Unassociated Document
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the
fiscal year ended
December 31, 2004
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
| |
DELAWARE |
|
77-0079387 |
|
| |
(State
of incorporation or organization) |
|
(I.R.S.
Employer Identification Number) |
|
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code: (661)
616-3900
(Former
name, former address and former fiscal year, if changed since last
report)
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 |
|
| |
Class
A Common Stock, $.01 par value |
|
New
York Stock Exchange |
|
| |
(including
associated stock purchase rights) |
|
|
|
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. YES x NO o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. o
Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Act). YES x NO o
As of
June 30, 2004, the aggregate market value of the voting stock held by
non-affiliates was $519,158,260. As of March 14, 2005, the registrant had
21,119,120 shares of Class A Common Stock outstanding. The registrant also had
898,892 shares of Class B Stock outstanding on March 14, 2005 all of which is
held by an affiliate of the registrant.
DOCUMENTS
INCORPORATED BY REFERENCE
Part III
is incorporated by reference from the registrant's definitive Proxy Statement
for its Annual Meeting of Shareholders to be filed, pursuant to Regulation 14A,
no later than 120 days after the close of the registrant's fiscal
year.
BERRY
PETROLEUM COMPANY
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PART
II
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PART
I
Company
Website
The
Company has a website located at http://www.bry.com. The
website can be used to access recent news releases and Securities and Exchange
Commission filings, crude oil price postings, the Company’s Annual Report, Proxy
Statement, Board committee charters, code of business conduct and ethics, the
code of ethics for senior financial officers and other items of interest.
The contents of the Company's website are not incorporated into this document. Securities and Exchange Commission filings, including supplemental schedules and
exhibits can also be accessed free of charge through the SEC website at
http://www.sec.gov.
Berry
Petroleum Company, (Berry or Company), is an independent energy company engaged
in the production, development, acquisition, exploitation and exploration of
crude oil and natural gas. While the Company was incorporated in Delaware in
1985 and has been a publicly traded company since 1987, it can trace its roots
in California oil production back to 1909. Currently, Berry's principal reserves
and producing properties are located in the San Joaquin Valley, Los Angeles and
Ventura Basins in California, the Uinta Basin in northeastern Utah and the
Denver-Julesburg Basin in Colorado, Kansas and Nebraska. The Company’s corporate
headquarters are located in Bakersfield, California. The Company has a regional
office in Denver, Colorado to manage its assets in the Rocky Mountain and
Mid-Continent regions. Management believes that these facilities are adequate
for its current operations and anticipated growth. Information contained in this
report on Form 10-K reflects the business of the Company during the year ended
December 31, 2004 unless noted otherwise.
The
Company's mission is to increase shareholder value, primarily through maximizing
the value and cash flow of the Company's assets. To achieve this, Berry's
corporate strategy is to increase its net proved reserves annually, grow
production annually and, in the process, increase both net income and cash flow
in total and per share. To increase proved reserves and production, the Company
will compete to acquire oil and gas properties with principally proved reserves
and exploitation potential or sizeable acreage positions that the Company
believes can ultimately contain substantial reserves which can be developed at
reasonable costs. Additionally, the Company will continue to focus on the
further development of its properties through developmental drilling, well
completions, remedial work and by application of enhanced oil recovery (EOR)
methods, as applicable. In conjunction with the goals of maximizing
profitability and the exploitation and development of its substantial heavy
crude oil base in California, the Company owns three cogeneration facilities
which are intended to provide an efficient and secure long-term supply of steam
necessary for the economic production of heavy oil. Berry views these assets as
a key part of its long-term success. Berry believes that its primary strengths
are its ability to maintain a cost-efficient operation, its ability to acquire
attractive producing properties which have significant development, exploitation
and enhancement potential and sizable prospective acreage blocks in or near
producing areas, its strong financial position and its experienced management
team and staff. The Company has identified the Rocky Mountain and Mid-Continent
regions as its primary areas of interest for growth. The Company believes that
it can be successful in growing its reserve base and production in a profitable
manner by investing in certain assets in these regions and California.
Additionally, it provides substantial opportunity for the Company to diversify
its existing predominantly heavy crude oil base into light oil and natural gas.
Strategically, the Company desires to increase its natural gas reserves and
production as the Company consumes approximately 37,000 MMBtu daily as fuel for
steam generation which is utilized in its California heavy oil operations. The
Company has an unsecured credit facility with a current borrowing base of $200
million (at year-end 2004, $172 million is available) which may be utilized in
adding reserves and production through acquisitions.
Proved
Reserves
As of
December 31, 2004, the Company's estimated proved reserves were 110 million
barrels of oil equivalent, (BOE), of which 87% are heavy crude oil, 9% light
crude oil and 4% natural gas. A significant portion of these proved reserves are
owned in fee. Geographically, 88% of the Company’s reserves are located in
California and 12% in the Rocky Mountain region. Proved undeveloped reserves
make up 26% of the Company's proved total. The projected capital to develop
these reserves is $114 million, at an estimated cost of approximately $4.00 per
BOE. Over 90% of the capital to develop these reserves is expected to be
expended in the next five years. Production in 2004 was 7.5 million BOE, up 25%
from production of 6.0 million BOE in 2003. Based on average daily fourth
quarter production for each year, the Company’s reserves-to-production ratio was
14.1 years at year-end 2004, reduced from 16.2 years at year-end 2003. This
reduction is primarily due to the shorter reserve life of the Company's Rocky
Mountain assets compared to its California assets.
Acquisitions
The
Company actively pursued its growth strategy during the year. In September 2004,
the Company and an industry partner were the successful bidders on certain
leases offered by the Bureau of Land Management (BLM). These leases representing
approximately 17,000 gross (8,500 net) acres are located southeast of the
Company's Brundage Canyon producing properties. The issuance of leases for this
acreage is subject to final approval by the BLM. The Company paid approximately
$3.3 million for its interest in this acreage, which is included in other
non-current assets on the Company's Balance Sheet as of December 31,
2004.
In July
2004, the Company and Bill Barrett Corporation, entered into a joint exploration
and development agreement with the Ute Indian Tribe to explore and develop
approximately 124,500 gross (62,250 net) prospective acres of tribal lands in
the Uinta Basin in Utah. The Company also purchased an interest in 44,500 gross
(22,250 net) acres of privately owned lands near this tribal acreage. The 169,000
gross acre block is located immediately west of the Company’s Brundage Canyon
producing properties. The Company will drill and operate the shallow wells which
target light oil in the Green River formation and retain up to a 75% working
interest. The Company's partner will drill and operate the deep wells which
target natural gas in the Mesaverde and Wasatch formations. Berry will hold up
to a 25% working interest in these deep wells. The Ute Tribe has the option to
participate in each well and obtain a 25% working interest which would reduce
the Company’s and its partner's participation. This
acquisition is a strategic fit as it builds on the Company's success at Brundage
Canyon and increases the potential for the discovery of additional light oil and
natural gas. The Company's minimum obligation under its exploration and
development agreement is $10.5 million.
In
December 2004, the Company signed a
development agreement with Petro-Canada Resources (USA) Inc., to develop
Petro-Canada's Coyote Flats prospect in Utah, approximately 45 miles southwest
of the Company's Brundage Canyon producing properties. Berry will be the
operator and upon completing a defined drilling program, will own an interest in
approximately 69,250 gross (33,500 net) undeveloped acres. The Company estimates
its total cost under this agreement will be approximately $10.3 million which
will vary based on drilling costs. Upon completion of the program,
the Company and its 50% partner, Petro-Canada Resources, will jointly
determine future development plans.
In
December 2004 the Company announced and, in January 2005, completed the
acquisition of certain natural gas producing assets in the Niobrara field
located in eastern Colorado for approximately $105 million utilizing the
Company's existing credit facility. These properties
consist of approximately 127,000 gross (69,500 net) acres. The Company has a
working interest of approximately 52%. Production, as of March 1, 2005, is 9 MMcf (million cubic feet) of natural gas per day net to Berry's interest, with
estimated proved natural gas reserves of 87 Bcf (billion cubic
feet).
In
January 2005, the Company purchased from Bill Barrett Corporation a working
interest in approximately 390,000 gross (172,250 net) prospective acres located
in eastern Colorado, western Kansas and southwestern Nebraska (the Tri-State
acreage). The
Company and its 50% partner will jointly explore and develop shallow Niobrara
biogenic natural gas, Sharon Springs Shale gas and deeper Pennsylvanian
formation oil assets on the acreage. The Company paid approximately $5 million
for its working interest in the acreage. The
Company believes the potential of the Tri-State area can be exploited by using
new drilling
techniques, with 3-D seismic technology to assess structural complexity,
estimate potentially recoverable oil and gas and determine drilling
locations.
2005
Outlook
The
Company is targeting a 12% increase in production in 2005 which includes the
production from the Niobrara gas assets. Additionally, crude pricing looks very
favorable for 2005. Additionally, the Company maintains a hedging program which
is designed to moderate the effects of a severe crude oil price downturn and
protect certain operating margins in the Company's California operations. The
Company has approximately 7,750 barrels per day hedged for calendar 2005 at
approximately NYMEX West Texas Intermediate (WTI) of $40.75 per barrel. The
Company's existing hedge position can be viewed on its website at: http://www.bry.com/index.php?page=hedging.
