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Oil
and gas producing operations (per BOE):
|
|
|
|
|
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|
Average
sales price before hedging
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Average
sales price after hedging
|
|
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|
|
Average
operating costs - oil and gas production
|
|
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|
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|
|
DD&A
- oil and gas production
|
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|
Total
proved reserves (BOE)
|
|
|
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|
Year
end average BOE price for PV10 purposes
|
|
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Return
on average shareholders' equity
|
|
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Return
on average capital employed
|
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|
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(1)
|
See Note 6 to the
financial statements
|
(2)
|
See
Supplemental Information About Oil & Gas Producing Activities
(unaudited).
|
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
|
|
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
|
·
|
Calibrating
our cost structure to the current commodity price
environment
|
|
·
|
Acquiring
additional assets with significant growth
potential
|
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
Notable
Items in 2008.
|
·
|
Achieved
record production which averaged 31,968 BOE/D, up 19% from
2007
|
|
·
|
Added
88 million BOE of proved reserves ending 2008 at 245.9 million
BOE
|
|
·
|
Recorded cash
from operating activities of $410 million and funded $398 million of
capital expenditures
|
|
·
|
Closed
on our E. Texas acquisition on July 15, 2008, adding approximately 32 MMcf
to daily production
|
|
·
|
Placed
5,000 Bbl/d of $100 WTI floor collars for 2009 and 2010 to protect cash
flow
|
|
·
|
Achieved
net income of $134 million
|
|
·
|
Drilled
85 wells in the diatomite and increased average production to 1,840 Bbl/D,
up 86% from 2007
|
|
·
|
Accomplished
an 8 day drilling record on a Piceance mesa location and reduced average
drilling days to 11
|
|
·
|
Drilled
72 gross (44 net) Piceance operated wells which increased net production
to average 21 MMcf/D
|
|
·
|
Increased
the borrowing base on our senior secured credit facility from $550 million
to $1.25 billion with an increase in bank commitments to $1.21
billion
|
|
·
|
Completed
relocation of our corporate headquarters from Bakersfield, California to
Denver, Colorado
|
|
·
|
David
D. Wolf joined the Company as Executive Vice President and Chief Financial
Officer
|
|
·
|
Temporarily
shut in 12,000 Bbl/D in December due to the bankruptcy of Big West Oil in
California and recorded an allowance for doubtful accounts of $38.5
million for November and December California crude oil
sales
|
|
·
|
Resumed
California operations in late December, marketing California production to
multiple refiners
|
|
·
|
Quickly
responded to declining commodity price environment reducing rig count from
twelve to two during the fourth quarter of 2008, and reducing our 2009
capital budget to $100 million
|
Notable
Items and Expectations for 2009.
|
·
|
Expecting
2009 capital expenditures of $100 million to be fully funded from
operating cash flow
|
|
·
|
Anticipating
average production of 32,000
BOE/D
|
|
·
|
Entered
into short-term agreements with multiple refiners to sell all of our
California crude oil
|
|
·
|
Targeting
a 20% reduction in operating, capital and general and
administrative costs for 2009
|
|
·
|
Amended
the terms of our senior secured credit facility, increasing our maximum
EBITDAX to debt ratio
|
Overview of the
Fourth Quarter of 2008. We achieved average production of
35,583 BOE/D in the fourth quarter of 2008, up 1% from an average of 35,149
BOE/D in the third quarter of 2008. We had a net loss of $12.0 million, or $0.27
per diluted share. Net cash from operations was $78 million and
capital expenditures during the quarter totaled $92 million. The net loss
resulted primarily from a write-off of $38.5 million (pre-tax) of accounts
receivable due from BWOC as a result of their bankruptcy filing. This
write-off included November and 22 days of December production from the majority
of our California properties. We have since contracted with other
parties to receive our California production. Other notable charges
taken in the fourth quarter of the year included pre-tax rig termination fees of
$2.3 million, $4.2 million related to the disposal and impairment of certain
drilling rigs and related equipment, and dry hole and impairment expenses of
$0.7 million.
View to 2009.
Our challenge for 2009 is to calibrate our cost structure to levels that
are consistent with those experienced when commodity prices were at $30 Bbl to
$50 Bbl. Each of our asset teams is actively pursuing cost reductions
and we are targeting a 20% reduction in our non-steam operating costs and our
capital costs per well when compared to 2008 levels. Our $100 million
capital program is designed to fund high return projects in California and E.
Texas and generate excess cash flow.
Capital
expenditures. Our capital expenditures for 2008 totaled $398 million for
development and were fully funded from our $410 million operating cash
flow. We also funded $668 million in acquisitions through additional
borrowing on our senior secured credit facility and capitalized $23 million of
interest. This compares to our total capital expenditures in 2007 of $341
million, which consisted of $56 million of acquisitions and $285 million in
development. We capitalized $18 million of interest in2007.
Excluding
the acquisition of new properties, in 2009 we have a developmental capital
program of approximately $100 million which we expect to fund fully out of
operating cash flow. As we have operational control of substantially all of our
assets and we have limited drilling commitments, we have the ability to revise
our capital program based on changes in commodity prices. We expect
our capital program will allow us to hold production flat with annualized 2008
levels of approximately 32,000 BOE/D.
Development, Exploitation and
Exploration Activity. We drilled 452 gross (381 net) wells during 2008,
realizing a gross success rate of 99 percent. As of December 31, 2008, we have
two rigs drilling on our properties under long-term contracts.
Drilling
Activity. The following table sets
forth certain information regarding drilling activities for the year ended
December 31, 2008:
(1)
|
Includes 6 gross wells (5 net
wells) that were dry holes in
2008.
|
Net Oil and Gas Producing
Properties at December 31,
2008.
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)
|
|
|
|
|
98 |
|
|
|
2,127 |
|
|
|
52.7 |
|
|
|
42.8 |
|
|
|
17
|
% |
|
|
9.9 |
|
|
|
4
|
% |
|
|
1,700 |
|
|
|
|
100 |
|
|
|
4,508 |
|
|
|
50.0 |
|
|
|
29.8 |
|
|
|
12 |
|
|
|
20.2 |
|
|
|
8 |
|
|
|
13,000 |
|
|
|
|
41 |
|
|
|
3,157 |
|
|
|
41.8 |
|
|
|
13.2 |
|
|
|
5 |
|
|
|
28.6 |
|
|
|
12 |
|
|
|
9,300 |
|
|
|
|
100 |
|
|
|
1,597 |
|
|
|
38.9 |
|
|
|
16.2 |
|
|
|
7 |
|
|
|
22.7 |
|
|
|
9 |
|
|
|
1,500 |
|
|
|
|
98 |
|
|
|
36,635 |
|
|
|
23.3 |
|
|
|
10.9 |
|
|
|
5 |
|
|
|
12.4 |
|
|
|
5 |
|
|
|
6,000 |
|
|
|
|
51 |
|
|
|
67,418 |
|
|
|
21.5 |
|
|
|
13.2 |
|
|
|
5 |
|
|
|
8.3 |
|
|
|
3 |
|
|
|
2,600 |
|
|
|
|
100 |
|
|
|
1,598 |
|
|
|
17.7 |
|
|
|
8.7 |
|
|
|
4 |
|
|
|
9.0 |
|
|
|
4 |
|
|
|
1,200 |
|
|
|
|
|
|
|
|
117,040 |
|
|
|
245.9 |
|
|
|
134.8 |
|
|
|
55
|
% |
|
|
111.1 |
|
|
|
45
|
% |
|
|
|
|
Properties
We have
seven 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, DJ and E. Texas. Our S.
Midway, S. Cal and DJ asset teams are primarily focused on production and
generate significant cash flow to fund the drilling inventory in our N. Midway,
Piceance, E. Texas and Uinta projects.
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.
2008 -
Capital was focused on adding 20 horizontal wells below existing horizontal
wells and further development at Ethel D including drilling 32 producers
and the initiation of a pilot steam flood.
2009 -
Efforts will be focused on drilling 10 additional, deeper horizontal wells,
evaluation of the Ethel D steam flood pilot and lowering operating costs
through optimization of well servicing and steam placement.
N. Midway
- We began the full scale development of our N. Midway diatomite asset in late
2006 and have drilled 190 wells on this property. The delineation drilling in
2008 increased our original oil in place estimates by 35% to 330 million
barrels. We are targeting ultimate recovery between 23% and 40% similar to other
diatomite developments in California.
2008 -
Capital was focused on drilling approximately 85 diatomite wells, completing
major infrastructure upgrades that will support future development, increasing
steam injection and further refining our thermal recovery
techniques. Production from our diatomite asset increased by 86% in
2008, averaging approximately 1,840 Bbl/D.
2009
- We plan to invest $37 million to drill an additional 44 diatomite wells and
install additional steam generation facilities. Additionally, we are seeking
operating and capital cost reductions through initiatives such as steam
management to improve our steam oil ratio and improved project management to
reduce overall well costs. Production is expected to increase over 50% averaging
approximately 3,000 Bbl/D.
S. Cal -
We acquired the Poso Creek properties in the San Joaquin Valley in early
2003 for approximately $3 million and have proceeded with a successful thermal
EOR redevelopment. In the Placerita field in Los Angeles County, 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.
2008 –
Capital was directed at a 28 well program at Poso Creek and further expansion of
the steam flood including the installation of a fourth steam generator and
expansion of our water processing facilities. Average production
increased from 1,950 Bbl/D in 2007 to 3,100 Bbl/D in
2008. A fifth steam generator was purchased and installed
allowing further steam flood expansion into 2009.
2009 -
Production at Poso Creek will increase as the steam flood patterns we developed
in 2008 continue to respond. We expect to focus our efforts in 2009 on improving
steam-oil ratios and lowering operating expenses.
Piceance -
In 2006, we made two separate acquisitions in Piceance 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 900 drilling locations which will
allow us to add significant proved reserves over the next several
years.
2008 -
Production averaged 20,750 Mcf/D in 2008 in comparison to 10,200 Mcf/D in 2007.
We operated a four rig drilling program for most of the year and drilled 54
gross (27 net) wells at Garden Gulch and 18 gross (17 net) wells at North
Parachute. Significant progress was made during 2008 in reducing the
days required to drill wells. During the last three months of drilling activity,
the number of drilling days on our mesa wells averaged 10 days on Garden Gulch
and 11 days in North Parachute, a 40% reduction in drilling times compared to
early 2008.
2009 –
Our focus in 2009 will be on reducing our drilling and completion cost structure
along with evaluating reservoir parameters and completion practices to improve
ultimate recoveries. We believe our focus on cost reduction and
improvement of ultimate recovery will allow for attractive returns to continue
the development of our over 900 well drilling inventory. We
have an inventory of approximately 40 completions and recompletions that we will
be evaluating for supplemental capital should commodity prices
warrant.
Uinta
- The
Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of
approximately 30,000 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 also hold a
163,000 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.
2008 –
Production averaged 6,142 BOE/D in 2008 compared to 5,743 BOE/D in
2007. We drilled 51 gross (50 net) wells in the Uinta project which
included 39 wells at Brundage Canyon, 8 wells in the Ashley Forest and
4 Green River wells at Lake Canyon. The Ashley Forest
results continue to be encouraging with the 2008 wells achieving recoveries
similar to Brundage Canyon. Three of our Lake Canyon wells
are waiting on completion which is scheduled for mid-2009.
2009 – In
2009 capital is primarily directed at facility upgrades, pursuing the remaining
three Lake Canyon completions and the completion of the Ashley Forest
Environmental Impact Study (EIS) which we anticipate in the first half of
2009.
DJ - In
2005, we made three acquisitions for approximately $111 million establishing a
core area in the Niobrara gas producing assets in eastern Colorado, western
Kansas, and southwestern Nebraska. In 2007, we divested of our Kansas
and Nebraska positions and focused our development in Yuma County where we
have approximately 110,000 net acres and over 1,100 producing
wells. Our Yuma County Niobrara projects provide sustainable and
steady cash flow resulting from low capital development costs, modest production
declines and long-life reserves.
2008 –
Production averaged 19,700 net Mcf/D in 2008 compared to 18,700 Mcf/D in
2007. In 2008 we drilled 107 Niobrara development wells (71 net) in
Yuma County with a 100% success rate and expanded our gathering and
compression infrastructure to facilitate our drilling program. Early
in the year we acquired an additional 75 square miles of 3-D seismic
data. Interpretation of the 2008 seismic program and re-evaluation of
previous year’s acquisitions continue to replenish our low risk repeatable
drilling inventory and provide additions to our proved reserves.
2009 –
The primary focus in 2009 will be to maximize production from our existing
wells, increase operational efficiencies, and reduce lease operating
expense. Our capital program will be directed toward lease
acquisition and facility infrastructure upgrades.
E. Texas –
On July 15, 2008, we
acquired a 100% working interest in natural gas producing properties on
4,500 net acres in Limestone and Harrison counties in East Texas for
approximately $650 million. In Limestone County, we are targeting
seven productive sands including the Cotton Valley and Bossier sands at depths
between 8,000 and 13,000 feet. In Harrison County, we are targeting five
productive sands with average depths between 6,500 and 13,000 feet and have
upside potential in the Haynesville and Bossier Shales. We assumed operations
from the seller on November 1, 2008.
2008 - We
executed a five rig program in 2008 and 19 wells have been drilled and put on
production since closing (4 in Harrison and 15 in Limestone). We also
drilled three wells which are awaiting completion during 2009.
2009 - We
plan to run one rig during 2009 and will drill approximately five vertical wells
in the Oakes field during the year and plan to begin drilling
horizontal wells in the Haynesville Shale Darco field in the third quarter of
2009.
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 87% of
our revenues are generated through the sale of oil and natural gas
production under either negotiated contracts or spot gas purchase
contracts at market prices. Approximately 8% of our revenues are derived
from electricity sales from cogeneration facilities which supply
approximately 32% of our steam requirement for use in our California
thermal heavy oil operations. We have invested in these
facilities for the purpose of lowering our steam costs which are
significant in the production of heavy crude oil. The remaining 5% of our
revenues are primarily derived from gas marketing sales which represent
excess capacity on the Rockies Express pipeline which we used to market
natural gas for our working interest partners.
Sales
of oil and gas were up 49% in 2008 compared to 2007 and up 62% from 2006.
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. Oil and
natural gas prices contributed roughly 73% of the revenue increase and the
increase in production volumes contributed the other 27%. Approximately
64% of our oil and gas sales volumes in 2008 were crude oil, with 82% of
the crude oil being heavy oil produced in California which was sold under
a contract based on the higher of WTI minus a fixed differential or the
average posted price plus a
premium.
|
The
following results are in millions (except per share data) for the years ended
December 31:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
sales of oil and gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on sale of assets (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues and other income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share (diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes
2007 sale of Montalvo, California
assets
|
The
following results are in millions (except per share data) for the three months
ended:
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
sales of oil and gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
(loss) on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues and other income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss) per share (diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Contracts. See Item 1 Business.
Hedging.
See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note
18 to the financial statements.
Operating
data. The following table is for the years ended December
31:
|
|
2008
|
|
|
%
|
|
|
2007
|
|
|
%
|
|
|
2006
|
|
|
%
|
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,633 |
|
|
|
52 |
|
|
|
16,170 |
|
|
|
60 |
|
|
|
15,972 |
|
|
|
63 |
|
Light
Oil Production (Bbl/D)
|
|
|
3,697 |
|
|
|
12 |
|
|
|
3,583 |
|
|
|
13 |
|
|
|
3,707 |
|
|
|
15 |
|
Total
Oil Production (Bbl/D)
|
|
|
20,330 |
|
|
|
64 |
|
|
|
19,753 |
|
|
|
73 |
|
|
|
19,679 |
|
|
|
78 |
|
Natural
Gas Production (Mcf/D)