The contents of the Company's website are not incorporated into this document
Excluding
any future acquisitions, in 2005 the Company plans to spend approximately $107
million on drilling 177 net wells and performing 92 workovers. The Company
intends to fund 100% of its capital program out of internally generated cash
flow. Major areas of focus in 2005 will be:
| |
· |
California
production - Projects include expanding the thermal development of the
Poso Creek field, the evaluation of the Company’s diatomite pilot at North
Midway-Sunset and additional drilling of infill horizontal wells at South
Midway-Sunset. |
| |
· |
Rockies
& Mid-Continent production - In 2005, the Company will continue the
development of the Brundage Canyon producing property on 80-acre spacing,
test the potential of 40-acre infill drilling and appraise the northern
and southern limits of the field. On the recently acquired Niobrara gas
assets, the Company plans to drill approximately 60 wells as part of its
ongoing development program and the initiation of the 40-acre infill
program from the existing 80-acre
development. |
| |
· |
Rockies
& Mid-Continent prospects - The Company and its joint venture partner,
will begin testing the oil potential of the Lake Canyon acreage with at
least two shallow test wells at approximately 6,000 feet in the Green
River trend. These initial drill sites will be approximately three miles
west of the Company’s Brundage Canyon producing property and have the
potential of providing the Company with development opportunities
comparable to Brundage Canyon. Drilling of the first deep natural gas test
well in Lake Canyon is scheduled for the fourth quarter of 2005. The
Company intends to drill its obligation wells at Coyote Flats, (45 miles
southwest of Brundage Canyon) which will target the Ferron sands and Emery
coals. Additionally, the Company will participate with its partner to
begin testing the Sharon Springs Shale gas, Niobrara biogenic natural gas,
along with the deeper Pennsylvanian formation oil prospects in its
recently acquired Tri-State acreage in Colorado, Nebraska and Kansas.
|
| |
· |
In
September 2004, the Company entered into a farm-out agreement
pursuant to which Bill Barrett Corporation had the right to earn a 75%
working interest in the deep Mesaverde formation and deeper horizons
within the Brundage Canyon field by drilling a deep exploratory test. The
Company's partner commenced the drilling of its initial deep exploratory
well in Brundage Canyon in November 2004 and abandoned it in
January 2005, pending the further evaluation of a 3-D seismic survey
and assessment of optimal completion technology. No costs were incurred by
the Company related to the drilling or abandonment of this
well. |
Operations
Berry
operates all of its principal oil and gas producing properties. In California,
the Midway-Sunset, Poso Creek and Placerita fields contain predominantly heavy
crude oil which requires heat, supplied in the form of steam, injected into the
oil producing formations to reduce the oil viscosity which allows the oil to
flow to the well-bore for production. Berry utilizes cyclic steam and/or steam
flood recovery methods in all of these fields and primary recovery methods at
its Montalvo field. Berry is able to produce its heavy oil at its Montalvo field
without steam since the majority of the producing reservoir is at a depth in
excess of 11,000 feet and thus the reservoir temperature is high enough to
produce the oil without the assistance of additional heat from steam. In Utah,
the Brundage Canyon field consists of light gravity crude and associated natural
gas produced from a depth of approximately 6,000 feet.
In
California, 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 lease automatic custody transfer units or gauged before sale
and subsequently transferred into crude oil pipelines
owned by other companies or transported via truck. Crude oil produced from the
Brundage Canyon field is transported by truck, while its gas production, net of
field usage, is transported by gathering or distribution pipelines to two main
shipper pipelines. Natural gas produced from the Niobrara gas assets is
transported by Company and third party distribution lines to two main shipper
pipelines.
Revenues
Total
revenues for 2004 increased by $94 million or 52% over 2003. Total revenues and
the percentage of revenues by source for the prior three years are as
follows:
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
Total
revenues (in millions) |
|
$ |
275 |
|
$ |
181 |
|
$ |
131 |
|
|
Sales
of oil and gas |
|
|
83 |
% |
|
75 |
% |
|
78 |
% |
|
Sales
of electricity |
|
|
17 |
% |
|
24 |
% |
|
21 |
% |
|
Other |
|
|
- |
|
|
1 |
% |
|
1 |
% |
Crude Oil and Natural Gas Marketing
The
global and California crude oil markets continue to remain strong. While
the Organization of Petroleum Exporting Countries successfully managed crude oil
prices despite petroleum product demand weakness due to worldwide economic
slowdowns and political instability during 2002 and 2003, increased market
demand and lower inventory levels were key factors during 2004. Product
prices began to rise in 2002 and continued to exhibit an overall-strengthening
trend in 2003 and 2004. The range of West
Texas Intermediate (WTI) crude prices for 2004 was a low of
$32.48 and a high of $55.17. The NYMEX settlement price for WTI, the U.S. benchmark crude oil, averaged $41.47 for 2004
compared to $30.99 for 2003 and $26.15 for 2002. The average posted price
for the Company’s 13 degree API heavy crude oil was $32.84 for 2004 compared to
$25.27 for 2003 and $20.67 for 2002. The average posted price for the Company’s
Utah light crude oil was $39.62 for 2004 compared to $29.14 for 2003. The
Company expects that crude prices will continue to be volatile in
2005.
While
crude oil price differentials between WTI and California’s heavy crude were
fairly consistent in both 2002 and 2003 at just under $6.00 per barrel, the
differential widened dramatically during 2004. The crude price differential
between WTI and California’s heavy crude oil averaged $8.57, $5.73 and $5.48 per
barrel for 2004, 2003 and 2002, respectively. On December 31, 2004 the
differential ended the year at $14.19. This differential has averaged over
$14.00 per barrel in the first two months of 2005, and the Company is concerned
that this differential may remain high for an extended period of time.
Subsequent to the termination of the Company's current crude oil sales contract
on December 31, 2004, a widening differential between WTI and California crude
oil could adversely affect the Company's revenues, profitability and cash flows
from its heavy oil operations. The Company will enter into a new contract
if favorable terms can be achieved or may sell its crude oil into the spot
market.
A
price-sensitive royalty burdens one of the Company’s California properties which
produces approximately 4,000 barrels per day. This royalty is 75% of the
amount of the heavy oil posted price above a base price which was $14.88 in
2004. This base price escalates at 2% annually, thus the threshold price
is $15.18 per barrel in 2005.
Berry
markets its crude oil production to competing buyers including independent
marketers but primarily to major oil refining companies. Because of the
Company’s ability to deliver significant volumes of crude oil over a multi-year
period, the Company was able to secure a thirty-nine month sales agreement,
beginning in late 2002, with a major oil company whereby the Company sells over
90% of its California production under a negotiated pricing mechanism.
This contract expires on December 31, 2005. Pricing
in this agreement is based upon the higher of the average of the local field
posted prices plus a fixed premium, or WTI minus a fixed
differential near
$6.00 per barrel. Both methods are calculated using a monthly
determination. In addition to providing a premium above field postings,
the agreement effectively eliminates the Company’s exposure to the risk of
widening WTI to California heavy crude price differentials and allows the
Company to effectively hedge its production based on WTI pricing. This
contract allowed the Company to improve its revenues over the posted price by
approximately $13 million in 2004. The Brundage Canyon crude oil, which is
approximately 40 degree API gravity, is also linked to WTI and is priced at WTI
less a fixed differential approximating $2.00 per barrel. This contract expires
on September 30, 2006.
Berry
markets produced natural gas from Utah, Wyoming and California. In October
2003, the Company began marketing produced gas from the Brundage Canyon
field. Some of the natural gas from Brundage Canyon is sold in the Salt
Lake City market at a Questar monthly index related price with an adjustment for
transportation. Brundage Canyon volume in excess of Berry’s firm pipeline
transportation volume is sold at the field at a Questar daily spot related
price. The Company owns a non-operated working interest in the South Joe
Creek field in the Powder River Basin in Wyoming. Berry began marketing
its working interest share of production in-kind from South Joe Creek in
December 2002, at Glenrock, Wyoming at monthly
Colorado
Interstate Gas (CIG) index related prices. Additionally, produced gas from
the Niobrara field in Colorado is also sold at monthly CIG index related price
For 2004,
the first-of-month indices approximated $5.60 per MMBtu for SoCal Border, $5.15
per MMBtu for Rockies CIG and $5.05 for Rockies Questar. The closing price
for the NYMEX prompt month natural gas contract averaged $6.18, $5.84 and $3.37
for years 2004, 2003 and 2002, respectively.
The
Company has physical access to interstate gas pipelines, such as the Kern River
Pipeline and the Questar Pipeline, as well as California intrastate systems
owned by Southern California Gas Company and Pacific Gas & Electric
(PG&E), to move gas to or from market. To avoid negative financial
impacts to the Company should California pipeline capacity become constrained,
the Company entered into a long-term gas transportation contract with Kern River
Gas Transmission Company for 12,000 MMBtu/D. This is a ten year contract
which began in May 2003. There is a proceeding currently before the
Federal Energy Regulatory Commission (FERC) that may result in an upward
adjustment in the transportation charge under this contract. The Company does
not believe any such adjustment would have a material adverse impact on its
operations. The Company also holds two firm transportation contracts on the
Questar Pipeline system in Utah totaling 5,300 MMBtu/D.
From time
to time, the Company enters into crude oil and natural gas hedge contracts, the
terms of which depend on various factors, including Management’s view of future
crude oil and natural gas prices and the Company’s future financial commitments.
This price hedging program is designed to moderate the effects of a severe crude
oil price downturn and protect certain operating margins in the Company's
California operations. Currently, the hedges are in the form of swaps, however,
the Company may use a variety of hedge instruments in the future. The Company's
hedging activities resulted in a net reduction in revenue per BOE to the Company
of $3.31 in 2004, $1.96 in 2003 and $.72 in 2002.
The
following table summarizes the hedge position of the Company as of March 1,
2005:
| |
|
Average |
|
Average
|
|
|
|
Average |
|
Average |
|
|
|
Barrels |
|
Swap
|
|
|
|
MMBtu |
|
Swap
|
|
Term
|
|
Per
Day |
|
Price
|
|
Term
|
|
Per
Day |
|
Price |
| |
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil Sales |
|
|
|
|
|
Natural
Gas Sales (CIG) |
|
|
|
|
|
(NYMEX
WTI) |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Full
Year 2005 |
|
1,000 |
|
$
6.21 |
|
1st
Quarter 2005 |
|
8,000 |
|
$
41.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Purchases |
|
|
|
|
|
2nd
Quarter 2005 |
|
8,000 |
|
$
40.58 |
|
(SoCal
Border) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd
Quarter 2005 |
|
7,500 |
|
$
40.84 |
|
1st
Quarter 2005 |
|
9,000 |
|
$
5.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
4th
Quarter 2005 |
|
7,500 |
|
$
40.67 |
|
2nd
Quarter 2005 |
|
8,000 |
|
$
5.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
1st
Quarter 2006 (1) |
|
1,250 |
|
$
45.32 |
|
3rd
Quarter 2005 |
|
6,667 |
|
$
5.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd
Quarter 2006 (1) |
|
1,250 |
|
$
44.49 |
|
4th
Quarter 2005 |
|
6,000 |
|
$
5.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd
Quarter 2006 (1) |
|
1,250 |
|
$
43.78 |
|
1st
Quarter 2006 |
|
5,000 |
|
$
4.85 |
(1) These contracts were entered into subsequent to
December 31, 2004.Payments
to the Company's counterparties are triggered when the monthly average prices
are above the swap price in the case of the Company's crude oil and natural gas
sales hedges and below the swap price for the Company's natural gas purchase
hedge positions. Conversely, payments from our counterparties are received when
the monthly average prices are below the swap price for the Company's crude oil
and natural gas sales hedges and above the swap price for the Company's natural
gas purchase hedge positions. Management regularly monitors the crude oil and
natural gas markets and the Company’s financial commitments to determine if,
when, and at what level some form of crude oil and/or natural gas hedging or
other price protection is appropriate.
Cogeneration
Steam Supply
As of
December 31, 2004, approximately 82% of the Company's proved reserves, or 90
million barrels, consisted of heavy crude oil produced from depths shallower
than 2,000 feet. The Company, in pursuing its goal of being a cost-efficient
heavy oil producer, has remained focused on minimizing its steam cost. One of
the main methods of keeping steam costs low is through the ownership and
efficient operation of cogeneration facilities. Two of these cogeneration
facilities, a 38 megawatt (MW) and an 18 MW facility are located in the
Company’s South Midway-Sunset field. The Company also owns a 42 MW cogeneration
facility located in the Placerita field. Steam generation from these facilities,
with a total steam capacity of approximately 38,000 barrels of steam per day
(BSPD), is more efficient than conventional steam generation as both steam and
electricity are concurrently produced from a common fuel stream. The Company
also purchases approximately 2,000 BSPD under contract on favorable terms from a
non-Company owned cogeneration facility.
Conventional
Steam Generation
In
addition to these cogeneration plants, the Company owns sixteen conventional
boilers. The quantity of boilers operated at any point in time is dependent on
the steam volume required for the Company to achieve its targeted production and
on the price of natural gas compared to the price of crude oil sold. The total
rated capacity of the conventional boilers is approximately 43,000 BSPD.
The cost
of natural gas purchased (excluding transportation) per MMBtu averaged $5.46,
$4.88 and $3.13 for 2004, 2003 and 2002, respectively. Most of the Company’s
conventional steam generators were run in 2004 to achieve the Company’s goal of
increasing heavy oil production to record levels.
The
Company believes that it may become necessary to add additional steam capacity
for its future development projects at Midway-Sunset, Placerita and Poso Creek
to allow for full development of its properties. The Company regularly reviews
its most economical source for obtaining additional steam to achieve its growth
objectives.
Operational
Control
Ownership
of these varied steam generation facilities and sources allows for maximum
control over the steam supply, location, and to some extent the aggregated cost.
The Company’s steam supply and flexibility are crucial for the maximization of
oil production, cost control and ultimate reserve recovery.
The total
annual average electrical generation of the Company’s three cogeneration
facilities is approximately 93 megawatts (MW), of which the Company consumes
approximately 8 MW for use in its operations. The three facilities can also
supply approximately 38,000 BSPD. Each facility is centrally located on an oil
producing property such that the steam generated by the facility is capable of
being delivered to the wells that require steam for the enhanced oil recovery
process. The Company’s investment in its cogeneration facilities have been for
the express purpose of lowering the steam costs in its heavy oil operations and
securing operating control of the respective steam generation. Expenses of
operating the cogeneration plants are analyzed regularly to determine that they
are advantageous versus conventional steam boilers. In 2004, the Company revised
its allocation of cogeneration costs to oil and gas operations. 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.
Electricity
Sales Contracts
Historically,
the Company has sold electricity produced by its cogeneration facilities to two
California public utilities, Southern California Edison Company (Edison) and
Pacific Gas and Electric (PG&E), under long-term contracts. These contracts
are referred to as Standard Offer (SO) contracts under which the Company is paid
an energy payment that reflects the utility’s Short Run Avoided Cost (SRAC) plus
a capacity payment that reflects a recovery of capital expenditures that would
otherwise have been made by the utility. The capacity payments are either fixed
throughout the term of the agreement or can be adjusted from time to time by the
California Public Utilities Commission (CPUC). The SRAC energy price is
determined by a formula that reflects the utility’s marginal fuel cost and a
conversion efficiency that represents a hypothetical utility resource to
generate electricity in the absence of the cogenerator. Natural gas is now the
marginal fuel for California utilities so this formula provides a hedge against
the Company’s cost of gas to produce electricity and steam in its
cogeneration facilities. A proceeding is now underway at the CPUC to review and revise the
methodology used to determine SRAC energy prices. This proceeding is currently
scheduled to be completed by the end of 2005. There is no assurance that any new
methodology will continue to provide a hedge against the Company’s fuel cost or
that a revised pricing mechanism will be as beneficial as the current contract
pricing.
The
original SO contract for Placerita Unit 1 continues in effect through March
2009. The modified SRAC pricing terms reflect a fixed energy price of 5.37
cents/kilowatt per hour (KWh) until June 2006, at which time the energy price
reverts to the SRAC pricing methodology. In 2002, the CPUC ordered the
California utilities to offer SO contracts to certain cogeneration facilities
with expired SO contracts, known as Qualifying Facilities or QFs, for a maximum
term of one year. The Company met these requirements and entered into new SO
contracts with Edison for its Placerita Unit 2 and with PG&E for its Cogen
38 and Cogen 18 facilities effective January 2003. These three new SO contracts
resulted in improved electrical pricing in 2003 over 2002. All three SO
contracts terminated on December 31, 2003, as originally ordered by the CPUC.
On
December 18, 2003, the CPUC ordered the California utilities to continue to
offer SO contracts to certain QFs with expired SO contracts, such as the
Company, for a one year term beginning January 1, 2004. In the same decision,
the CPUC also directed its staff to initiate a comprehensive review and revision
of the SRAC pricing methodology. Edison appealed the legality of the December
18, 2003 CPUC decision that ordered the additional one-year extension of SO
contracts, at the CPUC, but was unsuccessful. The Company executed a one year
extension of its SO contract with Edison, effective January 1, 2004 for the
Placerita Unit 2 facility, and executed similar one year extensions of its SO
contracts with PG&E for its Cogen 38 and Cogen 18 facilities. Those one year
extensions terminated as scheduled on December 31, 2004.
On
January 22, 2004, the CPUC issued a decision that establishes the rules under
which the California utilities will produce or procure energy for their
customers for the next 5 to 10 years. Among other things, this decision ordered
the California utilities to offer SO contracts to certain QFs whose SO contracts
will terminate prior to December 31, 2005, such as the Company, for a term of 5
years. The SRAC price paid under these SO contracts is subject to the same
prospective adjustments that were required in the prior CPUC decision that
ordered the one-year extension. In December 2004, the Company executed a five
year SO contract with Edison for the Placerita Unit 2 facility, and five year SO
contracts with PG&E for the Cogen 18 and Cogen 38 facilities, each effective
January 1, 2005. Edison and PG&E have challenged, in the California Court of
Appeal, the legality of the CPUC decision that ordered the utilities to enter
into the one-year SO contracts for 2004, and the decision that ordered the
utilities to enter into five-year SO contracts. Arguments in this case were
heard by the court in March 2005. The Company believes that QFs, such as the
Company's facilities, provide an important source of distributive power
generation into California's electricity grid, and as such, that the Company's
facilities will be economic to operate for at least the current five-year
contract term.
Facility
and Contract Summary
|
Location
and Facility |
Type
of Contract |
Purchaser |
Contract
Expiration |
Approximate
Megawatts Available for Sale |
Approximate
Megawatts Consumed in Operations |
Approximate
Barrels of Steam Per Day |
|
|
|
|
|
|
|
|
|
Placerita |
|
|
|
|
|
|
|
Placerita
Unit 1 |
SO2 |
Edison |
Mar-09 |
20 |
- |
6,600 |
|
Placerita
Unit 2 |
SO1 |
Edison |
Dec-09 |
16 |
4 |
6,700 |
|
|
|
|
|
|
|
|
|
South
Midway-Sunset |
|
|
|
|
|
|
|
Cogen
18 |
SO1 |
PG&E |
Dec-09 |
12 |
4 |
6,600 |
|
Cogen
38 |
SO1 |
PG&E |
Dec-09 |
37 |
- |
18,000 |
Berry
Petroleum Company is committed to responsible management of the environment,
health and safety, as these areas relate to the Company’s operations. The
Company strives to achieve the long-term goal of sustainable development within
the framework of sound environmental, health and safety practices and standards.
Berry makes environmental, health and safety protection an integral part of all
business activities, from the acquisition and management of its resources
through the decommissioning and reclamation of its wells and
facilities.
All
facets of the Company's operations are affected by a myriad of federal, state,
regional and local laws, rules and regulations. Berry is further affected by
changes in such laws and by constantly changing administrative regulations.
Furthermore, government agencies may impose substantial liabilities if the
Company fails to comply with such regulations or for any contamination resulting
from the Company's operations.
Therefore,
Berry has programs in place to identify and manage known risks, to train
employees in the proper performance of their duties and to incorporate viable
new technologies into its operations. The costs incurred to ensure compliance
with environmental, health and safety laws and other regulations are
inextricably connected to normal operating expenses such that the Company is
unable to separate the expenses related to these matters.
Currently,
California environmental laws and regulations are being revised to lower
emissions from stationary sources. Although these requirements do have a
substantial impact upon the energy industry, generally these requirements do not
appear to affect the Company any differently, or to any greater or lesser
extent, than other companies in California. Berry believes that compliance with
environmental laws and regulations will not have a material adverse effect on
the Company's operations or financial condition. There can be no assurances,
however, that changes in, or additions to, laws and regulations regarding the
protection of the environment will not have such an impact in the
future.
Berry
maintains insurance coverage that it believes is customary in the industry
although it is not fully insured against all environmental or other risks. The
Company is not aware of any environmental claims existing as of December 31,
2004 that would have a material impact upon the Company's financial position,
results of operations, or liquidity.
Regulation
of Oil and Gas
The oil
and gas industry is extensively regulated by numerous federal, state and local
authorities, including Native American tribes. Legislation affecting the oil and
gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, numerous departments and agencies, both
federal and state, and Native American tribes are authorized by statute to issue
rules and regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for failure to comply.
Although the regulatory burden on the oil and gas industry increases the
Company's cost of doing business and, consequently, may affect profitability,
these burdens generally do not affect the Company any differently or to any
greater or lesser extent than they affect other companies in the industry with
similar types, quantities and locations of production.
The
Company's operations are subject to various types of regulation at federal,
state, local and Native American tribal levels. These types of regulation
include requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states, and some counties, municipalities and Native
American tribes, in which the Company operates also regulate one or more of the
following:
| |
· |
the
method of drilling and casing wells; |
| |
· |
the
rates of production or "allowables;" |
| |
· |
the
surface use and restoration of properties upon which wells are
drilled; |
| |
· |
the
plugging and abandoning of wells; and |
| |
· |
notice
to surface owners and other third parties. |
State
laws regulate the size and shape of drilling and spacing units or proration
units governing the pooling of oil and natural gas properties. Some states allow
forced pooling or integration of tracts to facilitate exploration while other
states rely on voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and may reduce the
Company's interest
in the unitized properties. In addition, state conservation laws establish
maximum rates of production from oil and natural gas wells, generally prohibit
the venting or flaring of natural gas and impose requirements regarding the
ratability of production. These laws and regulations may limit the amount of oil
and natural gas the Company can produce from its wells or limit the number of
wells or the locations at which it can drill.