|
|
|
69,834 |
|
|
|
36 |
|
|
|
42,895 |
|
|
|
27 |
|
|
|
34,317 |
|
|
|
22 |
|
|
|
|
31,968 |
|
|
|
100 |
|
|
|
26,902 |
|
|
|
100 |
|
|
|
25,398 |
|
|
|
100 |
|
Percentage
increase from prior year
|
|
|
19 |
% |
|
|
|
|
|
|
6 |
% |
|
|
|
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$ |
70.22 |
|
|
|
|
|
|
$ |
49.72 |
|
|
|
|
|
|
$ |
48.38 |
|
|
|
|
|
Average
sales price after hedging
|
|
|
59.81 |
|
|
|
|
|
|
|
47.50 |
|
|
|
|
|
|
|
46.67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
99.75 |
|
|
|
|
|
|
$ |
72.41 |
|
|
|
|
|
|
$ |
66.25 |
|
|
|
|
|
Price
sensitive royalties
|
|
|
(2.95 |
) |
|
|
|
|
|
|
(5.03 |
) |
|
|
|
|
|
|
(5.13 |
) |
|
|
|
|
Gravity
differential and other
|
|
|
(11.32 |
) |
|
|
|
|
|
|
(9.53 |
) |
|
|
|
|
|
|
(8.20 |
) |
|
|
|
|
|
|
|
(16.89 |
) |
|
|
|
|
|
|
(4.61 |
) |
|
|
|
|
|
|
(2.37 |
) |
|
|
|
|
Correction
to royalties payable
|
|
|
1.42 |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
|
|
Average
oil sales price after hedging
|
|
$ |
70.01 |
|
|
|
|
|
|
$ |
53.24 |
|
|
|
|
|
|
$ |
50.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$ |
9.04 |
|
|
|
|
|
|
$ |
7.12 |
|
|
|
|
|
|
$ |
6.97 |
|
|
|
|
|
|
|
|
.45 |
|
|
|
|
|
|
|
.34 |
|
|
|
|
|
|
|
.33 |
|
|
|
|
|
|
|
|
.14 |
|
|
|
|
|
|
|
.74 |
|
|
|
|
|
|
|
.09 |
|
|
|
|
|
Location,
quality differentials and other
|
|
|
(2.62 |
) |
|
|
|
|
|
|
(2.93 |
) |
|
|
|
|
|
|
(1.82 |
) |
|
|
|
|
Average
gas sales price after hedging
|
|
$ |
7.01 |
|
|
|
|
|
|
$ |
5.27 |
|
|
|
|
|
|
$ |
5.57 |
|
|
|
|
|
Production
increased 19% or 5,066 BOE/D for the year ended December 31, 2008 when compared
to the year ended December 31, 2007. Our E. Texas acquisition which
closed on July 15, 2008, contributed 2,384 BOE/D on an annualized
basis. Our development activities during the year resulted in
increases in the Piceance, Poso and diatomite of 1,796 BOE/D, 1,133 BOE/D and
851 BOE/D, respectively.
The
following table is for the three months ended:
|
|
December 31, 2008
|
|
|
%
|
|
|
December 31, 2007
|
|
|
%
|
|
|
September 30, 2008
|
|
|
%
|
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
15,999 |
|
|
|
45 |
|
|
|
16,595 |
|
|
|
59 |
|
|
|
17,264 |
|
|
|
49 |
|
Light
Oil Production (Bbl/D)
|
|
|
3,659 |
|
|
|
10 |
|
|
|
3,395 |
|
|
|
12 |
|
|
|
3,898 |
|
|
|
11 |
|
Total
Oil Production (Bbl/D)
|
|
|
19,658 |
|
|
|
55 |
|
|
|
19,990 |
|
|
|
71 |
|
|
|
21,162 |
|
|
|
60 |
|
Natural
Gas Production (Mcf/D)
|
|
|
95,548 |
|
|
|
45 |
|
|
|
48,196 |
|
|
|
29 |
|
|
|
83,928 |
|
|
|
40 |
|
|
|
|
35,583 |
|
|
|
100 |
|
|
|
28,023 |
|
|
|
100 |
|
|
|
35,150 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$ |
38.45 |
|
|
|
|
|
|
$ |
60.38 |
|
|
|
|
|
|
$ |
80.22 |
|
|
|
|
|
Average
sales price after hedging
|
|
|
42.93 |
|
|
|
|
|
|
|
52.32 |
|
|
|
|
|
|
|
64.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
59.08 |
|
|
|
|
|
|
$ |
90.50 |
|
|
|
|
|
|
$ |
118.22 |
|
|
|
|
|
Price
sensitive royalties
|
|
|
(1.69 |
) |
|
|
|
|
|
|
(6.68 |
|
|
|
|
|
|
|
(5.30 |
) |
|
|
|
|
Gravity
differential and other
|
|
|
(8.55 |
) |
|
|
|
|
|
|
(9.92 |
|
|
|
|
|
|
|
(10.80 |
) |
|
|
|
|
|
|
|
4.69 |
|
|
|
|
|
|
|
(13.57 |
) |
|
|
|
|
|
|
(26.12 |
) |
|
|
|
|
Average
oil sales price after hedging
|
|
$ |
53.53 |
|
|
|
|
|
|
$ |
60.33 |
|
|
|
|
|
|
$ |
76.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$ |
6.95 |
|
|
|
|
|
|
$ |
7.39 |
|
|
|
|
|
|
$ |
10.24 |
|
|
|
|
|
|
|
|
.35 |
|
|
|
|
|
|
|
.35 |
|
|
|
|
|
|
|
.52 |
|
|
|
|
|
|
|
|
.70 |
|
|
|
|
|
|
|
.91 |
|
|
|
|
|
|
|
.15 |
|
|
|
|
|
Location,
quality differentials and other
|
|
|
(3.02 |
) |
|
|
|
|
|
|
(3.21 |
) |
|
|
|
|
|
|
(2.81 |
) |
|
|
|
|
Average
gas sales price after hedging
|
|
$ |
4.98 |
|
|
|
|
|
|
$ |
5.44 |
|
|
|
|
|
|
$ |
8.10 |
|
|
|
|
|
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 up in the year
ended 2008 from the year ended 2007 due to 18% higher electricity prices and 27%
higher natural gas prices, respectively. 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. We
purchased approximately 27 MMBtu/D as fuel for use in our cogeneration
facilities in both the year ended December 31, 2008 and the year ended December
31, 2007. In 2007 and 2008, 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 and 2008 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 is linked to Southern California Border prices, the fuel
we purchased at lower Rocky Mountain prices was the primary contributor to
the increase in our electricity margins in 2007 and 2008 compared to
2006.
On
September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes the
way SRAC energy prices will be determined for existing and new SO contracts and
revises the capacity prices paid under current SO1 contracts. The effective date
of the SRAC Decision has not been determined nor has every element of the
formula under the SRAC Decision been finalized. As such it is not
possible to predict the economic impact on us of the SRAC Decision nor whether
its terms will be applied retroactively and if so, for what period.
The
following table is for the years ended December 31:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease
to total oil and gas operating expenses per barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
power produced - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
power sold - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price/MWh (no hedging was in place)
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties.
A price-sensitive royalty burdens certain of our S. Midway properties which
produced approximately 2,300 BOE/D in 2008. This royalty was 75% of the amount
of the heavy oil posted price above a base price which was $16.11 in 2008. This
royalty rate was reduced to 53% effective January 1, 2008 as long as we maintain
a minimum steam injection level. We met the steam injection level in
2008 and expect to meet the requirement going forward. This base
price escalates at 2% annually, thus the threshold price is $16.43 per barrel in
2009. Liabilities payable for these royalties were $22 million, $36
million and $36 million in the years ended December 31, 2008, 2007 and 2006,
respectively.
In the
first quarter of 2008, we determined there was an error in computing royalties
payable in prior years, accumulating to $10.5 million as of December 31, 2007.
We concluded the error was not material to any individual prior interim or
annual period (or to the projected earnings for 2008) and, therefore, the error
was corrected during the first quarter of 2008, with the effect of increasing
our sales of oil and gas by $10.5 million and reducing our royalties
payable.
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)
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Operating
costs - oil and gas production
|
|
$ |
17.10 |
|
|
$ |
14.38 |
|
|
|
19
|
% |
|
$ |
200,098 |
|
|
$ |
141,218 |
|
|
|
42
|
% |
|
|
|
2.56 |
|
|
|
1.75 |
|
|
|
46
|
% |
|
|
29,898 |
|
|
|
17,215 |
|
|
|
74
|
% |
DD&A
- oil and gas production
|
|
|
11.81 |
|
|
|
9.54 |
|
|
|
24
|
% |
|
|
138,237 |
|
|
|
93,691 |
|
|
|
48
|
% |
|
|
|
4.73 |
|
|
|
4.09 |
|
|
|
16
|
% |
|
|
55,353 |
|
|
|
40,210 |
|
|
|
38
|
% |
|
|
|
2.24 |
|
|
|
1.76 |
|
|
|
27
|
% |
|
|
26,209 |
|
|
|
17,287 |
|
|
|
52
|
% |
|
|
$ |
38.44 |
|
|
$ |
31.52 |
|
|
|
22
|
% |
|
$ |
449,795 |
|
|
$ |
309,621 |
|
|
|
45
|
% |
Our total
operating costs, production taxes, G&A and interest expenses for 2008,
stated on a unit-of-production basis, increased 22% over 2007. The changes were
primarily related to the following items:
|
·
|
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. Of the $59 million increase in operating expense compared to 2007,
approximately $31 million was due to higher steam costs and approximately
$4 million was due to the addition of our E. Texas assets. On a
per barrel basis, E. Texas operating costs approximate $1.00/Mcf and
reduces our overall cost per barrel. The following table
presents steam information:
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Average
volume of steam injected (Bbl/D)
|
|
|
99,908 |
|
|
|
87,990 |
|
|
|
14 |
% |
Fuel
gas cost/MMBtu (including transportation)
|
|
|
7.95 |
|
|
$ |
6.08 |
|
|
|
31 |
% |
Based on
current plans, we are targeting average steam injection in 2009 of approximately
120,000 BSPD or a 20% increase compared to 2008.
|
·
|
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 2008 by 24% from
2007. 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 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 65% of our G&A is related to
compensation. The primary reason for the increase in G&A during 2008
was a 15% increase in employee headcount associated with our E. Texas
acquisition and the development of our assets. In 2008 we moved
our corporate headquarters from Bakersfield, California to Denver,
Colorado and approximately $1.7 million was related to relocation of our
employees and related expenses. Also included in G&A is $2.3 million
in rig termination penalties that we incurred during the fourth quarter of
2008 and $0.6 million for costs we incurred to evaluate the formation of a
master limited partnership.
|
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured money
market line of credit and senior subordinated notes, was $1.16 billion at
December 31, 2008 compared to $459 million at December 31, 2007. Average
borrowings in 2008 increased primarily due to our E. Texas acquisition.
For the year ended December 31, 2008, $23 million of interest cost has
been capitalized.
|
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
|
|
$ |
14.38 |
|
|
$ |
12.69 |
|
|
|
13
|
% |
|
$ |
141,218 |
|
|
$ |
117,624 |
|
|
|
20
|
% |
|
|
|
1.75 |
|
|
|
1.58 |
|
|
|
11
|
% |
|
|
17,215 |
|
|
|
14,674 |
|
|
|
17
|
% |
DD&A
- oil and gas production
|
|
|
9.54 |
|
|
|
7.30 |
|
|
|
31
|
% |
|
|
93,691 |
|
|
|
67,668 |
|
|
|
38
|
% |
|
|
|
4.09 |
|
|
|
3.98 |
|
|
|
3
|
% |
|
|
40,210 |
|
|
|
36,841 |
|
|
|
9
|
% |
|
|
|
1.76 |
|
|
|
1.05 |
|
|
|
68
|
% |
|
|
17,287 |
|
|
|
10,247 |
|
|
|
69
|
% |
|
|
$ |
31.52 |
|
|
$ |
26.60 |
|
|
|
18
|
% |
|
$ |
309,621 |
|
|
$ |
247,054 |
|
|
|
25
|
% |
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:
|
·
|
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)
|
|
|
87,990 |
|
|
|
81,246 |
|
|
|
8 |
% |
Fuel
gas cost/MMBtu (including transportation)
|
|
$ |
6.08 |
|
|
$ |
6.44 |
|
|
|
(6 |
%) |
|
·
|
Production
taxes: During 2007 our production taxes increased over 2006 as the value
of our oil and natural gas had 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.
|
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE in 2007 by 31% from
2006 due to an increase in capital spending in fields with higher drilling
and leasehold acquisition costs.
|
|
·
|
General
and administrative: in 2007, approximately 70% of our G&A was 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 was capitalized.
|
Estimated 2009
Oil and Gas Operating, G&A and Interest Expenses. We estimate our
2009 production volume will range between 32,000 BOE/D and 33,000 BOE/D. Based
on WTI of $47.50 and NYMEX HH of $5.00 MMBtu, we expect our expenses to be
within the following ranges:
|
|
Amount per BOE
|
|
|
|
Anticipated
|
|
|
|
|
|
|
|
|
|
range in 2009
|
|
|
2008
|
|
|
2007
|
|
Operating
costs-oil and gas production (1)
|
|
$ |
13.50
– 15.00 |
|
|
$ |
17.10 |
|
|
$ |
14.38 |
|
|
|
|
1.50
– 2.00 |
|
|
|
2.56 |
|
|
|
1.75 |
|
|
|
|
14.00
– 16.00 |
|
|
|
11.81 |
|
|
|
9.54 |
|
|
|
|
3.75
– 4.00 |
|
|
|
4.73 |
|
|
|
4.09 |
|
|
|
|
3.00 – 4.00 |
|
|
|
2.24 |
|
|
|
1.76 |
|
|
|
$ |
35.75
–41.00 |
|
|
$ |
38.44 |
|
|
$ |
31.52 |
|
|
(1)
|
We
expect operating costs to decrease in 2009 as compared to 2008 due to
lower natural gas prices which are the primary driver of our cost to
generate steam in California and our overall cost reduction
efforts.
|
|
(2)
|
We expect production taxes
will be lower on a per BOE basis as our averaged realized price decreases
due to lower commodity prices and a majority of these costs are based on a
percentage of our revenue.
|
Dry hole,
abandonment, impairment and exploration. In 2008 we had dry hole,
abandonment and impairment charges of $12.3 million. We recorded $7.3
million for technical difficulties that were encountered on five wells in
Piceance before reaching total depth. These holes were abandoned in
favor of drilling to the same bottom hole location by drilling new
wells. We incurred exploration costs of $2.4 million in 2008 compared
to $0.7 million and $3.8 million in 2007 and 2006, respectively. These costs
consist primarily of geological and geophysical costs in DJ. Due to
the release of our rigs we performed an impairment test which resulted in $2.4
million of impairment costs resulting from the impairment of one
rig. Additionally, we performed an impairment test of our oil and gas
assets at December 31, 2008 in accordance with SFAS 144 and determined that no
impairment was necessary.
In 2007
we had dry hole, abandonment and impairment charges of $13.7 million consisting
primarily of a $4.6 million write down of a portion of our Tri-State acreage in
connection with the then 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 write down of our Bakken properties sold in September 2007, and other
dry hole charges of $2.2 million.
Bad debt
expense. In December 2008, Flying J, Inc. and its wholly owned
subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for
bankruptcy protection under Chapter 11 of the United States Bankruptcy
Code. Of the $38.7 million recorded in bad debt expense for the year
ended December 31, 2008, $38.5 million relates to the allowance for bad debt
taken for the bankruptcy of BWOC with the remainder due to the bankruptcy of
SemCrude earlier in 2008. Of the $38.5 million due from BWOC, $12.4
million represents December crude oil sales by the Company and represents an
administrative claim under the bankruptcy proceedings and $26.1 million
represents November crude oil sales which would have the same priority as other
general unsecured claims. BWOC will also be liable to us for damages
under this contract for any amounts received by us under our short-term
contracts which are less than what we would have otherwise received from BWOC
had they been able to accept our production. We have guarantees from
Big West Oil and from Flying J, Inc. in the amount of $75 million each, in the
event that our claim is not fully collectible from BWOC. While we
believe that we may recover some or all of the amounts due from BWOC, the data
received from the bankruptcy proceedings to date has not provided us with
adequate data from which to make a conclusion that any amounts will be collected
nor as to whether BWOC will assume or reject our contract.
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. This credit is based on the average
wellhead prices for the prior year. While we do not expect to
generate EOR credit in 2009, we would expect to generate some EOR tax credit for
2010 if average U.S. wellhead oil prices in 2009 are within an approximate range
of $44 to $50. As of December 31, 2008, we have approximately $24
million of federal and $17 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 37%, 38% and 39% in 2008, 2007 and 2006,
respectively. The rate is lower than our combined federal and state statutory
tax rate of 40% primarily due to certain business incentives. We expect our
effective tax rate to range between 37% and 38% in 2009, given the current
commodity price environment. See Note 12 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 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 included
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.
On
January 2, 2008 we entered into NYMEX swaps to protect our DJ cash
flows. These natural gas derivatives were not correlated at
inception, and therefore ineffective. On January 14, 2008, we entered
into basis swaps and designated the combination of the basis swaps and NYMEX
swaps as cash flow hedges. However, we took a charge of $357,000 to
Commodity Derivatives in the first quarter of 2008 which reflected the
ineffectiveness for the interim period.
Most of
our oil hedges are based on the West Texas Intermediate (WTI) index and our
California oil sales contract with BWOC is tied to WTI which has allowed us to
qualify for hedge accounting and effectively hedge our
production. Our interim sales contracts are primarily based on the
field posting price and we are therefore subject to potential
ineffectiveness. There is a high correlation between WTI and the
field posting prices which allowed us to continue hedge
accounting. Additionally, under the dollar offset method, we did not
have any ineffectiveness under these contracts during 2008. However,
depending on the change in value of our actual hedges compared to a hypothetical
hedge based on field posting prices, we may have significant ineffectiveness on
these contracts in the future based on changes in the field posted price
compared to the changes in WTI.
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
zero at December 31, 2008 and $1.4 million as of December 31, 2007 in accordance
with SFAS No. 144. See Note 3 to the financial statements.
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.
Liquidity. In
October 2006, we completed the sale of $200 million of ten year 8.25% senior
subordinated notes and paid down our borrowings under our facility. In July 2008
we secured our credit facility with our assets and as of December 31, 2008 we
had bank commitments of $1.21 billion with a borrowing base of $1.25
billion. As of December 31, 2008, we had total borrowings under the
senior secured revolving credit facility and money market line of credit of $957
million and $200 million under our senior subordinated notes. Our available
credit under our senior secured credit facility was $245 million at year-end
2008.
Our
borrowing base is subject to semi-annual redeterminations in April and October
of each year. The borrowing base is determined by each lender based
on the value of our proved oil and gas reserves using price assumptions that
vary by lender. Due to a decline in commodity prices, it is likely
that our borrowing base will decrease in April 2009 which could substantially
reduce our liquidity. Should the amount of our borrowing base
decrease below the amount outstanding under the facility, we would be required
to repay any such deficiency in two equal installments 90 and 180 days after the
borrowing base redetermination. Hedges generally add significant
value to our borrowing base as the prices banks use to value our assets are at a
discount to futures prices. We have a minimal amount of our oil
production hedged after 2010 and we will likely enter into additional hedge
positions as needed to increase our borrowing base under the senior secured
credit facility. In addition to amending our covenants to increase
the amount of total leverage we may incur, the February 2009 amendment to our
credit facility provides us with the flexibility to add various forms of debt
that is junior to our senior secured credit facility and that is not subject to
a borrowing base. We are evaluating such junior debt to further increase our
liquidity.
Capital
Expenditures and Cash Flows. 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 debt
reduction or other corporate purposes. As we operate all of our
assets, we have the flexibility to modify our capital program based on changes
in commodity prices. In 2009, we have a capital program of
approximately $100 million and we expect to fully fund this program from
operating cash flow which should approximate $175 million. Approximately 90% of
our oil production is hedged for 2009 and thus our sensitivity to changes in oil
prices is limited. A ten dollar change in oil prices impacts our
operating cash flow by approximately $2 million in 2009. A one dollar
change in natural gas prices impacts operating cash flow by approximately $6
million.
Dividends.
Our regular annual dividend is currently $0.30 per share, or approximately $13.4
million annually, payable quarterly in March, June, September and
December.
Working
Capital. 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 decreased in 2008 (see graphs on page 32) and we increased production
by 19%.
Our
working capital balance fluctuates as a result of the amount of borrowings and
the timing of repayments under our credit arrangements. We use our long-term
borrowings under our 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
2009, we expect our working capital deficit to decrease by $50 to $65 million as
our accounts payable is reduced to reflect a $100 million capital budget
compared to a $400 million capital budget in 2009 and our price sensitive
royalty in California which is paid annually in February of each year is reduced
due to lower commodity prices.
In July
2008, we completed the purchase of 4,500 net acres in E. Texas for approximately
$650 million which was funded from our senior secured credit
facility.
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 of 2007 we paid the third and final
installment of approximately $54 million for the North Parachute Ranch property
located in Piceance.
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):
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Average
production (BOE/D)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
oil and gas sales prices, per BOE after hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital (deficit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging.
See Item 7A Quantitative and Qualitative Disclosures about Market Risk
and Note 18 to the financial statements.
Credit Facility.
See Note 7 to the financial statements for more information.
Contractual
Obligations.
Our
contractual obligations as of December 31, 2008 are as follows (in
thousands):
|
|
Total
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
Long-term
debt and interest
|
|
$ |
1,471,383 |
|
|
$ |
82,211 |
|
|
$ |
56,558 |
|
|
$ |
56,558 |
|
|
$ |
56,558 |
|
|
$ |
969,998 |
|
|
$ |
249,500 |
|
|
|
|
41,967 |
|
|
|
1,643 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
33,756 |
|
Operating
lease obligations
|
|
|
18,328 |
|
|
|
2,373 |
|
|
|
2,390 |
|
|
|
2,436 |
|
|
|
2,446 |
|
|
|
2,493 |
|
|
|
6,190 |
|
Drilling
and rig obligations
|
|
|
47,049 |
|
|
|
12,789 |
|
|
|
8,030 |
|
|
|
8,030 |
|
|
|
18,200 |
|
|
|
- |
|
|
|
- |
|
Firm
natural gas transportation contracts
|
|
|
165,071 |
|
|
|
19,803 |
|
|
|
19,803 |
|
|
|
19,803 |
|
|
|
19,652 |
|
|
|
17,557 |
|
|
|
68,453 |
|
|
|
$ |
1,743,798 |
|
|
$ |
118,819 |
|
|
$ |
88,423 |
|
|
$ |
88,469 |
|
|
$ |
98,498 |
|
|
$ |
991,690 |
|
|
$ |
357,899 |
|
Long-term debt and
interest - Our credit facility borrowings and related interest of
approximately 4.3% 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,
2008, 2007 and 2006 was $1.7 million, $1.5 million and $1.0 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, 2008 the remaining obligation is $2.4
million. Also included above, under our June 2006 joint venture agreement in
Piceance we are required to have 120 wells drilled by February 2011 to avoid
penalties of $0.2 million per well or a maximum of $24 million. As of December
31, 2008 we have drilled 29 of these wells and anticipate resuming drilling in
early 2010 to continue the progression towards meeting our
commitment.
Drilling rig
obligations - We are obligated in operating lease agreements for the use
of two drilling rigs, one in California and one of which resulted from our July,
2008 E. Texas Acquisition (see Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations,
Properties).
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
eight long-term transportation contracts on five 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, 2008, we had a
gross liability for uncertain tax benefits of $12 million of which $10 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, 2008, we had accrued approximately $1.2
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
through June 30, 2013 with a refiner for the purchase of our Uinta light crude
oil. Under the agreement, the refiner began purchasing 3,200 Bbl/D on July 1,
2007. After partial completion of its refinery expansion in Salt Lake City in
March 2008, the refiner increased its total purchase notional volumes to 5,000
Bbl/D. Pricing under the contract, which includes transportation and
gravity adjustments, is at a fixed percentage of WTI, and ranges between $10 and
$15 at WTI prices between $40 and $60. While the contractual
differentials under this contract may be less favorable at times than the posted
differential, demand for the Company’s paraffinic crude oil can vary seasonally
and this contract provides a stable outlet for the Company’s crude
oil.
Application
of Critical Accounting Policies. The preparation of
financial statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions for the reporting period
and as of the financial statement date. These estimates and assumptions affect
the reported amounts of assets and liabilities, the disclosure of contingent
liabilities and the reported amounts of revenues and expenses. Actual results
could differ from those amounts.
A
critical accounting policy is one that is important to the portrayal of 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. The application of the successful efforts method of accounting requires
management’s judgment to determine the proper designation of wells as either
developmental or exploratory, which will ultimately determine the proper
accounting treatment of costs of dry holes. Once a well is drilled, the
determination that economic proved reserves have been discovered may take
considerable time and judgment. The evaluation of oil and gas leasehold
acquisition costs included in unproved properties requires management’s judgment
to estimate the fair value of such properties
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 amounts 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. These evaluations involve a significant
amount of judgment since the results are based on estimated future sales prices,
costs to produce these products, estimates of oil and natural gas reserves to be
recovered and the timing of development.
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. Evaluation of the fair value of our hedge positions
involves judgment primarily related to whether or not the forecasted hedged
transaction will occur, the evaluation of unobservable inputs to the hedge
valuation and the evaluation of the credit risk of our
counterparties.
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
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 develop estimates based on
our historical costs and estimated costs where we do not have such historical
data and use 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.
The E.
Texas purchase price was based on the relative fair values, as determined by the
valuation of proved reserves and related assets as of the acquisition
date.
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 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 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 12.
In
September 2006, SFAS No. 157, Fair Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
We adopted this Statement in 2008 and increased our disclosures
accordingly. SFAS No. 157-2 addresses the same topic for nonfinancial
assets and liabilities and will become effective for our fiscal year beginning
January 1, 2009. We do not believe that the implementation of SFAS
157-2 will have a material impact on our financial statements.
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. We adopted this statement January 1, 2008 and it did not 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
became effective for our fiscal year beginning January 1, 2008 and did not have
any effect on our financial statements as we do not post collateral under our
hedging agreements.
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).
In
September 2008, the Financial Accounting Standards Board (FASB) issued FASB
Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133,
Accounting for Derivative
Instruments and Hedging Activities, to require disclosures by sellers of
credit derivatives, including credit derivatives embedded in a hybrid
instrument. This FSP also amends FASB Interpretation No.45,
Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others, to require an additional disclosure about the
current status of the payment/performance risk of a
guarantee. Further, this FSP clarifies the FASB’s intent about the
effective date of FASB Statement No. 161, Disclosures about Derivative
Instruments and Hedging Activities. This FSP was adopted
in 2008 and did not have a material effect on our financial statements and
related disclosures.
In
December 2007, the FASB issued Statement of Financial Accounting Standard (SFAS)
No. 160, Noncontrolling
Interests in Consolidated Financial Statements. SFAS 160 was issued to
establish accounting and reporting standards for the noncontrolling interest in
a subsidiary (formerly called minority interests) and for the deconsolidation of
a subsidiary. We do not expect the adoption of SFAS 160 to have a material
effect on our financial statements and related disclosures. The effective date
of this Statement is the same as that of the related Statement
141(R).
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Expanded disclosures are required to provide information
about (a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
application encouraged. This Statement will require us to provide the additional
disclosures described above.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles (GAAP) in
the United States of America (the GAAP hierarchy). This Statement is
effective 60 days following the SEC’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles, which has not
yet occurred. We do not expect
the adoption of SFAS 162 to have a material effect on our financial statements
or related disclosures.
As
discussed in Note 18 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.
The
following table summarizes our commodity hedge positions as of December 31,
2008:
Term
|
|
Average
Barrels Per Day
|
|
|
Floor/Ceiling
Prices
|
|
Term
|
|
Average
MMBtu Per Day
|
|
|
Average
Price
|
|
Crude Oil Sales (NYMEX
WTI) Collars
|
|
|
|
|
|
|
Natural Gas Sales (NYMEX
HH TO PEPL) Basis Swaps
|
|
|
|
|
|
|
|
|
|
295 |
|
|
$ |
80.00/$91.00 |
|
|
|
|
15,400 |
|
|
$ |
1.17 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$163.60 |
|
|
|
|
15,400 |
|
|
$ |
1.12 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$150.30 |
|
|
|
|
15,400 |
|
|
$ |
0.97 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$160.00 |
|
|
|
|
15,400 |
|
|
$ |
1.05 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$150.00 |
|
|
|
|
2,000 |
|
|
$ |
1.24 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$157.48 |
|
|
|
|
3,000 |
|
|
$ |
1.19 |
|
|
|
|
1,000 |
|
|
$ |
60.00
/ $80.00 |
|
|
|
|
2,000 |
|
|
$ |
1.05 |
|
|
|
|
1,000 |
|
|
$ |
55.00
/ $76.20 |
|
|
|
|
3,000 |
|
|
$ |
1.00 |
|
|
|
|
1,000 |
|
|
$ |
55.00
/ $77.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
55.00
/ $77.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
55.00
/ $83.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
60.00
/ $75.00 |
|
Natural Gas Sales (NYMEX
HH) Swaps
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
65.15
/ $75.00 |
|
|
|
|
15,400 |
|
|
$ |
8.50 |
|
|
|
|
1,000 |
|
|
$ |
65.50
/ $78.50 |
|
|
|
|
2,000 |
|
|
$ |
6.15 |
|
|
|
|
280 |
|
|
$ |
80.00
/ $90.00 |
|
|
|
|
3,000 |
|
|
$ |
6.19 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$161.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
100.00/$150.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
100.00/$160.00 |
|
Natural Gas Sales (NYMEX
HH) Collars
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
100.00/$150.00 |
|
|
|
|
2,000 |
|
|
$ |
6.00/$8.60 |
|
|
|
|
1,000 |
|
|
$ |
100.00/$158.50 |
|
|
|
|
3,000 |
|
|
$ |
6.00/$8.65 |
|
|
|
|
1,000 |
|
|
$ |
70.00/$86.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
270 |
|
|
$ |
80.00
/ $90.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales (NYMEX
WTI) Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
240 |
|
|
$ |
71.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
70.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
70.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
$ |
51.70 |
|
|
|
|
|
|
|
|
|
|
2nd,
3rd & 4th Quarters 2009
|
|
|
2,000 |
|
|
$ |
55.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000 |
|
|
$ |
54.67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
$ |
54.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
5,000 |
|
|
$ |
54.39 |
|
|
|
|
|
|
|
|
|
|
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.
From
January 1, 2009 to February 25, 2009, we entered into gas collars for 4,000
MMBtu/D with a floor of $6.50 and ceilings ranging from $8.75 to $8.90, for the
full year 2010 and E. Texas basis swaps on the same volumes for average prices
of $0.38 and $0.49. We converted 6,000 Bbl/D oil collars ranging from
floors of $55.00 to $60.00 and ceilings of $75.00 to $83.10 for the full year
2010 for swaps for the same volumes ranging from $61.00 to
$64.80. We also entered into oil collars for 3,000 Bbl/D for
the full year 2011 with floors of $55.00 to $55.20 and ceilings
of $68.65 to $70.50, an oil swap for 500 Bbl/D for the third quarter of 2009 for
$52.40, an oil swap for 650 Bbl/D for the full year 2010 for $56.90 and oil
swaps for 1,750 Bbl/D for the full year 2011 for average prices from $56.36 to
$61.80.
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 $55.00 to $100.00 per barrel while still participating in any oil price
increase up to the ceiling prices which range from $75.00 to $163.60 per barrel
on the volumes indicated above, and if 2) gas prices decline below our floor
price of $6.00 per MMBtu while still participating in any gas price increase up
to the ceiling prices, which range from $8.60 to $8.65 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 price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participant at the measurement date.
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 $0.8 million was recorded in other
comprehensive income at the date the hedges were designated.
In 2008
we exchanged 10,000 Bbl/D oil collar contracts for calendar 2009 with a floor of
$47.50 and a ceiling of $70.00 for swaps with strike prices ranging from $54.10
to $55.00. The collars were exchanged for the swaps on the same day
and the collars were dedesignated and the swaps were redesignated in the same
day.
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.
At
December 31, 2008, Accumulated Other Comprehensive Income, net of income taxes,
consisted of $114 million of unrealized gains from our crude oil and natural gas
hedges. Deferred net gains recorded in Accumulated Other Comprehensive Income at
December 31, 2008 are expected to be reclassified to earnings in the same period
as the hedged transaction. The 10,000 Bbl/D oil collars that were exchanged in
2008 for oil swaps were frozen in Accumulated Other Comprehensive Income on the
day of conversion and will be reclassified to earning in the same period as the
hedged transaction. 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.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Net
reduction of sales of oil and gas revenue due to hedging activities (in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
reduction of cost of gas due to hedging activities (in
millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
reduction in revenue per BOE due to hedging
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Based on
NYMEX futures prices as of December 31, 2008 (WTI $61.47; HH $6.84), we would
expect to receive payments over the remaining term of our crude oil and natural
gas hedges in place as follows:
|
|
12/31/08
|
|
|
Impact
of percent change in futures prices on
pretax future cash (payments) and receipts
|
|
|
|
NYMEX Futures
|
|
|
|
-40 |
% |
|
|
-20 |
% |
|
|
+20 |
% |
|
|
+40 |
% |
Average
WTI Futures Price (2009 – 2011)
|
|
$ |
61.47 |
|
|
$ |
36.88 |
|
|
$ |
49.18 |
|
|
$ |
73.77 |
|
|
$ |
86.06 |
|
Average
HH Futures Price (2009)
|
|
|
6.84 |
|
|
|
4.10 |
|
|
|
5.47 |
|
|
|
8.22 |
|
|
|
9.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$ |
185.2 |
|
|
$ |
353.5 |
|
|
$ |
254.0 |
|
|
$ |
116.7 |
|
|
$ |
29.5 |
|
Natural
Gas gain/(loss) (in millions)
|
|
|
12.2 |
|
|
|
34.0 |
|
|
|
20.8 |
|
|
|
1.7 |
|
|
|
(10.6
|
) |
|
|
$ |
197.4 |
|
|
$ |
387.5 |
|
|
$ |
274.8 |
|
|
$ |
118.4 |
|
|
$ |
18.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
(WTI $52.88; HH $6.42)
|
|
$ |
120.5 |
|
|
$ |
178.7 |
|
|
$ |
142.9 |
|
|
$ |
76.8 |
|
|
$ |
38.1 |
|
|
|
|
75.8 |
|
|
|
204.9 |
|
|
|
131.9 |
|
|
|
41.6 |
|
|
|
(18.6
|
) |
2011
(WTI $68.44)
|
|
|
1.1 |
|
|
|
3.9 |
|
|
|
- |
|
|
|
- |
|
|
|
(0.6
|
) |
Total
|
|
$ |
197.4 |
|
|
$ |
387.5 |
|
|
$ |
274.8 |
|
|
$ |
118.4 |
|
|
$ |
18.9 |
|
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, 2008 and 2007 was $1.13 billion and $445 million,
respectively. Interest on amounts borrowed under our revolving credit facility
is charged at LIBOR plus 1.375% to 2.125%, subject to our interest rate hedges,
plus the senior unsecured revolving credit facility’s margin through June 30,
2012. Based on year end 2008 credit facility borrowings, a 1% change in interest
rates would have a $3.7 million after tax impact on our financial
statements.
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. In 2008, $50 million of these interest rate swaps were
extended one year, resulting in a fixed rate of approximately 4.8%.
In 2008 we
also entered into three year interest rate swaps for a fixed rate of
approximately 2.2% on an additional $275 million of our outstanding borrowings
under our credit facility for three years beginning on April 15 and September
15, 2009. These interest rate swaps have been designated as cash flow
hedges. As of December 31, 2008, we had a total of $575 million of
fixed rate positions averaging 4.8% resulting from the $200 million of 8.25%
senior subordinated notes and $375 million of interest rate swaps for a fixed
rate of approximately 2.2%.
From
January 1, 2009 through February 25, 2009, we entered into three year interest
rates swaps for a fixed rate of approximately 2.0% on an additional $100 million
of our outstanding borrowings under our credit facility for three years
beginning on April 15 and December 15, 2009. These interest rate
swaps have been designated as cash flow hedges. As a result of these
2009 hedge contracts, we have a total of $675 million of fixed rate positions
averaging 4.4%.
|
Page
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting
Firm
|
|
Balance
Sheets at December 31, 2008 and 2007
|
|
Statements
of Income for the Years Ended December 31, 2008, 2007 and
2006
|
|
Statements
of Comprehensive Income for the Years Ended December 31, 2008, 2007 and
2006
|
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2008, 2007 and
2006
|
|
Statements
of Cash Flows for the Years Ended December 31, 2008, 2007 and
2006
|
|
Notes
to the Financial Statements
|
|
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)
|
|
Financial
statement schedules have been omitted since they are either not required, are
not applicable, or the required information is shown in the financial statements
and related notes.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of Berry Petroleum Company:
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, 2008 and 2007, and the results of its operations and its
cash flows for each of the three years in the period ended December 31,
2008 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,
2008, 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 4 to the financial statements, the Company changed the manner
in which it accounts for recurring fair value measurements of financial
instruments in 2008.