Moreover,
each state generally imposes a property, production or severance tax with
respect to the production and sale of oil, natural gas and natural gas liquids
within its jurisdiction.
A portion
of the Company's leases in the Uinta Basin are, and some of the Company's future
leases in this and other areas may be, regulated by Native American tribes. In
addition to regulation by various federal, state and local agencies and
authorities, an entirely separate and distinct set of laws and regulations
applies to lessees, operators and other parties within the boundaries of Native
American reservations. Various federal agencies within the U.S. Department
of the Interior, particularly the Minerals Management Service and the Bureau of
Indian Affairs, together with each Native American tribe, promulgate and enforce
regulations pertaining to oil and gas operations on Native American
reservations. These regulations include lease provisions, royalty matters,
drilling and production requirements, environmental standards, and numerous
other matters.
Native
American tribes are subject to various federal statutes and oversight by the
Bureau of Indian Affairs. However, each Native American tribe is a sovereign
nation and has the right to enforce certain other laws and regulations entirely
independent from federal, state and local statutes and regulations, as long as
they do not supersede or conflict with such federal statutes. These tribal laws
and regulations include various fees, taxes, requirements to employ Native
American tribal members, and numerous other conditions that apply to lessees,
operators, and contractors conducting operations within the boundaries of a
Native American reservation. Further, lessees and operators within a Native
American reservation are subject to the Native American tribal court system,
unless there is a specific waiver of sovereign immunity by the Native American
tribe allowing resolution of disputes between the Native American tribe and
those lessees or operators to occur in federal or state court.
Therefore,
the Company is subject to various laws and regulations pertaining to Native
American tribal surface ownership, Native American oil and gas leases and other
exploration agreements, fees, taxes, and other burdens, obligations and issues
unique to oil and gas ownership and operations within Native American
reservations. One or more of these requirements may increase the Company's cost
of doing business on Native American tribal lands and have an impact on the
economic viability of any well or project on those lands.
Federal
Energy Regulation
The
enactment of the Public Utility Regulatory Policies Act of 1978, as amended
(PURPA), and the adoption of regulations thereunder by the FERC provided
incentives for the development of cogeneration facilities such as those owned by
the Company. A domestic electricity generating project must be a Qualifying
Facility (QF) under FERC regulations in order to take advantage of certain rate
and regulatory incentives provided by PURPA.
PURPA
provides two primary benefits to QFs. First, QFs generally are relieved of
compliance with extensive federal and state regulations that control the
financial structure of an electricity generating plant and the prices and terms
on which electricity may be sold by the plant. Second, FERC’s regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility’s avoided cost, and
that the utility sell back-up power to the QF on a non-discriminatory basis. The
term "avoided cost" is defined as the incremental cost to an electric utility of
electric energy or capacity, or both, which, but for the purchase from QFs, such
utility would generate for itself or purchase from another source. FERC
regulations also permit QFs and utilities to negotiate agreements for utility
purchases of power at rates lower than the utilities’ avoided costs. In
California, the utility’s avoided cost is generally referred to as Short Run
Avoided Cost or SRAC.
In order
to be a QF, a cogeneration facility must produce not only electricity, but also
useful thermal energy for use in an industrial or commercial process for heating
or cooling applications in certain proportions to the facility’s total energy
output, and must meet certain energy efficiency standards. Also, a QF must not
be controlled or more than 50% owned by one or more electric utilities or by
most electric utility holding companies, or one or more subsidiaries of such a
utility or holding company or any combination thereof. Each of the Company’s
cogeneration facilities is a QF, pursuant to PURPA.
State
Energy Regulation
The CPUC
has broad authority to regulate both the rates charged by, and the financial
activities of, electric utilities operating in this state and to promulgate
regulation for implementation of PURPA. Since a power sales agreement becomes a
part of a utility’s cost structure (generally reflected in its retail rates),
power sales agreements with independent electricity producers, such as the
Company, are potentially under the regulatory purview of the CPUC and in
particular the process by which the utility has entered into the power sales
agreements. While the Company is not subject to regulation by the CPUC, the
CPUC's implementation of PURPA is of critical importance to the Company.
The oil
and gas industry is highly competitive. As an independent producer, the Company
does not own any refining or retail outlets and, therefore, it has little
control over the price it receives for its crude oil. As such, higher costs,
fees and taxes assessed at the producer level cannot necessarily be passed on to
the Company's customers. In acquisition activities, significant competition
exists as integrated and independent companies and individual producers are
active bidders for desirable oil and gas properties. Although many of these
competitors have greater financial and other resources than the Company,
Management believes that Berry is in a position to compete effectively due to
its low cost structure, transaction flexibility, strong financial position,
experience and determination.
On
December 31, 2004, the Company had 157 full-time employees, up from 129
full-time employees on December 31, 2003. As of March 1, 2005, and following the
acquisition of the Niobrara gas producing assets in Colorado, the Company has
181 employees. On-site production operation services, such as pumping,
maintenance, inspection and testing, are generally provided by independent
contractors.
Unless
otherwise noted, gross acreage, net wells, fourth quarter production, and 2004
year-end reserves are used in the property descriptions below.
San
Joaquin Valley Basin
Midway-Sunset,
California - Berry
owns and operates working interests in 38 properties consisting of 4,528 acres
located in the Midway-Sunset field. The Company estimates these properties
account for approximately 63% of the Company's proved oil and gas reserves and
approximately 57% of its current daily production. Of these properties, 23 are
owned in fee and the Company's average working interest in this field is
approximately 95%. The wells produce from an average depth of approximately
1,200 feet, and rely on thermal EOR methods, primarily cyclic
steaming.
During
2004, development activities at Midway-Sunset continued to be focused on
horizontal drilling to improve ultimate recovery of original oil-in-place,
reduce the development and operating costs of properties and to accelerate
production. Additionally, a steam flood pilot was initiated in the diatomite
formation. In 2005, the Company plans to drill an additional 54 wells, including
8 horizontal wells and 26 wells in the diatomite formation.
Poso
Creek, California - The
McVan property, consisting of 560 acres in the Poso Creek field, was purchased
in March 2003. An additional 120 acres were acquired in 2004 offsetting the
Company's existing position to the southeast. Year-end 2004 proved reserves
comprise 2% of Berry’s proved oil and gas reserves while year-end production has
increased to over 400 barrels per day.
During
2004, one service well was drilled and a ten well workover program was
completed. Steam injection was also reinitiated at the McVan property in 2004.
Plans for 2005 include the drilling of four new development wells, further well
workovers and the return to production of a number of idle wells.
Los
Angeles Basin
Placerita,
California - The
Company’s assets in the Placerita field consist of nine leases and four fee
properties totaling approximately 965 acres. The average depth of these wells is
1,800 feet and the properties rely on thermal recovery methods, primarily steam
flooding. The property accounts for approximately 16% of proved reserves and 13%
of current daily production.
During
2004, three new wells were drilled to begin redevelopment on the Castruccio
property which the Company acquired several years ago. In 2005, the Company
plans to drill 12 wells in the north end of the field to continue a major
expansion of the existing steam flood.
Ventura
Basin
Montalvo,
California - Berry
owns a 100% working interest in six leases totaling 8,563 acres in the Ventura
Basin comprising the entire Montalvo field. The State of California is the
lessor for two of the six leases. The Company estimates current proved reserves
from Montalvo account for approximately 6% of Berry’s proved oil and gas
reserves and approximately 4% of Berry's current daily production. The wells
produce from an average depth of approximately 11,500 feet. No new wells were
drilled in 2004; however one well was remediated and returned to production.
During 2005, one idle well is scheduled to be returned to
production.
Uinta
Basin
Brundage
Canyon, Utah -
The
Brundage Canyon leasehold in Duchesne County, Utah consists of federal, tribal
and private leases totaling 47,300 gross acres (45,420 net). The Company
estimates that the Brundage Canyon properties account for approximately 12% of
proved oil and gas reserves and approximately 23% of current daily production.
There are 164 wells in the Brundage Canyon field producing oil and associated
natural gas with an average well depth of 6,000 feet.
In 2004,
the Company continued its focus on development of the Brundage Canyon property,
drilling 54 wells including several 40-acre infill tests. The Company’s
objectives for 2005 include the drilling of 59 additional wells, including nine
40-acre infill wells and the recompletion of 20 existing wells.
In
September 2004, the Company entered into a farm-out agreement pursuant to
which Bill Barrett Corporation had the right to earn a 75% working interest in
the deep Mesaverde formation and deeper horizons within the Brundage Canyon
Field by drilling a deep exploratory test. The Company's partner commenced the
drilling of its initial deep exploratory well in Brundage Canyon in
November 2004 and abandoned it in January 2005, pending the further
evaluation of a 3-D seismic survey and assessment of the optimal completion
technology.
Lake
Canyon Prospect, Utah - In
2004, the Company and Bill Barrett Corporation entered into a joint exploration
and development agreement with the Ute Indian Tribe to explore and develop
approximately 124,500 gross (62,250 net) prospective acres of tribal lands in
the Uinta Basin in Utah. The Company also purchased an interest in approximately
44,500 gross (22,250 net) acres of privately owned lands near the tribal
acreage. The 169,000 gross acre block is located immediately west of the
Company’s Brundage Canyon producing properties. The Company will drill and
operate the shallow wells which target light oil in the Green River formation
and retain up to a 75% working interest. The Company's partner will drill and
operate the deep wells which target natural gas in the Mesaverde and Wasatch
formations. Berry will hold up to a 25% working interest in these deep wells.
The Ute Tribe has the option to participate in each well and obtain a 25%
working interest which would reduce the Company’s and its partner’s
participation. The Company plans to drill two shallow test wells in the Green
River trend and participate in one deep test well in the Mesaverde formation in
2005.
Coyote
Flats Prospect, Utah - In
December 2004, the Company entered into a development agreement with
Petro-Canada Resources (USA) Inc. to develop their Coyote Flats prospect in the
Uinta Basin. The property is located approximately 45 miles southwest of the
Company’s Brundage Canyon property. The Company is obligated to drill three test
wells into the Ferron sand to a depth of approximately 7,500 feet and also drill
a six well Emery coalbed methane pilot, found at approximately 4,500 feet. Upon
the completion of this total nine well drilling program, the Company will earn
an interest in the approximately 69,250 gross (33,500 net) acres. The Company
has drilled one Ferron sand test well in early 2005 which was deemed to be a dry
hole. The Company plans to drill the remaining two Ferron sand test wells and
the Emery coalbed methane pilot wells during 2005. Future development
plans will be determined jointly by the Company and its 50% partner, Petro-Canada
Resources.
Denver-Julesburg
Basin
Niobrara
Field, Colorado - In
January 2005, the Company acquired certain interests in the Niobrara field in
northeastern Colorado for approximately $105 million. The properties consist of
approximately 127,000 gross (69,500 net) acres and the Company has a 52% working
interest. Current production is approximately 9 MMcf of natural gas per day. The
acquisition also includes approximately 200 miles of a pipeline gathering system
and gas compression facilities for delivery into interstate gas lines. In 2005,
the Company plans to drill approximately 60 gross wells as part of its ongoing
development program and the initiation of the 40-acre infill program from the
existing 80-acre development.
Tri-State
Prospect, Colorado, Nebraska and Kansas - In
January 2005, the Company acquired a working interest in approximately
390,000 gross (172,250 net) prospective acres, located in eastern Colorado,
western Kansas and southwestern Nebraska, from Bill Barrett Corporation.
The 50% joint
venture will apply seismic technologies to explore and, if successful, develop
the Niobrara formation for biogenic gas, which lies at less than 2,000 feet, and
apply seismic technologies to evaluate oil potential in the Pennsylvanian
formations at depths of 4,000 to 4,800 feet. The Company
believes the potential of the Tri-State area can be exploited by using new
drilling techniques, with 3-D seismic technology to assess structural
complexity, and estimate potentially recoverable oil and gas and determine
drilling locations. The
Company plans to drill 8 gross wells (4 net) in 2005.
Other
South
Joe Creek, Wyoming - The
Company holds a 15.83% non-operated working interest in the South Joe Creek
coalbed methane field which represents interests in federal, state and private
leases totaling 5,106 acres in the northeastern portion of the Powder River
Basin in Wyoming. The property has 96 wells (14 net). The property accounts for
1% of production while reserves are minimal. There are no plans at this time to
drill any new wells in 2005.
Mickelson
Creek, Wyoming - In
2003, the Company purchased three federal leases located in the Mickelson Creek
field in Sublette County, Wyoming. There are currently five wells on the 2,800
acre property. Reserves and production from these properties are minimal. The
Company plans to drill two wells on this property in 2005.
Kansas
and Illinois Coalbed Methane (CBM) Projects - The
Company holds 163,000 and 55,000 net acres in Eastern Kansas and Central
Illinois, respectively, as prospective acreage for coalbed methane production.
The Company drilled a pilot in each state in late 2002, and in 2003 the Company
determined both these pilots were non-commercial. As such, the Company has no
reserves or production in either state as of December 31, 2004. The Company
continues to assess the potential of these properties.
The
following is a summary of the Company's capital expenditures incurred during
2004 and 2003 and budgeted capital expenditures for 2005.
CAPITAL
EXPENDITURES SUMMARY
(in
thousands)
| |
|
2005
|
|
2004
|
|
2003
|
|
| |
|
(Budgeted)
(1) |
|
|
|
|
|
CALIFORNIA |
|
|
|
|
|
|
|
Midway-Sunset
Field |
|
|
|
|
|
|
|
|
New
wells |
|
$ |
11,012 |
|
$ |
11,376 |
|
$ |
10,710 |
|
|
Remedials/workovers |
|
|
420
|
|
|
1,415
|
|
|
1,718
|
|
|
Facilities
- oil & gas |
|
|
6,850
|
|
|
4,045
|
|
|
3,136
|
|
|
Facilities
- cogeneration |
|
|
3,435
|
|
|
1,055
|
|
|
231
|
|
|
General |
|
|
2,001
|
|
|
2,144
|
|
|
187
|
|
| |
|
|
23,718
|
|
|
20,035
|
|
|
15,982
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Other
California Fields |
|
|
|
|
|
|
|
|
|
|
|
New
wells |
|
|
5,295
|
|
|
426
|
|
|
6,509
|
|
|
Remedials/workovers |
|
|
4,463
|
|
|
1,589
|
|
|
1,084
|
|
|
Facilities
- oil & gas |
|
|
2,470
|
|
|
3,416
|
|
|
1,676
|
|
|
Facilities
- cogeneration |
|
|
250
|
|
|
555
|
|
|
370
|
|
| |
|
|
12,478
|
|
|
5,986
|
|
|
9,639
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Total
California |
|
|
36,196
|
|
|
26,021
|
|
|
25,621
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
ROCKIES
AND MID-CONTINENT |
|
|
|
|
|
|
|
|
|
|
|
Uinta
Basin |
|
|
|
|
|
|
|
|
|
|
|
New
wells |
|
|
47,914
|
|
|
39,467
|
|
|
14,298
|
|
|
Remedials/workovers |
|
|
2,050
|
|
|
4,597
|
|
|
234
|
|
|
Facilities |
|
|
4,332
|
|
|
1,979
|
|
|
146
|
|
| |
|
|
54,296
|
|
|
46,043
|
|
|
14,678
|
|
|
DJ
Basin |
|
|
|
|
|
|
|
|
|
|
|
New
wells/workovers |
|
|
5,660
|
|
|
-
|
|
|
-
|
|
|
Land
and seismic |
|
|
3,573
|
|
|
-
|
|
|
-
|
|
| |
|
|
9,233
|
|
|
-
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
3,593
|
|
|
161
|
|
|
1,256
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Total
Rocky Mountain and |
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent |
|
|
67,122
|
|
|
46,204
|
|
|
15,934
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
3,682
|
|
|
-
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
107,000 |
|
$ |
72,225 |
|
$ |
41,555 |
|
(1) Budgeted
capital expenditures may be adjusted for numerous reasons including, but not
limited to, oil, natural gas and electricity price levels. See Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.
In recent
years, the Company has concentrated on growth through development of existing
assets and strategic acquisitions. The Company's acquisition and development
strategy will include exploratory drilling in the future.
The
Revenue Reconciliation Act of 1990 included a tax credit for certain costs
associated with extracting high-cost, capital-intensive marginal oil or gas and
which utilizes at least one of nine designated
"enhanced" or tertiary recovery
methods (EOR). Cyclic steam and steam flood recovery methods for heavy oil,
which Berry utilizes extensively, are qualifying EOR methods. In 1996,
California conformed to the federal law, thus, on a combined basis, the Company
is able to achieve credits approximating 12% of its qualifying costs. The credit
is earned only for qualified EOR projects by investing in one of three types of
expenditures: 1) drilling development wells, 2) adding facilities that are
integrally related to qualified EOR production, or 3) utilizing a tertiary
injectant, such as steam, to produce oil. The credit may be utilized to reduce
the Company's tax liability down to, but not below, its alternative minimum tax
liability. This credit is significant in reducing the Company's income tax
liabilities and effective tax rate.
The
Company continued to engage DeGolyer and MacNaughton (D&M) to appraise the
extent and value of its proved oil and gas reserves and the future net revenues
to be derived from properties of the Company for the year ended December 31,
2004. D&M is an independent oil and gas consulting firm located in Dallas,
Texas. In preparing their reports, D&M reviewed and examined geologic,
economic, engineering and other data considered applicable to properly determine
the reserves of the Company. They also examined the reasonableness of certain
economic assumptions regarding forecasted operating and development costs and
recovery rates in light of the economic environment on December 31, 2004. For
the Company's operated properties, such reserve estimates are filed annually
with the U.S. Department of Energy. See the Supplemental Information About Oil
& Gas Producing Activities (Unaudited) for the Company's oil and gas reserve
disclosures.
The
following table sets forth certain information regarding production for the
years ended December 31, as
indicated:
| |
|
2004 |
|
2003 |
|
2002 |
|
Net
annual production:(1) |
|
|
|
|
|
|
|
|
Oil
(Mbbls) |
|
|
7,044
|
|
|
5,827
|
|
|
5,123 |
|
|
Gas
(Mmcf) |
|
|
2,839
|
|
|
1,277
|
|
|
769 |
|
|
Total
equivalent barrels(2) |
|
|
7,517
|
|
|
6,040
|
|
|
5,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Average
sales price: |
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) before hedging |
|
$ |
33.43 |
|
$ |
24.41 |
|
$ |
20.27 |
|
|
Oil
(per Bbl) after hedging |
|
|
29.89
|
|
|
22.37
|
|
|
19.54
|
|
|
Gas
(per mcf) before hedging |
|
|
6.13
|
|
|
4.40
|
|
|
2.22
|
|
|
Gas
(per mcf) after hedging |
|
|
6.12
|
|
|
4.43
|
|
|
2.22
|
|
|
Per
BOE before hedging |
|
|
33.64
|
|
|
24.48
|
|
|
20.11
|
|
|
Per
BOE after hedging |
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
|
Average
operating cost – oil and gas production (per BOE) |
|
|
10.96
|
|
|
10.37
|
|
|
8.61
|
|
Mbbls -
Thousands of Barrels
Mmcf -
Million Cubic Feet
BOE -
Barrels of Oil Equivalent
(1)
Net production represents that owned by Berry and produced to its
interests.
(2)
Equivalent oil and gas information is at a ratio of 6 thousand cubic feet
(mcf) of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to
42 U.S. gallons.
As of
December 31, 2004, the Company's properties accounted for the following
developed and undeveloped acres:
| |
|
Developed
Acres |
|
Undeveloped
Acres |
|
Total |
|
| |
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California |
|
|
8,167
|
|
|
8,167
|
|
|
7,038
|
|
|
7,038
|
|
|
15,205
|
|
|
15,205
|
|
|
Utah
(1) |
|
|
9,520
|
|
|
9,360
|
|
|
82,363
|
|
|
58,352
|
|
|
91,883
|
|
|
67,712
|
|
|
Wyoming |
|
|
3,800
|
|
|
750
|
|
|
4,266
|
|
|
2,250
|
|
|
8,066
|
|
|
3,000
|
|
|
Illinois |
|
|
-
|
|
|
-
|
|
|
58,318
|
|
|
54,601
|
|
|
58,318
|
|
|
54,601
|
|
|
Kansas |
|
|
-
|
|
|
-
|
|
|
168,960
|
|
|
163,046
|
|
|
168,960
|
|
|
163,046
|
|
|
Other |
|
|
80
|
|
|
19
|
|
|
-
|
|
|
-
|
|
|
80
|
|
|
19
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
21,567
|
|
|
18,296
|
|
|
320,945
|
|
|
285,287
|
|
|
342,512
|
|
|
303,583
|
|
(1)
Includes 44,583 gross undeveloped acres (22,292 net) where the Company has an
interest in 75% of the deep rights and 25% of the shallow rights.
Gross
acres represent acres in which Berry has a working interest; net acres represent
Berry's aggregate working interests in the gross acres.
As of
December 31, 2004, the Company has 1,947 gross oil wells (1,909 net) and 103
gross gas wells (20 net). Gross wells represent the total number of wells in
which Berry has a working interest. Net wells represent the number of gross
wells multiplied by the percentages of the working interests owned by Berry. One
or more completions in the same bore hole are counted as one well. Any well in
which one of the multiple completions is an oil completion is classified as an
oil well. Costs of $.5 million which were incurred as of December 31, 2004
were charged to expense and are reflected on the Company's income statement
under "Dry-hole, abandonment and impairment."