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
Denver,
Colorado
February
25, 2009
Balance
Sheets
December
31, 2008 and 2007
(In
Thousands, Except Share Information)
ASSETS
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable, net of allowance for doubtful accounts of $38,511 and $0,
respectively
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
and royalties payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
long-term liabilities
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies (Note 14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
|
|
|
|
|
|
Capital
stock, $0.01 par value:
|
|
|
|
|
|
|
|
|
Class
A Common Stock, 100,000,000 shares authorized; 42,782,365 shares issued
and outstanding (42,583,002 in 2007)
|
|
|
|
|
|
|
|
|
Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and
outstanding (liquidation preference of $899) (1,797,784 in
2007)
|
|
|
|
|
|
|
|
|
Capital
in excess of par value
|
|
|
|
|
|
|
|
|
Accumulated
other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
Statements
of Income
Years
ended December 31, 2008, 2007 and 2006
(In
Thousands, Except Per Share Data)
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
$ |
697,977 |
|
|
$ |
467,400 |
|
|
$ |
430,497 |
|
|
|
|
63,525 |
|
|
|
55,619 |
|
|
|
52,932 |
|
|
|
|
35,750 |
|
|
|
- |
|
|
|
- |
|
Gain
(loss) on sale of assets
|
|
|
(1,297
|
) |
|
|
54,173 |
|
|
|
97 |
|
Interest
and other income, net
|
|
|
5,576 |
|
|
|
6,265 |
|
|
|
2,812 |
|
|
|
|
801,531 |
|
|
|
583,457 |
|
|
|
486,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
200,098 |
|
|
|
141,218 |
|
|
|
117,624 |
|
Operating
costs - electricity generation
|
|
|
54,891 |
|
|
|
45,980 |
|
|
|
48,281 |
|
|
|
|
29,898 |
|
|
|
17,215 |
|
|
|
14,674 |
|
Depreciation,
depletion & amortization - oil and gas
production
|
|
|
138,237 |
|
|
|
93,691 |
|
|
|
67,668 |
|
Depreciation,
depletion & amortization –
electricity generation
|
|
|
2,812 |
|
|
|
3,568 |
|
|
|
3,343 |
|
|
|
|
32,072 |
|
|
|
- |
|
|
|
- |
|
General
and administrative
|
|
|
55,353 |
|
|
|
40,210 |
|
|
|
36,841 |
|
|
|
|
26,209 |
|
|
|
17,287 |
|
|
|
10,247 |
|
|
|
|
358 |
|
|
|
- |
|
|
|
(736 |
) |
Dry
hole, abandonment, impairment and exploration
|
|
|
12,316 |
|
|
|
13,657 |
|
|
|
12,009 |
|
|
|
|
38,665 |
|
|
|
- |
|
|
|
- |
|
|
|
|
590,909 |
|
|
|
372,826 |
|
|
|
309,951 |
|
Income
before income taxes
|
|
|
210,622 |
|
|
|
210,631 |
|
|
|
176,387 |
|
Provision
for income taxes
|
|
|
77,093 |
|
|
|
80,703 |
|
|
|
68,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
133,529 |
|
|
$ |
129,928 |
|
|
$ |
107,943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
$ |
3.00 |
|
|
$ |
2.95 |
|
|
$ |
2.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
$ |
2.94 |
|
|
$ |
2.89 |
|
|
$ |
2.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share)
|
|
|
44,485 |
|
|
|
44,075 |
|
|
|
43,948 |
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
781 |
|
|
|
604 |
|
|
|
723 |
|
|
|
|
129 |
|
|
|
227 |
|
|
|
103 |
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share
|
|
|
45,395 |
|
|
|
44,906 |
|
|
|
44,774 |
|
Statements
of Comprehensive Income
Years
Ended December 31, 2008, 2007 and 2006
|
|
$ |
133,529 |
|
|
$ |
129,928 |
|
|
$ |
107,943 |
|
Unrealized
gains (losses) on derivatives, net of income taxes of $96,546, ($66,627),
and $7,647, respectively
|
|
|
157,522 |
|
|
|
(99,941
|
) |
|
|
11,471 |
|
Reclassification
of realized gains (losses) on derivatives included in net income, net of
income taxes of $47,119, ($524) and ($4,712),
respectively
|
|
|
76,879 |
|
|
|
(786
|
) |
|
|
(7,068
|
) |
|
|
$ |
367,930 |
|
|
$ |
29,201 |
|
|
$ |
112,346 |
|
The
accompanying notes are an integral part of these financial
statements.
Statements
of Shareholders’ Equity
Years
Ended December 31, 2008, 2007 and 2006
(In
Thousands, Except Per Share Data)
|
|
Class A
|
|
|
Class B
|
|
|
Capital in Excess of Par
Value
|
|
|
Retained Earnings
|
|
|
Accumulated Other
Comprehensive
Income (Loss)
|
|
|
Shareholders' Equity
|
|
Balances
at January 1, 2006
|
|
$ |
211 |
|
|
$ |
9 |
|
|
$ |
56,064 |
|
|
$ |
302,306 |
|
|
$ |
(24,380 |
) |
|
$ |
334,210 |
|
|
|
|
211 |
|
|
|
9 |
|
|
|
(220
|
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Shares
repurchased and retired (600,200 shares)
|
|
|
(6
|
) |
|
|
- |
|
|
|
(18,713
|
) |
|
|
- |
|
|
|
- |
|
|
|
(18,719
|
) |
Stock-based
compensation (498,939 shares)
|
|
|
5 |
|
|
|
- |
|
|
|
9,256 |
|
|
|
- |
|
|
|
- |
|
|
|
9,261 |
|
Tax
impact of stock option exercises
|
|
|
- |
|
|
|
- |
|
|
|
3,444 |
|
|
|
- |
|
|
|
- |
|
|
|
3,444 |
|
Deferred
director fees - stock compensation
|
|
|
- |
|
|
|
- |
|
|
|
335 |
|
|
|
- |
|
|
|
- |
|
|
|
335 |
|
Cash
dividends declared - $0.30 per share, including RSU dividend
equivalents
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(13,177
|
) |
|
|
- |
|
|
|
(13,177
|
) |
Change
in fair value of derivatives
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,403 |
|
|
|
4,403 |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
107,943 |
|
|
|
- |
|
|
|
107,943 |
|
Balances
at December 31, 2006
|
|
|
421 |
|
|
|
18 |
|
|
|
50,166 |
|
|
|
397,072 |
|
|
|
(19,977
|
) |
|
|
427,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation (484,451 shares)
|
|
|
4 |
|
|
|
- |
|
|
|
12,930 |
|
|
|
- |
|
|
|
- |
|
|
|
12,934 |
|
Tax
impact of stock option exercises
|
|
|
- |
|
|
|
- |
|
|
|
3,049 |
|
|
|
- |
|
|
|
- |
|
|
|
3,049 |
|
Deferred
director fees - stock compensation
|
|
|
- |
|
|
|
- |
|
|
|
445 |
|
|
|
- |
|
|
|
- |
|
|
|
445 |
|
Cash
dividends declared - $0.30 per share, including RSU dividend
equivalents
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(13,292
|
) |
|
|
- |
|
|
|
(13,292
|
) |
Cumulative
effect of accounting change from adoption of FIN 48
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(63
|
) |
|
|
- |
|
|
|
(63
|
) |
Change
in fair value of derivatives
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(100,727
|
) |
|
|
(100,727
|
) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
129,928 |
|
|
|
- |
|
|
|
129,928 |
|
Balances
at December 31, 2007
|
|
|
425 |
|
|
|
18 |
|
|
|
66,590 |
|
|
|
513,645 |
|
|
|
(120,704
|
) |
|
|
459,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation (199,363 shares)
|
|
|
2 |
|
|
|
- |
|
|
|
11,684 |
|
|
|
- |
|
|
|
- |
|
|
|
11,686 |
|
Tax
impact of stock option exercises
|
|
|
- |
|
|
|
- |
|
|
|
938 |
|
|
|
- |
|
|
|
- |
|
|
|
938 |
|
Deferred
director fees - stock compensation
|
|
|
- |
|
|
|
- |
|
|
|
441 |
|
|
|
- |
|
|
|
- |
|
|
|
441 |
|
Cash
dividends declared - $0.30 per share, including RSU dividend
equivalents
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(13,425
|
) |
|
|
- |
|
|
|
(13,425
|
) |
Change
in fair value of derivatives
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
234,401 |
|
|
|
234,401 |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
133,529 |
|
|
|
- |
|
|
|
133,529 |
|
Balances
at December 31, 2008
|
|
$ |
427 |
|
|
$ |
18 |
|
|
$ |
79,653 |
|
|
$ |
633,749 |
|
|
$ |
113,697 |
|
|
$ |
827,544 |
|
The
accompanying notes are an integral part of these financial
statements.
Statements of Cash
Flows
Years Ended December 31, 2008, 2007
and 2006
(In Thousands)
Cash
flows from operating activities:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based
compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain)
loss on sale of asset
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for abandonment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase)
decrease in current assets other than cash, cash equivalents and
short-term
investments
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in current liabilities other than line of
credit
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuances on line of credit
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
on line of credit
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
on long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from stock option exercises
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of $75,772, ($36,562), and $4,188,
respectively)
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current
(net of income taxes of $67,893, ($30,589), and ($1,252), respectively)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) to accumulated other comprehensive income
(loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
financing activity: Property acquired for debt
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these financial
statements.
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.
|
Reclassifications
and Error Corrections
|
Certain
reclassifications have been made to prior period financial statements to conform
them to the current year presentation. Specifically, the change in book
overdraft line in the Statements of Cash Flows is classified as an operating
activity to reflect the use of these funds in operations, rather than their
prior year classification as a financing activity.
In March
2008, we determined there was an error in computing royalties payable in prior
years, accumulating to $10.5 million as of December 31, 2007. We concluded the
error was not material to any individual prior interim or annual period (or to
the projected earnings for 2008) and, therefore, the error was corrected during
the first quarter of 2008, with the effect of increasing our sales of oil and
gas by $10.5 million and reducing our royalties payable.
3.
|
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, 2008 and
2007 is $31.8 million and $7.8 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, 2008 and 2007, we have an allowance for doubtful accounts of $38.5
million and $0, respectively. The 2008 amount represents the
Company’s November and December 2008 sales to Big West of California
(BWOC). In December 2008, Flying J, Inc., and its wholly owned
subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for
bankruptcy protection under Chapter 11 of the United States Bankruptcy
Code. Also in December 2008, BWOC informed the Company that it was
unable to receive the Company’s production. We have entered into
various short-term agreements with other companies to sell our California oil
production. Pricing and volumes under these agreements vary with
prices ranging from just above the posted price for San Joaquin heavy oil to the
posted price less a discount. In January 2009, our California crude
oil daily production was, on average, near levels achieved prior to BWOC’s
Chapter 11 filing. BWOC is evaluating several options, including a
sale of the Bakersfield, California refinery. We recorded $38.5
million of bad debt expense in 2008 for the bankruptcy of BWOC. Of
the $38.5 million due from BWOC, $12.4 million represents December crude oil
sales by the Company and represents an administrative claim under the bankruptcy
proceedings and $26.1 million represents November crude oil sales which would
have the same priority as other general unsecured claims. BWOC will
also be liable to us for damages under this contract for any amounts received by
us under our short-term contracts which are less than what we would have
otherwise received from BWOC had they been able to accept our
production. We have guarantees from Big West Oil and from Flying J,
Inc. in the amount of $75 million each, in the event that our claim is not fully
collectible from BWOC. While we believe that we may recover some or
all of the amounts due from BWOC, the data received from the bankruptcy
proceedings to date has not provided us with adequate data from which to make a
conclusion that any amounts will be collected nor as to whether BWOC will assume
or reject our contract.
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 on 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 contract. 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 (loss) 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 18 - Hedging.
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 zero and $1.4
million as of December 31, 2008 and 2007, 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. Both of these lease
agreements were terminated as of December 31, 2008.
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 use our historical cost to abandon wells
and facilities to provide evidence of our future cost to adandon these
assets. 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.
Accrued liabilities -
Accrued liabilities consist primarily of Accrued property taxes, Accrued
interest and Accrued payroll costs. Accrued property taxes were $13.5
million and $8.5 million as of December 31, 2008 and 2007,
respectively. Accrued interest was $8.4 million and $3.3 million as
of December 31, 2008 and 2007, respectively. Accrued payroll costs
were $8.4 million and $7.1 million as of December 31, 2008 and 2007,
respectively.
Revenue recognition -
Revenues associated with sales of crude oil, natural gas, electricity and
natural gas marketing 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). Revenues are derived from gas
marketing sales which represent excess capacity on the Rockies Express
pipeline which we use to market natural gas for our working interest
partners.
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, 2008, 2007 and 2006 was $5.8 million,
$5.0 million and $5.3 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 Operating costs - oil and gas
production were $9.5 million, $1.2 million and $0 for 2008, 2007 and 2006,
respectively. Natural gas transportation costs included in Operating
costs - electricity generation were $7.2 million, $6.7 million and $6.8
million for 2008, 2007 and 2006, respectively. Additionally, the transportation
costs in Uinta were $0.2 million, $1.4 million and $1.4 million in 2008, 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 340,000, 855,000, and 499,000 were excluded from the
calculation of diluted net income per common share for 2008, 2007 and 2006,
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.
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.
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.
General - The price sensitive royalty
that burdens our Formax property in the South Midway Sunset field has
changed. We previously paid a royalty equal to 75% of the amount of
the heavy oil posted above a price of $16.11. This price escalates at
2% annually. Effective January 1, 2008, the royalty rate is reduced
from 75% to 53% as long as we maintain a minimum steam injection level, which we
expect to meet, that reduces over time. Current net production from
this property is approximately 2,300 Bbl/D.
Recent accounting
developments - 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 12.
In
September 2006, SFAS No. 157, Fair Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
We adopted this Statement in 2008 and increased our disclosures
accordingly. SFAS No. 157-2 addresses the same topic for nonfinancial
assets and liabilities and will become effective for our fiscal year beginning
January 1, 2009. We do not believe that the implementation of SFAS
157-2 will have a material impact 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
became effective for our fiscal year beginning January 1, 2008 and did not have
any effect on our financial statements, as we do not post collateral under our
hedging agreements.
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which
expands the information that a reporting entity provides in its financial
reports about a business combination and its effects. This Statement establishes
principles and requirements for how the acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any non controlling interest in the acquiree, recognizes and measures the
goodwill acquired in the business combination or a gain from a bargain purchase,
and determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination. This Statement applies prospectively to business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. An entity may not
apply the principle before that date. We may experience a financial statement
impact depending on the nature and extent of any new business combinations
entered into after the effective date of SFAS No. 141(R).
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Expanded disclosures are required to provide information
about (a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
application encouraged. This Statement will require us to provide the additional
disclosures described above in the first quarter of 2009.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles (GAAP) in
the United States of America (the GAAP hierarchy). This Statement
became effective on November 13, 2008.
In
September 2008, the Financial Accounting Standards Board (FASB) issued FASB
Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133,
Accounting for Derivative
Instruments and Hedging Activities, to require disclosures by sellers of
credit derivatives, including credit derivatives embedded in a hybrid
instrument. This FSP also amends FASB Interpretation No.45,
Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others, to require an additional disclosure about the
current status of the payment/performance risk of a
guarantee. Further, this FSP clarifies the FASB’s intent about the
effective date of FASB Statement No. 161, Disclosures about Derivative
Instruments and Hedging Activities. This FSP was adopted in 2008 and did
not have a material effect on our financial statements and related
disclosures.
In
February 2009, the SEC issued its final rule on Modernization of Oil and Gas
Reporting (the Final Rule), which revises the disclosures required by oil
and gas companies. In addition to changing the definition and
disclosure requirements for oil and gas reserves, the Final Rule changes the
requirements for determining quantities of oil and gas reserves. The
Final Rule also changes certain accounting requirements under the full cost
method of accounting for oil and gas activities. The revisions are
intended to provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves, with a view to helping investors evaluate
their investments in oil and gas companies. The amendments are
designed to modernize the requirements for the determination of oil and gas
reserves, aligning them with current practices and updating them for changes in
technology. The Final Rule applies to registration statements filed
on or after January 1, 2010, and annual reports on Form 10-K for fiscal years
ending on or after December 31, 2009. This rule will require us to
provide the additional disclosures described above in our 10-K for our fiscal
year ending December 31, 2009. We are still evaluating the impact the
Final Rule will have on our financial statements but we may increase the amount
of proved, undeveloped reserves reported from technology advances and we may
disclose probable and possible reserves.
4.
|
Fair
Value Measurement
|
In
September 2006, SFAS No. 157, Fair Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
We adopted this Statement as of January 1, 2008.
Determination
of fair value
We have
established and documented a process for determining fair values. Fair value is
based upon quoted market prices, where available. We have various controls in
place to ensure that valuations are appropriate. These controls
include: identification of the inputs to the fair value methodology through
review of counterparty statements and other supporting documentation,
determination of the validity of the source of the inputs, corroboration of the
original source of inputs through access to multiple quotes, if available, or
other information and monitoring changes in valuation methods and assumptions.
The methods described above may produce a fair value calculation that may not be
indicative of future fair values. Furthermore, while we believe these valuation
methods are appropriate and consistent with that used by other market
participants, the use of different methodologies, or assumptions, to determine
the fair value of certain financial instruments could result in a different
estimate of fair value.
Valuation
hierarchy
SFAS 157
establishes a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy is based upon the transparency of inputs
to the valuation of an asset or liability as of the measurement date. The three
levels are defined as follows.
• Level
1 - inputs to the valuation methodology that are quoted prices (unadjusted) for
identical assets or liabilities in active markets.
• Level
2 - inputs to the valuation methodology that include quoted prices for similar
assets and liabilities in active markets, and inputs that are observable for the
asset or liability, either directly or indirectly, for substantially the full
term of the financial instrument.