The
following table sets forth certain information regarding Berry's drilling
activities for the periods indicated:
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
Gross |
|
Net
|
|
Gross |
|
Net
|
|
Gross |
|
Net
|
|
Exploratory
wells drilled: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
5
|
|
|
5
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Dry(1) |
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11
|
|
|
11
|
|
|
Development
wells drilled: (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
123
|
|
|
111
|
|
|
121
|
|
|
119
|
|
|
81
|
|
|
76
|
|
|
Dry(1) |
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
Total
wells drilled: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
128
|
|
|
116
|
|
|
121
|
|
|
119
|
|
|
81
|
|
|
76
|
|
|
Dry(1) |
|
|
-
|
|
|
-
|
|
|
1
|
|
|
1
|
|
|
11
|
|
|
11
|
|
(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. The 11 wells
drilled in 2002 were determined to be dry holes in 2003.
(2)
Wells drilled include 12 wells gross, 2 wells net for 2004, 2 wells gross,
.3 wells net for 2003 and 6 wells gross, 1 well net for 2002 at South Joe Creek
where the Company holds a 15.83% working interest.
As of
December 31, 2004, two development wells were being drilled on the Brundage
Canyon property, one exploratory well was being drilled on the Coyote Flats
prospect and one exploratory well was being drilled on the Company's
Midway-Sunset property. The well being drilled on the Midway-Sunset property and
the well being drilled on the Coyote Flats prospect were determined to be
non-commercial in February 2005. Costs of $.5 million which were incurred
as of December 31, 2004 were charged to expense and are reflected on the
Company's income statement under "Dry-hole, abandonment and impairment."
To the
best of the Company's knowledge, there are no defects in the title to any of its
principal properties including related facilities. Notwithstanding the absence
of a recent title opinion or title insurance policy on all of its properties,
the Company believes it has satisfactory title to its properties, subject to
such exceptions as the Company believes are customary and usual in the oil and
gas industry and which the Company believes will not materially impair its
ability to recover the proved oil and gas reserves or to obtain the resulting
economic benefits.
As is
customary in the industry in the case of undeveloped properties, often little
investigation of record title is made at the time of acquisition. Investigations
are made prior to the consummation of an acquisition of producing properties and
before commencement of drilling operations on undeveloped properties. However
there can be no assurance that all matters will be discovered during such
investigation and this is a risk assumed by the Company. Individual properties
may be subject to burdens that the Company believes do not materially interfere
with the use, or affect the value, of the properties. Burdens on properties may
include:
| |
· |
customary
royalty interests; |
| |
· |
liens
incident to operating agreements and for current
taxes; |
| |
· |
obligations
or duties under applicable laws; |
| |
· |
development
obligations under oil and gas
leases; and |
| |
· |
burdens
such as net profits interests. |
The oil
and gas business can be hazardous, involving unforeseen circumstances such as
blowouts or environmental damage. Although it is not insured against all risks,
the Company maintains a comprehensive insurance program to address the hazards
inherent in operating its oil and gas business.
Information
required by item 2 "Properties" is included under Item 1
"Business".
While the
Company is, from time to time, a party to certain lawsuits in the ordinary
course of business, the Company does not believe any of such existing lawsuits
will have a material adverse effect on the Company's operations, financial
condition, or liquidity.
|
Item
4. |
Submission of Matters to a Vote of Security
Holders |
None.
Listed
below are the names, ages (as of December 31, 2004) and positions of the
executive officers of Berry and their business experience during at least the
past five years. All officers of the Company are appointed in May of each year
at an organizational meeting of the Board of Directors. There are no family
relationships between any of the executive officers and members of the Board of
Directors.
ROBERT F.
HEINEMANN, 51, has been President and Chief Executive Officer since June 2004.
Mr. Heinemann was Chairman of the Board and interim President and Chief
Executive Officer from April 2004 to June 2004. From December 2003 to March
2004, Mr. Heinemann was the director designated to serve as the presiding
director at executive sessions of the Board in the absences of the Chairman and
to act as liaison between the independent directors and the CEO. Mr. Heinemann
joined the Company’s Board in March of 2003. From 2000 until 2002, Mr. Heinemann
served as the Senior Vice President and Chief Technology Officer of Halliburton
Company and as the Chairman of the Halliburton Technology Advisory Committee. He
was previously with Mobil Oil Corporation (Mobil) where he served in a variety
of positions for Mobil and its various affiliate companies in the energy and
technical fields from 1981 to 1999, with his last responsibilities as Vice
President of Mobil Technology Company and General Manager of the Mobil
Exploration and Producing Technical Center.
RALPH J.
GOEHRING, 48, has been Executive Vice President and Chief Financial Officer
since June 2004. Mr. Goehring was Senior Vice President from April 1997 to June
2004, and has been Chief Financial Officer since March 1992 and was Manager of
Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant
Secretary for the Company.
MICHAEL
DUGINSKI, 38, has been Senior Vice President of Corporate Development since June
2004 and was Vice President of Corporate Development from February 2002 through
June 2004. Mr. Duginski, a mechanical engineer, was previously with Texaco, Inc.
from 1988 to 2002 where his positions included Director of New Business
Development, Production Manager and Gas and Power Operations Manager. Mr.
Duginski is also an Assistant Secretary for the Company.
LOGAN
MAGRUDER, 48, has been Senior Vice President of the Rocky Mountain and
Mid-Continent Region since June 2004 and was Vice President of the Rocky
Mountain and Mid-Continent Region from August 2003 through June 2004. Mr.
Magruder, a petroleum engineer, was a consultant for the Company from February
2003 through August 2003. Mr. Magruder was previously Vice President of U.S.
Operations for Calpine Natural Gas Company from 2001 to 2003. Prior to Calpine,
Mr. Magruder was employed by Barrett Resources as Vice President of Engineering
and Operations from 1996 to 2001.
GEORGE T.
CRAWFORD, 44, has been Vice President of Production since December 2000 and was
Manager of Production, from January 1999 to December 2000. Mr. Crawford, a
petroleum engineer, was previously the Production Engineering Supervisor for
ARCO Western Energy, a subsidiary of Atlantic Richfield Corp. (ARCO). Mr.
Crawford was employed by ARCO from 1989 to 1998 in numerous engineering and
operational assignments including Production Engineering Supervisor, Planning
and Evaluation Consultant and Operations Superintendent.
BRIAN L.
REHKOPF, 57, has been Vice President of Engineering since March 2000 and was
Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf, a
registered petroleum engineer, joined the Company’s engineering department in
June 1997 and was previously a Vice President and Asset Manager with ARCO
Western Energy since 1992 and an Operations Engineering Supervisor with ARCO
from 1988 to 1992. Mr. Rehkopf is also an Assistant Secretary for the
Company.SHAWN M.
CANADAY, 29, has been Treasurer since December 2004 and was Senior Financial
Analyst from November 2003 until December 2004. Mr. Canaday has worked in the
oil and gas industry since 1998 in various finance functions at ChevronTexaco
and in public accounting. Mr. Canaday is also an Assistant Secretary for the
Company.
DONALD A.
DALE, 58, has been Controller since December 1985.
KENNETH
A. OLSON, 49, has been Corporate Secretary since December 1985 and was Treasurer
from August 1988 until December 2004.
PART
II
|
Item
5. |
Market for the Registrant’s Common Equity and 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 $1.00 per share
preference in the event of liquidation or dissolution. Further, each share of
Class B Stock is convertible into one share of Common Stock at the option of the
holder.
In
November 1999, the Company adopted a Shareholder Rights Agreement and declared a
dividend distribution of one such Right for each outstanding share of Capital
Stock on December 8, 1999. Each share of Capital Stock issued after December 8,
1999 includes one Right. The Rights expire on December 8, 2009. See Note 7 of
Notes to the Financial Statements.
Berry's
Class A Common Stock is listed on the New York Stock Exchange under the symbol
(NYSE:BRY). The Class B Stock is not publicly traded. The market data and
dividends for 2004 and 2003 are shown below:
|
|
|
2004 |
|
2003 |
|
|
|
Price
Range |
|
Dividends |
|
Price
Range |
|
Dividends |
|
|
|
|
High
|
|
Low
|
|
Per
Share |
|
High
|
|
Low
|
|
Per
Share |
|
|
First
Quarter |
|
$ |
27.30 |
|
$ |
18.25 |
|
$ |
0.11 |
|
$ |
17.01 |
|
$ |
14.65 |
|
$ |
0.10 |
|
|
Second
Quarter |
|
|
31.07
|
|
|
25.09
|
|
|
0.11
|
|
|
18.38
|
|
|
14.40
|
|
|
0.15
|
|
|
Third
Quarter |
|
|
38.44
|
|
|
27.73
|
|
|
0.18
|
|
|
19.17
|
|
|
16.96
|
|
|
0.11
|
|
|
Fourth
Quarter |
|
|
50.58
|
|
|
35.16
|
|
|
0.12
|
|
|
20.95
|
|
|
17.90
|
|
|
0.11
|
|
The
closing price per share of Berry's Common Stock, as reported on the New York
Stock Exchange Composite Transaction Reporting System for March 14, 2005,
December 31, 2004 and December 31, 2003 was $55.17, $47.70, and $20.25,
respectively.
The
number of holders of record of the Company's Common Stock was 643 as of March
14, 2005. There was one Class B Shareholder of record as of March 14,
2005.
The
Company paid a special dividend of $.06 per share on September 29, 2004 and
increased its regular quarterly dividend by 9%, from $.11 to $.12 per share
beginning with the September 2004 dividend. The Company's annual dividend is
currently $.48 per share, paid quarterly in March, June, September and
December.
Since
Berry Petroleum Company's formation in 1985 through December 31, 2004, the
Company has paid dividends on its Common Stock for 61 consecutive quarters and
previous to that for eight consecutive semi-annual periods. The Company intends
to continue the payment of dividends, although future dividend payments will
depend upon the Company's level of earnings, operating cash flow, capital
commitments, financial covenants and other relevant factors. Annual dividend payments
are limited by covenants in the Company's credit facility to the greater of $13
million or 75% of net income. The total dividends paid by the Company in
2004 and 2003 were $11.4 million and $10.2 million, respectively, which is in
compliance with these covenants.
As of
December 31, 2004, dividends declared on 4,000,894 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by the Company to the surviving member of a group of individuals, the B
group, for as long as this remaining member shall live.