• Level
3 - inputs to the valuation methodology that are unobservable and significant to
the fair value measurement.
A
financial instrument's categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement.
Our oil
swaps, natural gas swaps and interest rate swaps are valued using the
counterparties’ mark-to-market statements which are validated by our internally
developed models and are classified within Level 2 of the valuation hierarchy.
The observable inputs include underlying commodity and interest rate levels and
quoted prices of these instruments on actively traded
markets. Derivatives that are valued based upon models with
significant unobservable market inputs (primarily volatility), and that are
normally traded less actively are classified within Level 3 of the valuation
hierarchy. Level 3 derivatives include oil collars, natural gas collars and
natural gas basis swaps.
Assets
and liabilities measured at fair value on a recurring basis
December
31, 2008 (in millions)
|
|
Total carrying value on the Balance
Sheet
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative asset
|
|
|
198.4 |
|
|
|
25.9 |
|
|
|
172.5 |
|
Interest
rate swaps liability
|
|
|
(12.5 |
) |
|
|
(12.5 |
) |
|
|
- |
|
Total
assets at fair value
|
|
|
185.9 |
|
|
|
13.4 |
|
|
|
172.5 |
|
Changes
in Level 3 fair value measurements
The table
below includes a rollforward of the Balance Sheet amounts (including the change
in fair value) for financial instruments classified by us within Level 3 of the
valuation hierarchy. When a determination is made to classify a financial
instrument within Level 3 of the valuation hierarchy, the determination is based
upon the significance of the unobservable factors to the overall fair value
measurement. Level 3 financial instruments typically include, in addition to the
unobservable or Level 3 components, observable components (that is, components
that are actively quoted and can be validated to external sources).
(in
millions)
|
|
Three months ended December 31,
2008
|
|
|
Twelve months ended December 31,
2008
|
|
|
|
|
|
|
|
|
Fair
value liability, beginning of period
|
|
$ |
(208.9 |
) |
|
$ |
(194.3 |
) |
Total
realized and unrealized gains and (losses) included in sales of oil and
gas
|
|
|
227.1 |
|
|
|
196.0 |
|
Purchases,
sales and settlements, net
|
|
|
154.3 |
|
|
|
170.8 |
|
Transfers
in and/or out of Level 3
|
|
|
- |
|
|
|
- |
|
Fair
value asset, December 31, 2008
|
|
|
172.5 |
|
|
|
172.5 |
|
|
|
|
|
|
|
|
|
|
Total
unrealized gains and (losses) included in income related to financial
assets and liabilities still on the condensed balance sheet at December
31, 2008
|
|
$ |
- |
|
|
$ |
- |
|
In
February of 2007, the FASB issued SFAS 159, which is effective for fiscal years
beginning after November 15, 2007. SFAS 159 provides an option to elect fair
value as an alternative measurement for selected financial assets and financial
liabilities not previously carried at fair value. We adopted this statement at
January 1, 2008, but did not elect fair value as an alternative for any
financial assets or liabilities.
Cash
equivalents consist principally of bank deposits. Cash and equivalents of $0.2
million and $0.3 million at December 31, 2008 and 2007, respectively, are stated
at cost.
The
estimated fair value of financial instruments is the amount at which the
instrument could be exchanged currently between willing parties. We
use available marketing data and valuation methodologies to estimate the fair
value of debt. This disclosure is presented in accordance with SFAS No. 107,
“Disclosures about Fair Value of Financial Instruments” and does not impact our
financial position, results of operations or cash flows. Our
short-term investments available for sale at December 31, 2008 and 2007 consist
of United States treasury notes that mature in less than one year. For the three
years ended December 31, 2008, realized and unrealized gains and losses of our
short-term investments were insignificant to the financial statements. The cost
of our long-term senior subordinated notes is $200 million and the
fair value is approximately $116 million. The cost and the fair value
of our senior secured credit facilities is approximately $957
million.
5.
|
Concentration
of Credit Risks
|
We sell
oil, gas and natural gas liquids to pipelines, refineries and oil companies and
electricity to utility companies. Credit is extended based on an evaluation of
the customer’s financial condition and historical payment record.
On
November 21, 2005, we entered into a crude oil sales contract with BWOC for
substantially all of our California production for deliveries beginning February
1, 2006. In December 2008, Flying J, Inc., and its wholly owned
subsidiary Big West Oil and its wholly owned subsidiary BWOC filed for
bankruptcy protection under Chapter 11 of the United States Bankruptcy
Code. Also in December 2008, BWOC informed the Company that it was
unable to receive the Company’s production. We have entered into
various short-term agreements with other companies to sell our California oil
production. Pricing and volumes under these agreements vary with
prices ranging from just above the posted price for San Joaquin heavy oil to the
posted price less a discount. In January 2009, our California crude
oil daily production was, on average, near levels achieved prior to BWOC’s
Chapter 11 filing. BWOC is evaluating several options, including a
sale of the Bakersfield, California refinery. We recorded $38.5
million of bad debt expense in 2008 for the bankruptcy of BWOC. Of
the $38.5 million due from BWOC, $12.4 million represents December 2008 crude
oil sales by the Company and represents an administrative claim under the
bankruptcy proceedings and $26.1 million represents November 2008 crude oil
sales which would have the same priority as other general unsecured
claims. BWOC will also be liable to us for damages under this
contract for any amounts received by us under our short-term contracts which are
less than what we would have otherwise received from BWOC had they been able to
accept our production. We have guarantees from Big West Oil and from
Flying J, Inc. in the amount of $75 million each, in the event that our claim is
not fully collectible from BWOC. While we believe that we may recover
some or all of the amounts due from BWOC, the data received from the bankruptcy
proceedings to date has not provided us with adequate data from which to make a
conclusion that any amounts will be collected nor as to whether BWOC will assume
or reject our contract.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract with
a refiner for our Uinta light crude oil. Under the agreement, the refiner began
purchasing 3,200 Bbl/D on July 1, 2007. After partial completion of its refinery
expansion in Salt Lake City in March 2008, the refiner increased its total
purchase capacity to 5,000 Bbl/D. This contract is in effect through
June 30, 2013. This contract is our only sales contract for our Uinta
oil.
During
2008, the Company experienced two credit losses related to its oil and natural
gas sales. Included in bad debt expense is $0.2 million related to
the bankruptcy of SemGroup and $38.5 million related to BWOC as described
above. During the two years 2006 and 2007, we did not have any credit
losses on the sale of oil, natural gas, natural gas liquids or hedging
contracts.
We place
our temporary cash investments with high quality financial institutions and
limit the amount of credit exposure to any one financial institution. For the
three years ended December 31, 2008, we have not incurred losses related to
these investments.
As
of December 31, 2008, $177 million, of the approximate net value of the
Company’s hedging positions of approximately $186 million, can be attributed to
one of three counterparties. While a significant portion of our
hedges are with a small number of counterparties, we monitor each counterparty’s
credit rating and CDS rate and as of December 31, 2008 each of our hedge
counterparties maintained a rating of AA-(S&P)/Aa2(Moody’s) or
better. Neither we nor our counterparties are required to post
collateral under our hedging contracts.
The
following summarizes the accounts receivable balances at December 31, 2008 and
2007 and sales activity with significant customers for each of the years ended
December 31, 2008, 2007 and 2006 (in thousands). We do not believe that the loss
of any one customer would impact the marketability, but it may impact the
profitability of our crude oil, gas, natural gas liquids or electricity sold.
Due to the possibility of refinery constraints in the Utah region, it is
possible that the loss of the crude oil sales customer could impact the
marketability of a portion of our Utah crude oil volumes.
|
|
Accounts
Receivable
|
|
|
Sales
before hedging and royalties
|
|
|
|
As of December 31,
|
|
|
For the Year Ended
December 31,
|
|
Customer
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Oil
& Gas Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,082 |
|
|
$ |
5,347 |
|
|
$ |
107,414 |
|
|
$ |
39,791 |
|
|
$ |
- |
|
|
|
|
- |
|
|
|
- |
|
|
|
3,795 |
|
|
|
20,239 |
|
|
|
75,597 |
|
|
|
|
4 |
|
|
|
5,793 |
|
|
|
17,734 |
|
|
|
28,170 |
|
|
|
10,458 |
|
|
|
|
38,787 |
|
|
|
44,450 |
|
|
|
582,885 |
|
|
|
404,038 |
|
|
|
305,587 |
|
|
|
|
5,785 |
|
|
|
- |
|
|
|
32,431 |
|
|
|
- |
|
|
|
- |
|
|
|
$ |
48,658 |
|
|
$ |
55,590 |
|
|
$ |
744,259 |
|
|
$ |
492,238 |
|
|
$ |
391,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,799 |
|
|
$ |
1,979 |
|
|
$ |
30,975 |
|
|
$ |
26,033 |
|
|
$ |
24,335 |
|
|
|
|
2,227 |
|
|
|
2,573 |
|
|
|
34,553 |
|
|
|
29,470 |
|
|
|
28,597 |
|
|
|
$ |
4,026 |
|
|
$ |
4,552 |
|
|
$ |
65,528 |
|
|
$ |
55,503 |
|
|
$ |
52,932 |
|
Sales
amounts will not agree to the Statements of Income due primarily to the effects
of hedging and price sensitive royalties paid on a portion of our crude oil
sales, which are netted in “Sales of oil and gas” on the Statements of
Income. Accounts receivable amounts will not agree to the Balance
Sheet due primarily to the Allowance for doubtful accounts, which is netted in
Accounts receivable on the Balance Sheet.
As of December 31, 2008
we have an allowance for doubtful accounts of $38.5 million which represents the
Company’s November and December 2008 sales to Big West of California
(BWOC). While the Company believes that it may recover some or all of
the amounts due from BWOC, the data received from the bankruptcy proceedings to
date has not provided the Company with any data from which to make a conclusion
that any amounts will be collected. We did not have an allowance for
doubtful accounts for the year ended December 31, 2007.
6.
|
Oil
and Gas Properties, Buildings and
Equipment
|
Oil and
gas properties, buildings and equipment consist of the following at December 31
(in thousands):
Oil
and gas:
|
|
2008
|
|
|
2007
|
|
Proved
properties:
|
|
|
|
|
|
|
Producing
properties, including intangible drilling costs
|
|
|
|
|
|
|
|
|
Lease
and well equipment (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties,
including intangible drilling costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
rigs and equipment
|
|
|
|
|
|
|
|
|
Buildings
and improvements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
accumulated depreciation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes cogeneration facility
costs.
On July
15, 2008, the Company acquired certain interests in natural gas producing
properties on 4,500 net acres in Limestone and Harrison Counties in East
Texas for $668 million cash (E. Texas Acquisition) including an initial purchase
price of $622 million, and post closing adjustments of $46 million.
In
February 2006, we closed on an agreement with a private seller to acquire a 50%
working interest in natural gas assets in Piceance of western Colorado for
approximately $159 million. The acquisition was funded under our existing credit
facility. We purchased 100% of Piceance Operating Company LLC (which owned a 50%
working interest in the acquired assets). The total purchase price was allocated
as follows: $30 million to proved reserves and $129 million to unproved
properties. The allocation was made based on fair value. The historical
operating activities of these oil and gas assets are insignificant compared to
our historical operations, and therefore we have not included proforma
disclosures. Piceance Operating Company LLC was dissolved subsequent to the
acquisition.
In June
2006, we entered into an agreement with a party to jointly develop the North
Parachute Ranch property in the Grand Valley field of Piceance of western
Colorado. We estimate we will pay up to $153 million to fund the drilling of 90
natural gas wells on the joint venture partner’s acreage. The maximum amount of
cost charged to us will not exceed $1.7 million per well. If any wells are
drilled for less than $1.7 million, the excess will be returned to us. In
exchange for our payments of up to $153 million, we will earn a 5% working
interest (4% net revenue interest) on each of the 90 wellbores and a net working
interest of 95% (79% net revenue interest) in 4,300 gross acres located
elsewhere on the property. The costs of drilling and development on the 4,300
gross acres will be shared by the partners in relation to the working interests.
The $153 million payment was allocated to unproved properties based on the fair
value of the 5% and 95% working interests.
In July
2006, we paid $51 million, the first installment of the total $153 million, and
thereby earned the assignment of the 4,300 gross acres. In November 2006, we
paid the second installment of approximately $48 million. We paid the third and
final installment of approximately $54 million in May 2007. Prior to February
2011, we are required to drill 120 wells, bearing 95% of the cost, on our 4,300
gross acres and if not met, then we are required to pay $0.2 million for each
well less than 120 drilled. Additionally, if we have not drilled at least one
well by mid-2011 in each 160 acre tract within the 4,300 gross acres, then that
specific undrilled 160 acre tract shall be reassigned to the joint venture
partner. As of the date of the agreement there were no operating activities from
these gas assets.
Suspended
Well Costs
The
following table provides an aging of capitalized exploratory well costs based on
the date the drilling was completed and the number of wells for which
exploratory well costs have been capitalized for a period of greater than one
year since the completion of drilling (in thousands, except number of
projects):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Capitalized
exploratory well costs that have been capitalized for a period of one year
or less
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized
exploratory well costs that have been capitalized for a period greater
than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of projects that have exploratory well costs that have been capitalized
for a period of greater than one year
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table reflects the net changes in capitalized exploratory well costs
(in thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Beginning
balance at January 1
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
to capitalized exploratory well costs pending the determination of proved
reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications
to wells, facilities and equipment based on the determination of proved
reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized
exploratory well costs charged to expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry hole, abandonment and
impairment and
asset sales
In 2008
we had dry hole, abandonment and impairment charges of $12.3 million consisting
primarily of $7.3 million for technical difficulties that were encountered on
five wells in Piceance before reaching total depth. These holes were
abandoned in favor of drilling to the same bottom hole location by drilling new
wells. We incurred exploration costs of $2.4 million in 2008 compared
to $0.7 million and $3.8 million in 2007 and 2006, respectively. These costs
consist primarily of geological and geophysical costs in DJ. Due to
the release of our rigs we performed an impairment test which resulted in $2.6
million of impairment costs resulting from the impairment of one
rig. Additionally, we performed an impairment test of our oil and gas
assets at December 31, 2008 in accordance with SFAS 144 and determined that no
impairment was necessary.
In 2007
we had dry hole, abandonment, impairment and exploration charges of $13.7
million that consisted primarily of a $4.6 million writedown on 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 which were sold in
September 2007, geological and geophysical costs of $0.7 million and other dry
hole charges of $2.2 million.
In 2006,
there was $8.3 million of dry hole, abandonment and impairment charges that
consisted 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 Uinta
drilled for approximately $1.6 million net to our interest and four wells in
Bakken and four wells in DJ for $1.5 million.
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. We completed the
sale of a portion of our Tri-State acreage during the fourth quarter of 2007 and
have classified $1.4 million as held for sale at December 31, 2007 which
reflects additional acreage that we sold in the first quarter of 2008 in
accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets.
Short-term
lines of credit
In 2005,
we completed an unsecured uncommitted money market line of credit (Line of
Credit). Borrowings under the Line of Credit may be up to $30 million for a
maximum of 30 days and are subject to the borrowing base under the Company’s
senior credit facility. The Line of Credit may be terminated at any
time upon written notice by either us or the lender. In conjunction
with the amendment to our senior secured credit facility, on July 15, 2008, the
Line of Credit was secured by our assets. At December 31, 2008 and
2007, the outstanding balance under this Line of Credit was $25.3 million and
$14.3 million, respectively. Interest on amounts borrowed is charged at LIBOR
plus a margin of approximately 1%. The weighted average interest rate on
outstanding borrowings on the Line of Credit at December 31, 2008 and 2007 was
1.4% and 5.7%, respectively. Covenants under this agreement match the covenants
under our senior secured revolving credit facility.
In July,
2008, we completed a $100 million senior unsecured credit facility that was to
mature on December 31, 2008. We terminated this credit facility
without penalty in October 2008.
Senior
Secured Revolving Credit Facility
On July
15, 2008, we entered into a five year amended and restated credit agreement (the
Agreement) with Wells Fargo Bank, N.A. as administrative agent and other
lenders. This agreement was amended on October 17, 2008, as noted below. The
July 15, 2008 Agreement amended and restated the Company’s previous credit
agreement dated as of April 28, 2006. The Agreement is a revolving
credit facility for up to $1.5 billion with a borrowing base of $1.0
billion. The outstanding Line of Credit reduces our borrowing
capacity available under the Agreement. The borrowing base under the
April 28, 2006 agreement was $650 million. Interest on amounts
borrowed under this debt was charged at LIBOR plus a margin of 1.125% to 1.875%
or the prime rate, with margins on the various rate options based on the ratio
of credit outstanding to the borrowing base. An annual
commitment fee of .25% to .375% was charged on the unused portion of the credit
facility.
On
October 17, 2008, we further amended our $1.5 billion credit facility with the
Company’s syndicate of banks which increased our borrowing base from $1.0
billion to $1.25 billion with commitments of $1.08 billion and a new maturity
date of July 15, 2012. Commitments were increased during the fourth
quarter of 2008 with the addition of $130 million in commitments bringing the
total commitments under the facility to $1.21 billion from 19 banks. The
amendment includes an accordion feature which allows the Company to increase
borrowing commitments to $1.25 billion without further bank approval, and
modifies the annual commitment fee and interest rate
margins. Interest on amounts borrowed under the facility is charged
at LIBOR or the prime rate plus a margin. The LIBOR and prime rate
margins range between 1.375% and 2.125% based on the ratio of credit outstanding
to the borrowing base. Additionally, an annual commitment fee of .30%
to .50% is charged on the unused portion of the credit facility. The
deferred costs of approximately $10.8 million associated with the issuance of
this credit facility and $0.6 million associated with the issuance of the
previous credit facility are being amortized over the four year life of the
Agreement. The total deferred costs under this facility and the previous
facility were $10.6 million as of December 31, 2008. A charge of $0.1
million was recorded on the income statement as a loss on debt extinguishment
during the third quarter of 2008 related to parties who reduced their commitment
or chose not to participate in the Agreement.