Equity Compensation Plan Information
|
|
|
Number
of securities to be |
|
|
|
|
|
|
|
issued
upon exercise of |
|
Weighted
average exercise |
|
Number
of securities |
|
|
|
outstanding
options, warrants |
|
price
of outstanding options, |
|
remaining
available for future |
|
|
|
and
rights (1)(3) |
|
warrants
and rights |
|
issuance
(2)(3) |
|
Plan
category
|
|
(a)
|
|
(b)
|
|
(c)
|
|
|
|
|
|
|
|
|
|
Equity
compensation plans approved
by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
compensation plans not
approved by security holders |
|
|
|
|
|
|
|
Total |
|
1,565,625 |
|
$25.41 |
|
- |
(1) Does not include 56,204 shares earned and
reserved for issuance from the Non-Employee Directors Deferred Compensation Plan
for past compensation deferred.
(2) Does not include 192,999 shares available and
reserved for future issuance from the Non-Employee Directors Deferred
Compensation Plan in lieu of future option issuance from the Company's 1994
Non-Statutory Stock Option Plan which expired on December 2, 2004.
(3) Based on historical averages, the actual
shares issued from the 1994 Non-Statutory Stock Option Plan have been at a ratio
of approximately four options exercised for each share of Common Stock issued.
The
following table sets forth certain financial information with respect to the
Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8,
“Financial Statements and Supplementary Data.” The statement of income and
balance sheet data included in this table for each of the five years in the
period ended December 31, 2004 were derived from the audited financial
statements and the accompanying notes to those financial statements (in
thousands, except per share, per BOE and % data).
| |
|
2004 |
|
2003
(1) |
|
2002
(1) |
|
2001
(1) |
|
2000
(1) |
|
Audited
Financial Information |
|
|
|
|
|
|
|
|
|
|
|
Statement
of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas |
|
$ |
226,876 |
|
$ |
135,848 |
|
$ |
102,026 |
|
$ |
100,146 |
|
$ |
118,801 |
|
|
Sales
of electricity |
|
|
47,644
|
|
|
44,200
|
|
|
27,691
|
|
|
35,133
|
|
|
51,420
|
|
|
Operating
costs – oil and gas production |
|
|
82,419
|
|
|
62,554
|
|
|
45,217
|
|
|
38,114
|
|
|
48,594
|
|
|
Operating
costs – electricity generation |
|
|
46,191
|
|
|
42,351
|
|
|
26,747
|
|
|
36,890
|
|
|
45,464
|
|
|
General
and administrative expenses (G&A) |
|
|
20,354
|
|
|
12,868
|
|
|
9,215
|
|
|
8,718
|
|
|
6,782
|
|
|
Depreciation,
depletion & amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(DD&A)
- oil and gas production |
|
|
29,752
|
|
|
17,258
|
|
|
13,388
|
|
|
13,225
|
|
|
11,374
|
|
|
DD&A
- electricity generation |
|
|
3,490
|
|
|
3,256
|
|
|
3,064
|
|
|
3,295
|
|
|
2,656
|
|
|
Net
income |
|
|
69,187
|
|
|
32,363
|
|
|
29,210
|
|
|
20,985
|
|
|
37,766
|
|
|
Basic
net income per share |
|
|
3.16
|
|
|
1.49
|
|
|
1.34
|
|
|
0.96
|
|
|
1.71
|
|
|
Diluted
net income per share |
|
|
3.08
|
|
|
1.47
|
|
|
1.33
|
|
|
0.95
|
|
|
1.71
|
|
|
Weighted
average number of shares outstanding (basic) |
|
|
21,894
|
|
|
21,772
|
|
|
21,741
|
|
|
21,973
|
|
|
22,029
|
|
|
Weighted
average number of shares outstanding (diluted) |
|
|
22,470
|
|
|
22,031
|
|
|
21,902
|
|
|
22,162
|
|
|
22,145
|
|
|
Balance
Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital |
|
$ |
(3,840 |
) |
$ |
(3,540 |
) |
$ |
(2,892 |
) |
$ |
6,314 |
|
$ |
(963 |
) |
|
Total
assets |
|
|
412,104
|
|
|
340,377
|
|
|
259,325
|
|
|
238,779
|
|
|
238,572
|
|
|
Long-term
debt |
|
|
28,000
|
|
|
50,000
|
|
|
15,000
|
|
|
25,000
|
|
|
25,000
|
|
|
Shareholders'
equity |
|
|
263,086
|
|
|
197,338
|
|
|
172,774
|
|
|
153,590
|
|
|
145,220
|
|
|
Cash
dividends per share |
|
|
0.52
|
|
|
0.47
|
|
|
0.40
|
|
|
0.40
|
|
|
0.40
|
|
|
Operating
Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations |
|
|
124,613
|
|
|
64,825
|
|
|
57,895
|
|
|
35,433
|
|
|
65,934
|
|
|
Capital
expenditures (excluding acquisitions) |
|
|
72,225
|
|
|
41,555
|
|
|
30,632
|
|
|
14,895
|
|
|
25,253
|
|
|
Property/facility
acquisitions |
|
|
2,845
|
|
|
48,579
|
|
|
5,880
|
|
|
2,273
|
|
|
3,182
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Operating Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas producing operations (per BOE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging |
|
$ |
33.64 |
|
$ |
24.48 |
|
$ |
20.11 |
|
$ |
19.63 |
|
$ |
23.01 |
|
|
Average
sales price after hedging |
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
|
19.79
|
|
|
21.72
|
|
|
Average
operating costs - oil and gas production |
|
|
10.96
|
|
|
10.37
|
|
|
8.61
|
|
|
7.64
|
|
|
9.29
|
|
|
G&A |
|
|
2.71
|
|
|
2.13
|
|
|
1.75
|
|
|
1.73
|
|
|
1.24
|
|
|
DD&A
- oil and gas production |
|
|
3.96
|
|
|
2.86
|
|
|
2.55
|
|
|
3.28
|
|
|
2.57
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
(MBOE) |
|
|
7,517
|
|
|
6,040
|
|
|
5,251
|
|
|
5,044
|
|
|
5,467
|
|
|
Production
(MWh) |
|
|
776
|
|
|
767
|
|
|
748
|
|
|
483
|
|
|
764
|
|
|
Proved
Reserves Information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
BOE |
|
|
109,836
|
|
|
109,920
|
|
|
101,719
|
|
|
102,855
|
|
|
107,361
|
|
|
Standardized
measure (2) |
|
$ |
686,748 |
|
$ |
528,220 |
|
$ |
449,857 |
|
$ |
278,453 |
|
$ |
501,694 |
|
Present
value (PV10) of estimated future net cash
flow before income taxes |
|
|
876,502
|
|
|
683,124
|
|
|
599,826
|
|
|
358,653
|
|
|
719,882
|
|
|
Year-end
average BOE price for PV10 purposes |
|
|
29.87
|
|
|
25.89
|
|
|
24.91
|
|
|
14.13
|
|
|
21.13
|
|
|
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average shareholders' equity |
|
|
31.06 |
% |
|
17.50 |
% |
|
17.90 |
% |
|
14.00 |
% |
|
28.80 |
% |
|
Return
on average total assets |
|
|
18.60 |
% |
|
10.80 |
% |
|
11.70 |
% |
|
8.80 |
% |
|
16.90 |
% |
(1)
Information has been revised to reflect the Company's change in allocation of
cogeneration costs to oil and gas operations. See Note 2 to the Company's
financial statements.
(2)
See Supplemental Information About Oil & Gas Producing
Activities.
|
Item
7. |
Management's Discussion and Analysis of Financial
Condition and Results of
Operations |
The
Company is an independent oil and natural gas exploration and production company
operating in California and the Rocky Mountain and Mid-Continent regions. The
Company's objective is to increase shareholder value by profitably growing
reserves and production, primarily through drilling operations and strategic
acquisitions. The Company seeks high quality development, exploitation and
exploration projects with potential for providing long-term drilling inventories
that generate high returns. Approximately three-quarters of the Company's
revenues are generated through the sale of oil and natural gas production under
either negotiated contracts or spot gas purchase contracts at market prices.
Over 90% of these volumes are from oil production, and the majority of those
volumes are from heavy oil production in California. The other quarter of the
Company's revenues are derived from electricity sales from cogeneration
facilities which supply over half of the Company’s steam requirement for use in
its California thermal heavy oil operations. The Company has invested in these
facilities for the purpose of lowering its steam costs which are significant in
the production of heavy crude oil.
The
Company's revenues, profitability and future growth depend substantially on
prevailing prices for oil and gas and on its ability to find, develop and
acquire oil and gas reserves that are economically recoverable. The preparation
of financial statements in conformity with generally accepted accounting
principles requires estimates and assumptions that affect its reported results
of operations and the amount of reported assets, liabilities and proved oil and
gas reserves. The Company uses the successful efforts method of accounting for
its oil and gas operations.
Oil
and Gas Prices. Prices
for oil and gas fluctuate widely. Oil and gas prices affect:
|
· |
the
profitability of the Company; |
|
· |
the
amount of cash flow available for capital expenditures;
|
|
· |
the
Company's ability to borrow and raise additional capital;
and |
|
· |
the
amount of oil and gas that the Company can economically
produce. |
Approximately
83% of the Company's current production is California heavy crude oil which
sells at a discount to WTI crude pricing. The risk of widening price
differentials between WTI and the Company's California heavy crude oil is
mitigated by a crude oil sales contract under which the Company sells over 90%
of its California production. Pricing in the existing agreement is based upon
the higher of the average of the local field posted prices plus a fixed premium,
or WTI minus a fixed differential approximating $6.00 per barrel. This contract
expires on December 31, 2005. While crude oil price differentials between WTI
and California’s heavy crude were fairly consistent in both 2002 and 2003 at
just under $6.00 per barrel, the differential widened dramatically during
2004, with the average climbing to $8.57. On December 30, 2004 the differential
ended the year at $14.19. This differential has averaged over $14.00 per barrel
in the first two months of 2005, and the Company is monitoring this differential
and trying to determine the reasons behind the breakout from the historical
norm. Subsequent to the termination of the current contract, a widening
differential between WTI and California crude oil could adversely affect the
Company's revenues, profitability and cash flows from its heavy oil operations.
The Company will enter into a new contract if favorable terms can be achieved or
may sell its crude oil into the spot market.
The
Company's cogeneration plants and conventional steam boilers require significant
volumes of natural gas for use as fuel in generating steam used in the
production of its heavy oil. A substantial increase in California natural gas
prices without a corresponding increase in heavy crude oil prices would
adversely affect the Company's California heavy oil operations. This risk is
partially offset by the Company's cogeneration plants, as their revenue is
currently linked to the price of California natural gas available for purchase
at California's border. A change in these electricity contracts to a formula
that is not closely linked to the price of California natural gas would increase
the Company's risk related to an increase in California natural gas prices. At
times, California natural gas prices have been more volatile than other markets
in the United States. To mitigate the risk of volatile California natural gas
prices, the Company has a firm transportation contract with Kern River Gas
Transmission Company for 12,000 MMBtu/D, approximately one-third of the
Company's current natural gas demand, until April 2013. There is a proceeding
currently before the Federal Energy Regulatory Commission (FERC) that may result
in an upward adjustment in the transportation charge under this contract. The
Company does not believe any such adjustment would have a material adverse
impact on its operations.