The total
outstanding debt at December 31, 2008 under the Agreement and the Line of Credit
was $932 million and $25 million, respectively, and $8 million in letters of
credit have been issued under the facility, leaving $245 million in borrowing
capacity available under the Agreement. The maximum amount available
is subject to semi-annual redeterminations of the borrowing base, based on the
value of our proved oil and gas reserves, in April and October of each year in
accordance with the lender’s customary procedures and practices. Both
we and the banks have the bilateral right to one additional redetermination each
year.
See Note
21 related to changes in the terms of our Senior secured credit facility in
February 2009.
Senior
Subordinated 8.25% NotesDue 2016
In 2006,
we issued in a public offering $200 million of 8.25% senior subordinated notes
due 2016 (the Notes). Interest on the Notes is paid semiannually in
May and November of each year. The deferred costs of approximately $5
million associated with the issuance of this debt are being amortized over the
ten year life of the Notes and the remaining balance as of December 31, 2008 was
$4 million. The net proceeds from the offering were used to 1) repay
approximately $145 million of borrowings under the bank credit facility, which
were $170 million as of the issuance date after the application of this payment,
and 2) approximately $50 million to finance the November 2006 installment under
the joint venture agreement to develop properties in Piceance. 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.
The
senior secured revolving credit facility contains restrictive covenants which,
among other things, require us to maintain a debt to EBITDA ratio of not greater
than 3.5 to 1.0 and a minimum current ratio, as defined, of 1.0. See Note
21 - Subsequent Events. The non-cash financial statement impact of hedging
is excluded from the calculation of both ratios and all of the availability
under the senior credit facility is added to current assets when computing the
current ratio. The $200 million Notes are subordinated to our credit
facility and line of credit indebtedness. Under the Notes, as long as the
interest coverage ratio (as defined) is greater than 2.5 times, we may incur
additional debt. Our covenant ratios for the two years ended December 31, 2008,
were as follows:
|
|
2008
|
|
|
2007
|
|
Current
Ratio (Not less than 1.0)
|
|
|
|
|
|
|
|
|
EBITDA
To Total Funded Debt Ratio (Not greater than 3.5)
|
|
|
|
|
|
|
|
|
Interest
Coverage Ratio (Not less than 2.5)
|
|
|
|
|
|
|
|
|
We were
in compliance with all such covenants as of December 31, 2008 and
2007.
Interest
Rates and Interest Rate Hedges
Additionally,
in 2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility for five years beginning on September 29, 2006. In 2008, the
term on $50 million of these swaps was extended by one year. These
interest rate swaps have been designated as cash flow hedges. In
2008, $50 million of these interest rate swaps were extended one year, resulting
in a fixed rate of approximately 4.8%.
In 2008
we entered into three year interest rate swaps totaling $275 million for a fixed
rate averaging approximately 2.2% on an additional $275 million of our
outstanding borrowings under our credit facility for three years beginning on
April and September 15, 2009. These interest rate swaps have been
designated as cash flow hedges.
As of
December 31, 2008, we had a total of $575 million of fixed rate positions
averaging 4.8% resulting from the $200 million of 8.25% senior subordinated
notes and $375 million of interest rate swaps for a fixed rate of approximately
2.2%.
The
weighted average interest rate on total outstanding borrowings at December 31,
2008 and 2007 was 4.9% and 5.7%, respectively, excluding the effect of interest
rate hedges.
In March
2006, our Board of Directors approved a two-for-one stock split to shareholders
of record on May 17, 2006, subject to obtaining shareholder approval of an
increase in our authorized shares. On May 17, 2006, our shareholders approved
the authorized share increase and in June 2006 each shareholder received one
additional share for each share in the shareholder's possession on May 17, 2006.
This did not change the proportionate interest a shareholder maintained in Berry
Petroleum Company on May 17, 2006. All historical shares, equity awards and per
share amounts have been restated for the two-for-one stock split.
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 $0.50 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 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 or 2008.
Dividends
Our
regular annual dividend is currently $0.30 per share, payable quarterly in
March, June, September and December. We paid a special dividend of $0.02 per
share on September 29, 2006 and increased our regular quarterly dividend by 15%,
from $0.065 to $0.075 per share beginning with the September 2006
dividend.
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.
Shareholder
Rights Plan
In
November 1999, we adopted a Shareholder Rights Agreement and declared a dividend
distribution of one Right for each outstanding share of Capital Stock on
December 8, 1999. Each Right, when exercisable, entitles the holder to purchase
one one-hundredth of a share of a Series B Junior Participating Preferred Stock,
or in certain cases other securities, for $19.00. The exercise price and number
of shares issuable are subject to adjustment to prevent dilution. The Rights
would become exercisable, unless earlier redeemed by us 10 days following a
public announcement that a person or group has acquired, or obtained the right
to acquire, 20% or more of the outstanding shares of Common Stock, or 10
business days following the commencement of a tender or exchange offer for such
outstanding shares which would result in such person or group acquiring 20% or
more of the outstanding shares of Common Stock, either event occurring without
the prior consent of us.
The
Rights will expire on December 8, 2009 or may be redeemed by us at $0.005 per
Right prior to that date, unless they have theretofore become exercisable. The
Rights do not have voting or dividend rights, and until they become exercisable,
have no diluting effect on our earnings. A total of 500,000 shares of our
Preferred Stock has been designated Series B Junior Participating Preferred
Stock and reserved for issuance upon exercise of the Rights.
9.
|
Asset
Retirement Obligations (AROs)
|
Inherent
in the fair value calculation of AROs are numerous assumptions and judgments
including: the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement, and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to
these assumptions impact the fair value of the existing ARO liability, a
corresponding adjustment is made to the oil and gas property balance. In 2007,
we reassessed our estimate as costs increased due to demand for these services,
resulting in an increase in the ARO balance at year end. As of
December 31, 2008, we did not have any asset retirement obligations for which no
liability has been accrued.
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the years ended December 31 (in thousands):
|
|
2008
|
|
|
2007
|
|
Beginning
balance at January 1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
in estimated liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance at December 31
|
|
|
|
|
|
|
|
|
Of the
$38.7 million recorded in bad debt expense for the year ended December 31, 2008,
$38.5 million relates to the allowance for bad debt taken for the bankruptcy of
BWOC with the remainder due to the bankruptcy of SemCrude earlier in
2008.
In
December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and
its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter
11 of the United States Bankruptcy Code. Also in December 2008, BWOC
informed the Company that it was unable to receive the Company’s
production. We have entered into various short-term agreements with
other companies to sell our California oil production. Pricing and
volumes under these agreements vary with prices ranging from just above the
posted price for San Joaquin heavy oil to the posted price less a
discount. In January 2009, our California crude oil daily production
was, on average, near levels achieved prior to BWOC’s Chapter 11
filing. BWOC is evaluating several options, including a sale of the
Bakersfield, California refinery. We recorded $38.5 million of bad
debt expense in 2008 for the bankruptcy of BWOC. Of the $38.5 million
due from BWOC, $12.4 million represents December crude oil sales by the Company
and represents an administrative claim under the bankruptcy proceedings and
$26.1 million represents November crude oil sales which would have the same
priority as other general unsecured claims. BWOC will also be liable
to us for damages under this contract for any amounts received by us under our
short-term contracts which are less than what we would have otherwise received
from BWOC had they been able to accept our production. We have
guarantees from Big West Oil and from Flying J, Inc. in the amount of $75
million each, in the event that our claim is not fully collectible from
BWOC. While we believe that we may recover some or all of the amounts
due from BWOC, the data received from the bankruptcy proceedings to date has not
provided us with adequate data from which to make a conclusion that any amounts
will be collected nor as to whether BWOC will assume or reject our
contract.
On July
15, 2008, the Company acquired certain interests in natural gas producing
properties on 4,500 net acres in Limestone and Harrison Counties in East
Texas for $668 million cash (E. Texas Acquisition) including an initial purchase
price of $622 million and normal post closing adjustments of $46
million.
The
unaudited pro forma results presented below for the years ended December 31,
2008 and 2007 have been prepared to give effect to the E. Texas Acquisition on
the Company’s results of operations under the purchase method of accounting as
if it had been consummated at the beginning of each of the periods
presented. The unaudited pro forma results do not purport to
represent the results of operations that actually would have occurred on such
date or to project the Company’s results of operations for any future date or
period:
|
|
Year Ended December 31,
2008
|
|
|
Year Ended December 31,
2007
|
|
Pro
forma revenue
|
|
$ |
854,237 |
|
|
$ |
616,835 |
|
Pro
forma income from operations
|
|
$ |
217,398 |
|
|
$ |
164,447 |
|
Pro
forma net income
|
|
$ |
138,432 |
|
|
$ |
105,657 |
|
Pro
forma basic earnings per share
|
|
$ |
3.11 |
|
|
$ |
2.40 |
|
Pro
forma diluted earnings per share
|
|
$ |
3.05 |
|
|
$ |
2.36 |
|
The
following is a calculation and allocation of purchase price to the E. Texas
Acquisition assets and liabilities based on their relative fair values, as
determined by the valuation of proved reserves and related assets as of the
acquisition date:
Purchase
price (in thousands):
|
|
As of
December 31, 2008
|
|
|
Original
purchase price
|
|
$ |
622,356 |
|
|
|
|
|
|
|
|
Closing
adjustments for property costs, and operating expenses in excess of
revenues between the effective date and closing date
|
|
|
45,506 |
|
|
|
|
|
|
|
|
Total
purchase price allocation
|
|
$ |
667,862 |
|
|
|
|
|
|
|
|
Allocation
of purchase price (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas properties
|
|
$ |
651,659 |
|
(i)
|
Pipeline
|
|
|
17,277 |
|
|
Tax
receivable
|
|
|
1,476 |
|
|
|
|
|
|
|
|
Total
assets acquired
|
|
|
670,412 |
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
(1,195 |
) |
(ii)
|
Asset
retirement obligation
|
|
|
(1,355 |
) |
|
|
|
|
|
|
|
Net
assets acquired
|
|
$ |
667,862 |
|
|
(i) Determined
by reserve analysis.
(ii) Accrual
for royalties payable.
The
provision for income taxes consists of the following (in
thousands):
The
following table summarizes the components of the total deferred tax assets and
liabilities before financial statement offsets. The components of the net
deferred tax liability consist of the following at December 31 (in
thousands):
|
|
2008
|
|
|
2007
|
|
Deferred
tax asset:
|
|
|
|
|
|
|
Federal
benefit of state taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
deferred tax liability
|
|
|
|
|
|
|
|
|
At
December 31, 2008, our net deferred tax assets and liabilities were recorded as
a current liability of $45.5 million and a long-term liability of $270.4
million. At December 31, 2007, our net deferred tax assets and liabilities were
recorded as a current asset of $28.5 million and a long-term liability of $128.8
million.
Reconciliation
of the statutory federal income tax rate to the effective income tax rate
follows:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Tax
computed at statutory federal rate
|
|
|
35
|
% |
|
|
35
|
% |
|
|
35
|
% |
State
income taxes, net of federal benefit
|
|
|
4 |
|
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
(2
|
) |
|
|
(2
|
) |
|
|
(1
|
) |
|
|
|
37
|
% |
|
|
38
|
% |
|
|
39
|
% |
We have
approximately $24 million of federal and $17 million of state (California) EOR
tax credit carryforwards available to reduce future income taxes. The EOR
credits will begin to expire, if unused, in 2024 and 2015 for federal and
California purposes, respectively.
In June
2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income
Taxes—an interpretation of FASB Statement No. 109, Accounting for Income
Taxes. The Interpretation addresses the determination of whether tax
benefits claimed or expected to be claimed on a tax return should be recorded in
the financial statements. Under FIN No. 48, we may recognize the tax benefit
from an uncertain tax position only if it is more likely than not that the tax
position will be sustained on examination by the taxing authorities, based on
the technical merits of the position. The tax benefits recognized in the
financial statements from such a position should be measured based on the
largest benefit that has a greater than fifty percent likelihood of being
realized upon ultimate settlement. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes,
accounting in interim periods and requires increased disclosures.
As of
December 31, 2008, we had a gross liability for uncertain tax benefits of $12
million of which $10 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. We had accrued
approximately $1.2 million and $1.1 million of interest related to our uncertain
tax positions as of December 31, 2008 and 2007, respectively.
We
anticipate the balance of our unrecognized tax benefits could be reduced during
the next 12 months as the IRS finalizes certain examinations which are in
progress, however, we cannot reasonably estimate the impact of the examination
at this time.
For the
year ended December 31, 2008 we recognized a net benefit of approximately $1.6
million to the Statements of Income due to the closure of certain federal and
state tax years, offset by additional FIN 48 accruals net of interest expense of
approximately $1.9 million.
For the
year ended December 31, 2007 we recognized a net benefit of approximately $0.6
million to the Statements of Income due to the closure of certain federal and
state tax years, offset by additional FIN 48 accruals net of interest expense of
approximately $0.2 million.
The
following table illustrates changes in our gross unrecognized tax benefits (in
millions):
|
|
|
|
|
|
|
Unrecognized
tax benefits at January 1
|
|
$ |
12.0 |
|
|
$ |
14.6 |
|
Increases
for positions taken in current year
|
|
|
1.2 |
|
|
|
0.5 |
|
Increases
for positions taken in a prior year
|
|
|
0.3 |
|
|
|
(.3
|
) |
Decreases
for settlements with taxing authorities
|
|
|
- |
|
|
|
- |
|
Decreases
for lapses in the applicable statute of limitations
|
|
|
(1.5
|
) |
|
|
(2.8
|
) |
Unrecognized
tax benefits at December 31
|
|
$ |
12.0 |
|
|
$ |
12.0 |
|
As of
December 31, 2008, we remain subject to examination in the following major tax
jurisdictions for the tax years indicated below:
Jurisdiction:
|
Tax
Years Subject to Exam:
|
|
|
|
|
|
|
|
|
As of
December 31, 2008, all of our rig leases had either expired or were terminated
and the leasee did not exercise the bargain purchase option under the lease. The
$5.8 million in lease receivable was capitalized under property plant and
equipment as of December 31, 2008.
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, respectively. The total net
investment in these rigs is approximately $8.8 million at December 31, 2007.
Both agreements are accounted for as direct financing leases as defined by SFAS
No. 13, Accounting for
Leases. Net investment in both leases are included in the Balance Sheet
as other assets and as of December 31, 2007 are as follows (in
thousands):
Net
minimum lease payments receivable
|
|
|
|
|
|
|
|
|
|
Net
investment in direct financing lease
|
|
|
|
|
As of
December 31, 2007, estimated future minimum lease payments, including the
purchase option, to be received are as follows (in thousands):
14.
|
Commitments
and Contingencies
|
We have
no accrued environmental liabilities for our sites, including sites in which
governmental agencies have designated us as a potentially responsible party,
because it is not probable that a loss will be incurred and the minimum cost
and/or amount of loss cannot be reasonably estimated. However, because of the
uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be incurred. Management believes,
based upon current site assessments, that the ultimate resolution of any matters
will not result in substantial costs incurred. We are involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of our
business. In the opinion of management, the resolution of these matters will not
have a material effect on our financial position, or on the results of our
operations or liquidity.
During
the California energy crisis in 2000 and 2001, we had electricity sales
contracts with various utilities and a portion of the electricity prices paid to
us under such contracts from December 2000 to March 27, 2001 has been under a
degree of legal challenge since that time. It is possible that we may
have a liability pending the final outcome of the CPUC proceedings on the
matter. There are ongoing proceedings before the CPUC in which
Edison and PG&E are seeking credit against future payments they are to make
for electricity purchases based on retroactive adjustment to pricing under
contracts with us. Whether or not retroactive adjustments will be
ordered, how such adjustments would be calculated and what period they would
cover are too uncertain to estimate at this time.
Our
contractual obligations not included in our Balance Sheet as of December 31,
2008 (except Long-term debt and Abandonment obligations) are as follows (in
thousands):
|
|
Total
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
Long-term
debt and interest
|
|
$ |
1,471,383 |
|
|
$ |
82,211 |
|
|
$ |
56,558 |
|
|
$ |
56,558 |
|
|
$ |
56,558 |
|
|
$ |
969,998 |
|
|
$ |
249,500 |
|
|
|
|
41,967 |
|
|
|
1,643 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
1,642 |
|
|
|
33,756 |
|
Operating
lease obligations
|
|
|
18,328 |
|
|
|
2,373 |
|
|
|
2,390 |
|
|
|
2,436 |
|
|
|
2,446 |
|
|
|
2,493 |
|
|
|
6,190 |
|
Drilling
and rig obligations
|
|
|
47,049 |
|
|
|
12,789 |
|
|
|
8,030 |
|
|
|
8,030 |
|
|
|
18,200 |
|
|
|
- |
|
|
|
- |
|
Firm
natural gas transportation contracts
|
|
|
165,071 |
|
|
|
19,803 |
|
|
|
19,803 |
|
|
|
19,803 |
|
|
|
19,652 |
|
|
|
17,557 |
|
|
|
68,453 |
|
|
|
$ |
1,743,798 |
|
|
$ |
118,819 |
|
|
$ |
88,423 |
|
|
$ |
88,469 |
|
|
$ |
98,498 |
|
|
$ |
991,690 |
|
|
$ |
357,899 |
|
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,
2008, 2007 and 2006 was $1.7 million, $1.5 million and $1 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
- In the primary term (November 2004 to November 2009) of our
Utah Lake Canyon project, we have a 21 gross well drilling commitment.
To date, we have drilled 14 gross wells (9.8 net wells) under
theTribal Lake Canyon Exploration and Development Agreement
(EDA). We have 7 remaining commitment wells to drill in
Lake Canyon by the end of November 2009. Our minimum obligation
under our exploration and development agreement is $9.6 million, and as of
December 31, 2008 the remaining obligation is $2.4 million. Also included above,
under our June 2006 joint venture agreement in Piceance, we are required to have
120 wells drilled by February 2011 to avoid penalties of $0.2 million per well
or a maximum of $24 million. As of December 31, 2008 we have drilled 29 of these
wells.
Drilling rig
obligations - We are obligated in operating lease agreements for the use
of two drilling rigs, one of which resulted from the July 2008 E. Texas
Acquisition (see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations).
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 -
On February 27, 2007, we entered into a multi-staged crude oil sales
contract with a refiner for our Uinta light crude oil. Under the agreement, the
refiner began purchasing 3,200 Bbl/D on July 1, 2007. After partial completion
of its refinery expansion in Salt Lake City in March 2008, the refiner increased
its total purchase capacity to 5,000 Bbl/D. This contract is in
effect through June 30, 2013. Pricing under the contract, which
includes transportation and gravity adjustments, is at a fixed percentage of
WTI, which ranges from $10 to $15 at WTI prices between $40 and $60. This
contract is our only sales contract for our Uinta oil.
15.
|
Equity
Compensation Plans
|
In
December 1994, our Board of Directors adopted the Berry Petroleum Company 1994
Stock Option Plan which was restated and amended in December 1997 and December
2001 (the 1994 Plan or Plan) and approved by the shareholders in May 1998 and
May 2002, respectively. The 1994 Plan provided for the granting of stock options
to purchase up to an aggregate of 3,000,000 shares of Common Stock. All options,
with the exception of the formula grants to non-employee Directors, were granted
at the discretion of the Compensation Committee and the Board of Directors. The
term of each option did not exceed ten years from the date the options were
granted. The 1994 Plan expired in December 2004, and the shareholders approved a
new equity incentive plan in May 2005.
The 2005
Equity Incentive Plan (the 2005 Plan), approved by the shareholders in May 2005,
provides for granting of equity compensation up to an aggregate of 2,900,000
shares of Common Stock. All equity grants are at market value on the date of
grant and at the discretion of the Compensation Committee or the Board of
Directors. The term of each grant did not exceed ten years from the grant date,
and vesting has generally been at 25% per year for 4 years or 100% after 3
years. The 2005 Plan also allows for grants to non-employee Directors. The
grants made to the non-employee Directors vest immediately. We use a broker for
issuing new shares upon option exercise.
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 No. 148, Accounting for Stock-Based
Compensation - Transition and Disclosure. Under this method, we
recognized stock option compensation expense as if we had applied the fair value
method to account for unvested stock options from the original effective date.
Total compensation cost recognized in the Statements of Income was $8.9 million,
$8.4 million and $6.1 million in 2008, 2007 and 2006, respectively. The tax
benefit related to this compensation cost was $3.8 million, $3.3 million and
$2.4 million in 2008, 2007 and 2006, respectively.
Stock
Options
The fair
value of each stock option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the assumptions noted in the
following table. Expected volatilities are based on the historical volatility of
our stock. We use historical data to estimate option exercises and employee
terminations within the valuation model; separate groups of recipients that have
similar historical exercise behavior are considered separately for valuation
purposes. The expected term of options granted is based on historical exercise
behavior and represents the period of time that options granted are expected to
be outstanding; the range given below results from certain groups of recipients
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. During 2008, the non-employee Directors did not
receive any options.
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
36 |
% |
|
|
32%
- 33 |
% |
|
|
32%
- 33 |
% |
Weighted-average
volatility
|
|
|
36 |
% |
|
|
33 |
% |
|
|
32 |
% |
|
|
|
1 |
% |
|
|
1 |
% |
|
|
.8%
- 1.0 |
% |
|
|
|
5 |
|
|
|
4.9
- 5.6 |
|
|
|
5.3
- 5.5 |
|
|
|
|
3.2 |
% |
|
|
3.4%
- 4.7 |
% |
|
|
4.5%
- 4.8 |
% |
The
following table summarizes information related to stock options outstanding and
exercisable as of December 31, 2008:
Range
of Exercise Prices
|
|
Options
Outstanding
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Remaining Contractual Life
|
|
|
Options
Exercisable
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Remaining Contractual Life
|
|
|
|
|
682,650 |
|
|
$ |
10.42 |
|
|
|
4.4 |
|
|
|
682,650 |
|
|
$ |
10.42 |
|
|
|
4.4 |
|
|
|
|
490,500 |
|
|
|
21.60 |
|
|
|
5.9 |
|
|
|
478,000 |
|
|
|
21.60 |
|
|
|
5.9 |
|
|
|
|
933,551 |
|
|
|
31.85 |
|
|
|
7.5 |
|
|
|
590,900 |
|
|
|
31.54 |
|
|
|
7.5 |
|
|
|
|
316,199 |
|
|
|
42.75 |
|
|
|
9.1 |
|
|
|
90,982 |
|
|
|
42.99 |
|
|
|
8.8 |
|
|
|
|
2,422,900 |
|
|
$ |
25.16 |
|
|
|
6.5 |
|
|
|
1,842,532 |
|
|
$ |
21.70 |
|
|
|
6.0 |
|
Weighted
average option exercise price information for the years ended December
31:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
during the year
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancelled/expired
during the year
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following is a summary of stock option activity for the years ended December
31:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Balance
outstanding, January 1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
outstanding, December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available
for future grant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average remaining contractual life (years)
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average fair value per option granted during the year based on the
Black-Scholes pricing model
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
December 31, 2008, there was $5.2 million of total unrecognized compensation
cost related to stock options granted under the Plan. This cost is expected to
be recognized over a weighted-average period of 1.4 years. The tax benefit
realized from stock options exercised during the year ended December 31, 2008,
2007 and 2006 is $1.4 million, $3.5 million and $4.3 million,
respectively.
|
|
Stock Options
|
|
|
|
Year
ended
|
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
Weighted
average fair value per option granted during the year based on the
Black-Scholes pricing model
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
intrinsic value of options exercised (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
intrinsic value of options outstanding (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
intrinsic value of options exercisable (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
Stock Units
Under the
2005 Equity Plan, we began a long-term incentive program whereby restricted
stock units (RSUs) are available for grant to certain employees and non-employee
Directors. Granted RSUs generally vest at either 25% per year over 4 years or
100% after 3 years. Unearned compensation under the restricted stock award plan
is amortized over the vesting period. During 2008, the non-employee
Directors did not receive any RSUs. The RSUs granted to the non-employee
Directors are 100% vested at date of grant but are subject to a deferral
election before the corresponding shares are issued of a minimum of four years
or until they leave the Board of Directors or upon change of control. We pay
cash compensation on the RSUs in an equivalent amount of actual dividends paid
on a per share basis of our outstanding common stock.
The
following is a summary of RSU activity for the year ended December 31,
2008:
|
|
RSUs
|
|
|
Weighted Average Intrinsic Value at Grant Date
|
|
Weighted Average Contractual Life
Remaining
|
Balance
outstanding, January 1
|
|
|
506,923 |
|
|
$ |
34.84 |
|
|
|
|
|
572,102 |
|
|
|
11.26 |
|
|
|
|
|
(73,414
|
) |
|
|
33.95 |
|
|
|
|
|
(39,413
|
) |
|
|
37.58 |
|
|
Balance
outstanding, December 31
|
|
|
966,198 |
|
|
$ |
20.83 |
|
|
|
|
|
|
|
RSUs Year ended
|
|
|
|
|
|
|
December 31, 2008
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
Weighted-average
grant date fair value of RSUs issued
|
|
$ |
11.26 |
|
|
$ |
42.36 |
|
|
$ |
31.86 |
|
Total
value of RSUs vested (in millions)
|
|
|
.8 |
|
|
|
2.1 |
|
|
|
1.0 |
|
The total
compensation cost related to nonvested awards not yet recognized on December 31,
2008 is $13.3 million and the weighted average period over which this cost is
expected to be recognized is 1.5 years.
We
sponsor a defined contribution thrift plan under section 401(k) of the Internal
Revenue Code to assist all employees in providing for retirement or other future
financial needs. In December 2005, the 401(k) Plan was amended whereby effective
January 1, 2006, our matching contribution is $1.00 for each $1.00 contributed
by the employee up to 8% of an employee's eligible compensation. Our
contributions to the 401(k) Plan, net of forfeitures, were $1.4 million, $1.4
million and $1.2 million for 2008, 2007 and 2006, respectively. Employees are
eligible to participate in the 401(k) Plan on their date of hire and
approximately 92% of our employees participated in the 401(k) Plan in
2008.
17.
|
Director
Deferred Compensation Plan
|
We
established a non-employee director deferred stock and compensation plan to
permit eligible directors, in recognition of their contributions to us, to
receive compensation for service and to defer recognition of their compensation
in whole or in part to a Stock Unit Account or an Interest Account. When the
eligible director ceases to be a director, the distribution from the Stock Unit
Account shall be made in shares using an established market value date. The
distribution from the Interest Account shall be made in cash. The aggregate
number of shares which may be issued to eligible directors under the plan shall
not exceed 500,000, subject to adjustment for corporate transactions that change
the amount of outstanding stock. The plan may be amended at any time, but not
more than once every six months, by the Compensation Committee or the Board of
Directors. Shares earned and deferred in accordance with the plan as of December
31, 2008, 2007 and 2006 were 23,312, 12,866 and 13,387,
respectively.
Amounts
allocated to the Stock Unit Account have the right to receive an amount equal to
the dividends per share we declare as applicable. The dividend payment date and
this “dividend equivalent” shall be treated as reinvested in an additional
number of units and credited to their account using an established market value
date. Amounts allocated to the Interest Account are credited with interest at an
established interest rate.
From time
to time we enter into crude oil and natural gas hedge contracts, the terms of
which depend on various factors, including management’s view of future crude oil
and natural gas prices and our future financial commitments. This hedging
program is designed to moderate the effects of a severe crude oil price downturn
and protect certain operating margins in our California operations. Currently,
the hedges are in the form of swaps and collars, however, we may use a variety
of hedge instruments in the future. 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 or other price
protection is appropriate. All of these hedges have historically been deemed to
be cash flow hedges with the marked-to-market valuations provided by external
sources, based on prices that are actually quoted.
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. We are not required to issue
collateral on these hedging transactions. Additionally, our valuation of
derivatives reflects an adjustment for the credit risk for each party based on
credit default swaps when such data is available and historical default rates
when such data is not available. As of December 31, 2008 and 2007, we
recorded a credit risk reduction of $632 thousand and $0, respectively, to the
Fair value of derivatives asset.
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 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. We
recognized an unrealized net gain of $5.6 million in 2006. The net gain of $0.8
million was recorded in other accumulated comprehensive income (loss) at the
date the hedges were designated and will be amortized to revenue as the related
sales occur.
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 for five years. These interest rate swaps have been
designated as cash flow hedges. In 2008, $50 million of these
interest rate swaps were extended one year, resulting in a fixed rate of
approximately 4.8%.
In 2008
we also entered into three year interest rate swaps for a fixed rate of
approximately 2.2% on an additional $275 million of our outstanding borrowings
under our credit facility for three years beginning on April and September 15,
2009. These interest rate swaps have been designated as cash flow
hedges.
The
related cash flow impact of our derivative activities are reflected as cash
flows from operating activities. At December 31, 2008, our net fair value of
derivatives asset was $185.9 million as compared to a derivatives liability of
$201.6 million at December 31, 2007. Based on NYMEX strip pricing as of December
31, 2008, we expect to receive hedge payments under the existing derivatives of
$120.5 million during the next twelve months. At December 31, 2008 and 2007,
Accumulated Other Comprehensive Income (Loss) consisted of an unrealized gain of
$113.7 million and an unrealized loss of $120.7 million, respectively, net of
tax, from our crude oil, natural gas and interest swaps and collars that
qualified for hedge accounting treatment at December 31, 2008. Deferred net
gains recorded in Accumulated Other Comprehensive Income (Loss) at December 31,
2008 and subsequent marked-to-market changes in the underlying hedging contracts
are expected to be reclassified to earnings over the life of these
contracts.
Most of
our oil hedges are based on the West Texas Intermediate (WTI) index and our
California oil sales contract with BWOC is tied to WTI which has allowed us to
qualify for hedge accounting and effectively hedge our
production. Our interim sales contracts are primarily based on the
field posting price and we are therefore subject to potential
ineffectiveness. There is a high correlation between WTI and the
field posting prices which allowed us to continue hedge
accounting. Additionally, under the dollar offset method, we did not
have any ineffectiveness under these contracts.
19.
|
Master
Limited Partnership
|
On
October 22, 2007, we announced plans to form a master limited partnership (MLP).
We decided not to proceed with this plan due to unfavorable capital market
conditions and expensed $0.6 million of legal and accounting fees during 2008
under the caption “general and administrative” in the Statements of Income
related to the formation of the MLP.
20.
|
Related
Party Transaction
|
In
December 2007, we accepted a tender issued by Bakersfield Fuel & Oil Company
(BFO) to purchase all of our shares in BFO for $2.9 million. These proceeds are
reflected in the “Proceeds from sale of assets” line on the Statements of Cash
Flows and in the “Gain on sale of assets” line on the Statements of Income.
Mr. Thomas Jamieson is a Director of Berry Petroleum Company and a
director and the controlling stockholder of BFO. The tender was made to all
shareholders of BFO other than Mr. Jamieson and his affiliates. The
Corporate Governance and Nominating Committee, with input from the Audit
Committee, approved this transaction.
On
February 19, 2009, the company executed an amendment to its senior secured
credit facility which, among other things, increased the maximum EBITDAX to
total funded debt ratio to 4.75 through year-end 2009, to 4.50 through year-end
2010 and to 4.0 thereafter. A new senior secured debt to EBITDAX
covenant limits the maximum EBITDAX to outstanding debt under our senior secured
credit facility to 3.75 through September 2010, 3.5 from October 2010 through
March 2011, 3.25 from April 2011 through September 2011 and 3.0
thereafter. Additionally, the write off of $38.5 million to bad debt
expense associated with the bankruptcy of Big West will be excluded from the
calculation of EBITDAX. The LIBOR and prime rate margins increased to
between 2.25% and 3.0% based on the ratio of credit outstanding to the borrowing
base. Additionally, the annual commitment fee on the unused portion
of the credit facility increased to 0.50%, regardless of the amount
outstanding. The deferred costs of this amendment of $4.5 million
will be amortized over the remaining term of the facility.
22.
|
Quarterly
Financial Data (Unaudited)
|
The
following is a tabulation of unaudited quarterly operating results for 2008 and
2007 (in thousands, except per share data).
2008
|
|
Operating Revenues
|
|
|
Income
(Loss) Before Taxes
|
|
|
Net Income(Loss)
|
|
|
Basic
Net Income(Loss) Per
Share
|
|
|
Diluted
Net Income(Loss) Per
Share
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
|
|
|
|
|
|
|
|
|
(1) Includes
$38.5 million of bad debt expense related to the allowance for bad debt taken
for the bankruptcy of BWOC.
23.
|
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)
|
The
following sets forth costs incurred for oil and gas property acquisition,
development and exploration activities, whether capitalized or expensed (in
thousands):
Property
acquisitions
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Development costs include $0.1
million, $1.2 million and $0.5 million charged to expense during 2008,
2007 and 2006, respectively.
|
(2)
|
Exploration costs include $2.4
million, $5.2 million and $3.8 million that were charged to expense during
2008, 2007 and 2006, respectively. Exploration costs include $23.2 million
and $18.1 million of capitalized interest in 2008 and 2007, respectively.
|
The
following sets forth results of operations from oil and gas producing and
exploration activities (in thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Sales
to unaffiliated parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of operations from producing and exploration
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent our owned interests located solely within the United
States. Proved reserves represent estimated quantities of crude oil and natural
gas which geological and engineering data demonstrated with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed oil and gas reserves are the
quantities expected to be recovered through existing wells with existing
equipment and operating methods. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells for which relatively major expenditures are required for
completion.
The
following disclosures of oil and gas reserves are based on estimates prepared by
independent engineering consultants as of December 31, 2008, 2007 and 2006. Such
estimates are subject to numerous uncertainties inherent in the estimation of
quantities of proved reserves and in the projection of future rates of
production and the timing of development expenditures. These estimates do not
include probable or possible reserves. The information provided does not
represent management's estimate of our expected future cash flows or value of
proved oil and gas reserves.
Changes
in estimated reserve quantities
The net
interest in estimated quantities of proved developed and undeveloped reserves of
crude oil and natural gas at December 31, 2008, 2007 and 2006, and changes in
such quantities during each of the years then ended were as follows (in
thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
|
Mbbl
|
|
|
MMcf
|
|
|
MBOE
|
|
|
Mbbl
|
|
|
MMcf
|
|
|
MBOE
|
|
|
Mbbl
|
|
|
MMcf
|
|
|
MBOE
|
|
Proved
developed and Undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
116,602 |
|
|
|
315,464 |
|
|
|
169,179 |
|
|
|
112,538 |
|
|
|
226,363 |
|
|
|
150,262 |
|
|
|
103,733 |
|
|
|
135,311 |
|
|
|
126,285 |
|
Revision
of previous estimates
|
|
|
(10,211
|
) |
|
|
(41,570
|
) |
|
|
(17,139
|
) |
|
|
(3,826
|
) |
|
|
3,358 |
|
|
|
(3,262
|
) |
|
|
(512
|
) |
|
|
(222
|
) |
|
|
(553
|
) |
|
|
|
7,600 |
|
|
|
- |
|
|
|
7,600 |
|
|
|
4,500 |
|
|
|
- |
|
|
|
4,500 |
|
|
|
11,900 |
|
|
|
- |
|
|
|
11,900 |
|
Extensions
and discoveries
|
|
|
18,700 |
|
|
|
145,800 |
|
|
|
43,000 |
|
|
|
17,300 |
|
|
|
101,400 |
|
|
|
34,200 |
|
|
|
4,100 |
|
|
|
78,000 |
|
|
|
17,100 |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6,700
|
) |
|
|
- |
|
|
|
(6,700
|
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
(7,440
|
) |
|
|
(25,559
|
) |
|
|
(11,700
|
) |
|
|
(7,210
|
) |
|
|
(15,657
|
) |
|
|
(9,819
|
) |
|
|
(7,183
|
) |
|
|
(12,526 |
) |
|
|
(9,270
|
) |
Purchase
of reserves in place
|
|
|
- |
|
|
|
330,000 |
|
|
|
55,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
500 |
|
|
|
25,800 |
|
|
|
4,800 |
|
|
|
|
125251 |
|
|
|
724,135 |
|
|
|
245,940 |
|
|
|
116,602 |
|
|
|
315,464 |
|
|
|
169,179 |
|
|
|
112,538 |
|
|
|
226,363 |
|
|
|
150,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78,339 |
|
|
|
147,346 |
|
|
|
102,897 |
|
|
|
84,782 |
|
|
|
104,934 |
|
|
|
102,270 |
|
|
|
78,308 |
|
|
|
70,519 |
|
|
|
90,061 |
|
|
|
|
74,616 |
|
|
|
361,575 |
|
|
|
134,879 |
|
|
|
78,339 |
|
|
|
147,346 |
|
|
|
102,897 |
|
|
|
84,782 |
|
|
|
104,934 |
|
|
|
102,270 |
|
The
standardized measure has been prepared assuming year end sales prices adjusted
for fixed and determinable contractual price changes, current costs and
statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense. Cash outflows for future production and development costs
include those cash flows associated with the ultimate settlement of the asset
retirement obligation.
Standardized
measure of discounted future net cash flows from estimated production of proved
oil and gas reserves (in thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future
income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount for estimated timing of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales prices at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in standardized measure of discounted future net cash flows from proved oil and
gas reserves (in thousands):
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Standardized
measure - beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas produced, net of production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
to estimates of proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
changes in sales prices and production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of previous quantity estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions
and discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in estimated future development costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases
of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
costs incurred during the period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure - end of year
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
Evaluation
of Disclosure Controls and Procedures
As of
December 31, 2008, we have carried out an evaluation under the supervision of,
and with the participation of, our management, including our Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15
under the Securities Exchange Act of 1934, as amended.
Based on
their evaluation as of December 31, 2008, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of
1934) are effective to ensure that the information required to be disclosed by
us in the reports that we file or submit under the Securities Exchange Act of
1934 is recorded, processed, summarized and reported within the time periods
specified in SEC rules and forms.
Management’s
Report on Internal Control Over Financial Reporting
Internal
control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f)
promulgated under the Securities Exchange Act of 1934, as amended, as a process
designed by, or under the supervision of, our principal executive and principal
financial officers, or persons performing similar functions, and effected by our
Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external reporting purposes in accordance with U.S.
generally accepted accounting principles and includes those policies and
procedures that:
·
|
pertain
to the maintenance of records that in reasonable detail accurately and
fairly reflect the transactions and dispositions of our
assets;
|
·
|
provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of our management
and Directors; and
|
·
|
provide
reasonable assurance regarding prevention or the timely detection of
unauthorized acquisition, or the use or disposition of our assets that
could have a material effect on the financial
statements.
|
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. All internal control systems, no matter how
well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Additionally, projections of
any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).
Under the supervision and with the participation of management, including the
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on our evaluation under the framework in Internal Control - Integrated
Framework, management concluded that our internal control over financial
reporting was effective as of December 31, 2008.
The
effectiveness of the Company's internal control over financial reporting as of
December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.
Changes
in Internal Control Over Financial Reporting
There
were no changes in our internal control over financial reporting that occurred
during the three months ended December 31, 2008 that have materially affected,
or are reasonably likely to materially affect, our internal control over
financial reporting. We may make changes in our internal control procedures from
time to time in the future.
None.
PART
III
The
information called for by Item 10 is incorporated by reference from information
under the captions “Corporate Governance”, “Meetings and Committees of our
Board” and “Compliance with Section 16(a) of the Securities Exchange Act of
1934” in our definitive proxy statement to be filed pursuant to Regulation 14A
no later than 120 days after the close of our fiscal year. Information regarding
Executive Officers is contained in this report in Item 1 Business of this Form
10-K.
The
information called for by Item 11 is incorporated by reference from information
under the caption "Executive Compensation" in our definitive proxy statement to
be filed pursuant to Regulation 14A no later than 120 days after the close of
our fiscal year.
Item
12. Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The
information called for by Item 12 is incorporated by reference from information
under the captions "Security Ownership" and "Principal Shareholders" in our
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of our fiscal year and Item 5 Market for the
Registrant's Common Equity and Related Shareholder Matters and Issuer Purchases
of Equity Securities of this Form 10-K.
Item
13. Certain Relationships and Related Transactions, and Director
Independence
The
information called for by Item 13 is incorporated by reference from information
under the caption "Certain Relationships and Related Transactions" in our
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of our fiscal year.
Item
14. Principal
Accounting Fees and Services
The
information called for by Item 14 is incorporated by reference from the
information under the caption “Fees to Independent Registered Public Accounting
Firms for 2008 and 2007” in our definitive proxy statement to be filed pursuant
to Regulation 14A no later than 120 days after the close of our fiscal
year.
PART
IV
Item 15. Exhibits,
Financial Statement Schedules
A.
Financial Statements and Schedules
See Item
8 Index to Financial Statements and Supplementary Data in this Form
10-K.
B.
Exhibits
Exhibit
No.
|
Description
of Exhibit
|
|
|
3.1*
|
Registrant's
Amended and Restated Certificate of Incorporation (filed as Exhibit 3.1 to
the Registrant’s Quarterly Report on Form 10-Q for the period ended June
30, 2006, File No. 1-09735).
|
3.2*
|
Registrant's
Restated Bylaws dated July 1, 2005 (filed as Exhibit 3.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 2005, File No. 1-09735).
|
4.1*
|
First
Supplemental Indenture, dated as of October 24, 2006, between the
Registrant and Wells Fargo Bank, National Association as Trustee relating
to the Registrant's 8 1/4% Senior Subordinated Notes due 2016 (filed as
Exhibit 4.1 to the Registrant's Current Report on Form 8-K on October 25,
2006 File No. 1-9735).
|
4.2*
|
Registrant’s
8.25% Senior Subordinated Notes (filed as Form 425B5 on October 19,
2006).
|
4.3*
|
Registrant's
Certificate of Designation, Preferences and Rights of Series B Junior
Participating Preferred Stock (filed as Exhibit A to the Registrant's
Registration Statement on Form 8-A12B on December 7, 1999, File No.
778438-99-000016).
|
4.4*
|
Rights
Agreement between Registrant and ChaseMellon Shareholder Services, L.L.C.
dated as of December 8, 1999 (filed by the Registrant on Form 8-A12B on
December 7, 1999, File No. 778438-99-000016).
|
10.1*
|
Instrument
for Settlement of Claims and Mutual Release by and among Registrant,
Victory Oil Company, the Crail Fund and Victory Holding Company effective
October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1 to the
Registrant's Registration Statement on Form S-4 filed on May 22, 1987,
File No. 33-13240).
|
10.2*
|
Description
of Short-Term Cash Incentive Plan of Registrant (filed as Exhibit 10.1 to
the Registrant’s Annual Report on Form 10-K for the period ended December
31, 2006, File No. 1-0735).
|
|
|
10.3*
|
Form
of Change in Control Severance Protection Agreement dated August 24, 2006,
by and between Registrant and selected employees of the Company (filed as
Exhibit 99.1 to the Registrant’s Current Report on Form 8-K on August 24,
2006, File No. 1-9735).
|
10.4*
|
Amended
and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the
Registrant’s Registration Statement on Form S-8 filed on August 20, 2002,
File No. 333-98379).
|
10.5*
|
First
Amendment to the Registrant’s Amended and Restated 1994 Stock Option Plan
dated as of June 23, 2006 (filed as Exhibit 99.3 to the Registrant's
Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
10.6*
|
Berry
Petroleum Company 2005 Equity Incentive Plan (filed as Exhibit 4.2 to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
10.7*
|
Form
of the Stock Option Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 4.3 to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
10.8*
|
Form
of the Stock Appreciation Rights Agreement, by and between Registrant and
selected employees, directors, and consultants (filed as Exhibit 4.4 to
the Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
10.9*
|
Form
of Stock Award Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 99.4 to the
Registrant's Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
10.10*
|
Form
of Restricted Stock Award Agreement, by and between Registrant and
selected directors (filed as Exhibit 99.1 on Form 8-K filed on December
17, 2007, File No. 1-9735).
|
10.11*
|
Form
of Restricted Stock Award Agreement, by and between Registrant and
selected officers (filed as Exhibit 99.1on Form 8-K December 17, 2007,
File No. 1-9735).
|
10.12*
|
Non-Employee
Director Deferred Stock and Compensation Plan (as amended effective
January 1, 2006) (filed as Exhibit 10.13 to the Registrant’s Annual Report
on Form 10-K for the period ended December 31, 2005, File No.
1-09735).
|
10.13*
|
Amended
and Restated Employment Contract dated as of June 23, 2006 by and between
the Registrant and Robert F. Heinemann (filed as Exhibit 99.1 to
the Registrant's Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
10.14*
|
Stock
Award Agreement dated as of June 23, 2006 by and between the Registrant
and Robert F. Heinemann (filed as Exhibit 99.2 to the
Registrant's Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
10.15*
|
Employment
Agreement dated November 19, 2008 by and between Berry Petroleum Company
and David D. Wolf (Filed as Exhibit 10.1 in Registrant’s Form
8-K/A filed on November 21, 2008, File No. 1-9735)
|
10.16*
|
Employment
Agreement dated November 19, 2008 by and between Berry Petroleum Company
and Michael Duginski (filed as Exhibit 10.1 in Registrant’s Form
8-K/A filed on November 21, 2008, File No.
1-9735)
|
|
Credit
Agreement, dated as of June 27, 2005, by and between the Registrant and
Wells Fargo Bank, N.A. and other financial institutions (filed as Exhibit
10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2005, File No. 1-9735).
|
|
First
Amendment to Credit Agreement, dated as of December 15, 2005 by and
between the Registrant and Wells Fargo Bank, N.A. and other financial
institutions (filed as Exhibit 3.1 to the Registrant’s Annual Report on
Form 10-K for the period ended December 31, 2005, File No.
1-09735).
|
|
Second
Amendment to Credit Agreement, dated as of April 28, 2006 by and between
the Registrant and Wells Fargo Bank, N.A. and other financial institutions
(filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q
for the period ended March 31, 2006, File No.
1-09735).
|
|
Amended
and Restated Credit Agreement, dated as of July 15, 2008 by and between
the Registrant and Wells Fargo Bank, N.A. and other financial institutions
(filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q
for the period ended June 30, 2008, File No.
1-9735).
|
|
Credit
Agreement by and among Berry Petroleum Company, Societe Generale, SG
Americas Securities, LLC, BNP Paribas Securities Corp., BNP Paribas, and
other financial institutions date July 31, 2008 (filed as Exhibit 10.2 on
Form 10-Q for the period ended September 30, 2008, File No.
1-9735).
|
|
First
Amendment to Amended and Restated Credit Agreement, by and between Berry
Petroleum Company, Wells Fargo Bank, N.A. and other financial
institutions, dated as of October 17, 2008 (filed on October 17, 2008, as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K File No.
1-9735).
|
|
Joinder
Agreement dated November 13, 2008 by and among Berry Petroleum Company,
Wells Fargo Bank, N.A., and Bank of Montreal (filed as Exhibit 10.1in
Registrant’s Form 8-K filed on November 17, 2008, File No.
1-9735).
|
|
Joinder
Agreement dated December 2, 2008 by and among Berry Petroleum Company,
Wells Fargo Bank, N.A., and Calyon New York Branch (filed as Exhibit
10.1in Registrant’s Form 8-K filed on December 4, 2008, File No.
1-9735).
|
|
Crude
oil purchase contract, dated November 14, 2005 between Registrant and Big
West of California, LLC (filed as Exhibit 99.2 on Form 8-K filed on
November 22, 2005, File No. 1-9735).
|
|
Amended
and Restated Purchase and Sale Agreement between Registrant and Orion
Energy Partners, LP (filed as Exhibit 10.17 to the Registrant’s Annual
Report on Form 10-K for the period ended December 31, 2005, File No.
1-09735).
|
|
Carry
and Earning Agreement, dated June 7, 2006, between Registrant and EnCana
Oil & Gas (USA), Inc. (filed as Exhibit 99.2 on Form 8-K on June 19,
2006, File No. 1-9735).
|
|
Underwriting
Agreement dated October 18, 2006 by and between Registrant and the several
Underwriters listed in Schedule 1 thereto (filed as Exhibit 1.1 to the
Registrant’s Current Report on Form 8-K on October 19, 2006, File No.
1-9735).
|
|
Crude
Oil Supply Agreement between the Registrant and Holly Refining and
Marketing Company - Woods Cross (filed as Exhibit 10.22 to the
Registrant’s Annual Report on Form 10-K for the period ended December
31,2006, File No. 1-0735).
|
|
Purchase
and Sale Agreement between the Registrant and Venoco, Inc. dated March 19,
2007 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form
10-Q for the period ended March 31, 2007, File No.
1-9735).
|
|
Purchase
and Sale Agreement Between O’Brien Resources, LLC, Sepco II,
LLC, Liberty Energy, LLC, Crow Horizons Company and O’Benco II LP
collectively as Seller and Berry Petroleum Company as Purchaser, dated as
of June 10, 2008 (filed as Exhibit 10.2 to the Registrant’s Quarterly
Report on Form 10-Q for the period ended June 30, 2008, File No.
1-9735).
|
|
Overriding
Royalty Purchase Agreement Between
O’Brien Resources, LLC, as Seller and Berry Petroleum Company
as Purchaser, dated as of June 10, 2008 (filed as Exhibit 10.3 to the
Registrant’s Quarterly Report on Form 10-Q for the period ended June 30,
2008, File No. 1-9735).
|
|
Second Amendment
to the Amended and Restated Credit Agreement, dated as of February 19,
2009 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
on February 20, 2009, File NO. 1-9735).
|
|
Ratio
of Earnings to Fixed Charges
|
|
Consent
of PricewaterhouseCoopers LLP, Independent Registered Public Accounting
Firm.
|
|
Consent
of DeGolyer and MacNaughton.
|
|
Certification
of Chief Executive Officer pursuant to SEC Rule
13(a)-14(a).
|
|
Certification
of Chief Financial Officer pursuant to SEC Rule
13(a)-14(a).
|
|
Certification
of Chief Executive Officer pursuant to Section 1350 of Chapter 63 of Title
18 of the U.S. Code.
|
|
Certification
of Chief Financial Officer pursuant to Section 1350 of Chapter 63 of Title
18 of the U.S. Code.
|
|
Form
of Indemnity Agreement of Registrant (filed as Exhibit 99.1 in
Registrant's Annual Report on Form 10-K filed on March 31, 2005, File No.
1-9735).
|
|
Form
of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to
Registrant's Registration Statement on Form S-4 filed on May 22, 1987,
File No. 33-13240).
|
* Incorporated
by reference
**
Portions of this exhibit have been omitted pursuant to a request for
confidential treatment
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized on February 25, 2009.
BERRY PETROLEUM
COMPANY
/s/
Robert F. Heinemann
|
/s/
David D. Wolf
|
/s/
Shawn M. Canaday
|
ROBERT F. HEINEMANN
|
DAVID D. WOLF
|
SHAWN M.
CANADAY
|
President,
Chief Executive Officer
|
Executive
Vice President and
|
Vice
President and Controller
|
and
Director
|
Chief
Financial Officer
|
(Principal
Accounting Officer)
|
|
(Principal
Financial Officer)
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities on the dates indicated.
Name
|
Office
|
Date
|
|
|
|
/s/
Martin H. Young, Jr.
|
Chairman
of the Board,
|
February
25, 2009
|
Martin H. Young,
Jr.
|
Director
|
|
|
|
|
/s/
Robert F. Heinemann
|
President,
Chief Executive Officer
|
February
25, 2009
|
Robert F. Heinemann
|
and
Director
|
|
|
|
|
/s/
Joseph H. Bryant
|
Director
|
February
25, 2009
|
Joseph H. Bryant
|
|
|
|
|
|
/s/
Ralph B. Busch, III
|
Director
|
February
25, 2009
|
Ralph B. Busch,
III
|
|
|
|
|
|
/s/
William E. Bush, Jr.
|
Director
|
February
25, 2009
|
William E. Bush,
Jr.
|
|
|
|
|
|
/s/
Stephen L. Cropper
|
Director
|
February
25, 2009
|
Stephen L. Cropper
|
|
|
|
|
|
/s/
J. Herbert Gaul, Jr.
|
Director
|
February
25, 2009
|
J.
Herbert Gaul, Jr.
|
|
|
|
|
|
/s/
Thomas J. Jamieson
|
Director
|
February
25, 2009
|
Thomas J. Jamieson
|
|
|
|
|
|
/s/
J. Frank Keller
|
Director
|
February
25, 2009
|
J.
Frank Keller
|
|
|
|
|
|
/s/
Ronald J. Robinson
|
Director
|
February
25, 2009
|
Ronald J. Robinson
|
|
|
82