The
Company generally hedges a substantial, but varying, portion of its anticipated
future oil production and natural gas used as fuel in its enhanced oil recovery
operations. The Company uses hedging to, among other things, reduce its exposure
to commodity price fluctuations.
Reserve
Replacement.
Generally, the Company's producing properties in California have a modest
initial production rate with a gradual production decline and long reserve life.
The Company's Rocky Mountain assets have high initial production rates, followed
by steeper declines and a shorter reserve life. The Company's Niobrara natural
gas assets have modest initial production rates, a gradual decline and long
reserve life. The Company attempts to locate and develop or acquire new oil and
gas reserves to grow the Company and replace those reserves being depleted by
production. Substantial capital expenditures are required to find, develop and
acquire oil and gas reserves.
Significant
Estimates. The
Company believes the most difficult, subjective or complex judgments and
estimates it must make in connection with the preparation of its financial
statements are:
| |
· |
determining
its proved oil and gas reserves; |
| |
· |
timing
of its future drilling, development and abandonment activities;
|
| |
· |
future
costs to develop and abandon oil and gas properties;
|
| |
· |
estimates
and timing of certain tax items, deductions and credits,
|
| |
· |
estimates
related to certain, if any, environmental impacts of operations,
and |
| |
· |
the
valuation of derivative positions. |
Please
see “Other Factors Affecting the Company's Business and Financial Results” in
this Item 7 for a more detailed discussion of a number of other factors
that affect the Company's business, financial condition and results of
operations.
The
following discussion provides information on the results of operations for each
of the three years ended December 31, 2004, 2003 and 2002 and the financial
condition, liquidity and capital resources as of December 31, 2004 and 2003. The
financial statements and the notes thereto contain detailed information that
should be referred to in conjunction with this discussion.
The
profitability of the Company's operations in any particular accounting period
will be directly related to the average realized prices of oil, gas and
electricity sold, the type and volume of oil and gas produced and electricity
generated and the results of development, exploitation, acquisition and
exploration activities. The average realized prices for natural gas and
electricity will fluctuate from one period to another due to regional market
conditions and other factors, while oil prices will be predominantly influenced
by world supply and demand. The aggregate amount of oil and gas produced may
fluctuate based on the success of development and exploitation of oil and gas
reserves pursuant to current reservoir management. The cost of natural gas used
in the Company's steaming operations and electrical generation, production
rates, labor, maintenance expenses and production taxes are expected to be the
principal influences on operating costs. Accordingly, the results of operations
of the Company may fluctuate from period to period based on the foregoing
principal factors, among others.
Results
of Operations
In 2004,
the Company achieved a record year for revenue and net income. The Company
earned $69.2 million, or $3.08 per share (diluted), in 2004 on revenues of $275
million, up 114% from $32.4 million, or $1.47 per share (diluted), on revenues
of $181 million in 2003, and up from $29.2 million, or $1.33 per share
(diluted), on revenues of $131 million earned in 2002.
The
following table presents certain operating data for the years ended December
31:
|
|
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
Oil
and Gas |
|
|
|
|
|
|
|
|
Oil
Production (Bbl/D) |
|
|
19,246
|
|
|
15,966
|
|
|
14,036
|
|
|
Natural
Gas Production (Mcf/D) |
|
|
7,752
|
|
|
3,499
|
|
|
2,106
|
|
|
Total
(BOE/D) |
|
|
20,537
|
|
|
16,549
|
|
|
14,387
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Per
BOE: |
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging |
|
$ |
33.64 |
|
$ |
24.48 |
|
$ |
20.11 |
|
|
Average
sales price after hedging |
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
| |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Electricity |
|
|
|
|
|
|
|
|
|
|
|
Electric
power produced - MWh/D |
|
|
2,121
|
|
|
2,100
|
|
|
2,050
|
|
|
Electric
power sold – MWh/D |
|
|
1,915
|
|
|
1,925
|
|
|
1,848
|
|
|
Average
sales price/MWh before hedging |
|
$ |
70.24 |
|
$ |
62.91 |
|
$ |
40.06 |
|
|
Average
sales price/MWh after hedging |
|
$ |
70.24 |
|
$ |
61.95 |
|
$ |
39.64 |
|
|
Fuel
gas cost/MMBtu (excluding transportation) |
|
$ |
5.46 |
|
$ |
4.88 |
|
$ |
3.13 |
|
Revenues.
The Company's revenues are derived from the sale of its oil and gas production
and electricity generation. The Company's revenues may vary significantly from
year to year as a result of changes in commodity prices and/or production
volumes. Sales of oil and gas were $227 million in 2004, up 67% from $136
million in 2003 and up 123% from $102 million in 2002. This significant
improvement was due to increases in both oil prices and production levels. The
increase in oil prices contributed roughly two-thirds of the revenue increase
and the increase in production volumes contributed the other third. The 2004
average sales price per BOE of the Company’s oil and gas, net of hedging, was
$30.32, up 35% and 56% from $22.52 and $19.39 received in 2003 and 2002,
respectively. Approximately 94% of the Company’s oil and gas sales volumes in
2004 were crude oil, with 80% of the crude oil being heavy oil produced in
California which is sold under a contract based on the higher of WTI minus a
fixed differential or the average posted price of three local posters plus a
premium. This contract expires on December 31, 2005. With this contract in
place, the Company has effectively eliminated the risk of a differential larger
than approximately $6.00 per barrel between the Company's heavy crude oil and
WTI prices through December 31, 2005. The average differential widened during
2004 to $8.57 and was over $14.00 for the first two months of 2005. In 2004, the
Company estimates that its revenues benefited from this contract by
approximately $13 million, and at a current differential of approximately $14.00
per barrel, the Company estimates that its revenues in 2005 will benefit from
the contract by approximately $45 million. The Company is monitoring the
differential and investigating the possible reasons as to why this differential
has expanded over its historical average. While the Company believes that over
time the differential will be more in line with its historical norm, it is
unlikely that the Company will be able to obtain terms similar for crude oil
sales in 2006 to the current contract. The Company is confident that it will be
able to secure a contract for the sale of its California heavy crude oil if it
so desires. The Brundage Canyon crude oil is priced at WTI less a fixed
differential approximating $2.00 per barrel. During 2004, WTI prices per barrel
reached a high of $55.17, a low of $32.48 and averaged $41.47 for the year
compared to an average of $30.99 and $26.15 in 2003 and 2002, respectively. In
2004, the difference between WTI and the Company's average sales price, net of
hedging, consists of product quality differentials of $5.02 per BOE, hedge
payments of $3.32 per BOE, and price sensitive royalties of $2.81 per BOE.
The Company anticipates crude oil prices to remain strong in 2005 and into 2006.
However, since crude oil prices are impacted by world supply and demand,
instability in the Middle East and other factors, actual prices may vary
significantly from current prices.
As a
result of hedging activities, the Company's revenue was reduced by $24.9
million, $11.8 million and $3.8 million in 2004, 2003 and 2002, respectively,
which was reported as a reduction in "Sales of oil and gas" in the Company's
financial statements. These price hedging activities resulted in a net reduction
in revenue per BOE to the Company of $3.31 in 2004, $1.96 in 2003, and $.72 in
2002. The Company has hedged approximately 7,750 barrels per day of its oil
production for 2005 at prices averaging near WTI $40.75 per barrel. The Company
primarily is at risk to reductions in operating income as a result of declines
in crude oil and electricity prices and increases in natural gas prices. The
Company's exposure to increasing natural gas prices will be less in 2005 than
2004 due to the additional gas production from the Niobrara field and potential
increases in natural gas production in the Uinta Basin. The Company's 2005 sales
volume from natural gas is expected to approximately double from its 2004 sales
volume. To assist in mitigating these risks, the Company periodically enters
into various types of commodity hedges. See “Item 7A. Quantitative and
Qualitative Disclosures About Market Risk”.
Acquisitions.
In August
2003, the Company completed the acquisition of its Brundage Canyon properties
for approximately $45 million. The properties represented Berry’s first
substantial acquisition of a Company-operated core asset outside of California,
and was consistent with the Company’s goal of building a strong asset portfolio
in the Rocky Mountain region. At acquisition, the properties produced less than
1,200 BOE/day of light crude oil and natural gas. In 2003 and 2004, the Company
drilled 82 new wells and completed a number of workovers, increasing production
to approximately 5,000 BOE/day at December 31, 2004. The Company believes the
Rockies provide the Company with solid upside potential and is committed to
increasing its acreage position in this region. In September 2004, the
Company entered into a farm-out agreement pursuant to which Bill Barrett
Corporation had the right to earn a 75% working interest in the deep Mesaverde
formation and deeper horizons within the Brundage Canyon field by drilling a
deep exploratory test. The Company's partner commenced the drilling of its
initial deep exploratory well in Brundage Canyon in November 2004 and
abandoned it in January 2005, pending further evaluation of a 3-D seismic
survey and assessment of optimal completion technology. No costs were incurred
by the Company related to the drilling or abandonment of this well.
As part
of the Company's expansion into the Rockies, in July 2004, the Company and Bill
Barrett Corporation completed a joint exploration and development agreement with
the Ute Indian Tribe to explore for and develop potential hydrocarbons on
124,500 gross (62,250 net) prospective acres of tribal lands in the Uinta Basin
in Utah. The Company also purchased an interest in 44,500 gross (22,250 net)
acres of fee lands near and/or adjacent to the tribal acreage. The total 169,000
gross acre block is located immediately west of the Company’s Brundage Canyon
producing properties. The total cost to the Company was approximately $2
million. The Company will drill and operate the shallow wells which target light
oil in the Green River formation and retain up to a 75% working interest. The
Company's partner will drill and operate the deep wells which target natural gas
in the Mesaverde and Wasatch formations. Berry will hold up to a 25% working
interest in these deep wells The Ute Tribe has the option to participate in each
well and obtain a 25% working interest which would reduce the Company’s and its
partner's participation. The Company is committed to drill two shallow test
wells in the Green River trend and participate in one deep test well in the
Mesaverde formation in 2005. The
Company's minimum obligation under its exploration and development agreement is
$10.5 million. The
Company plans to commence drilling in the summer of 2005.
In
December 2004, the Company entered into a development agreement with
Petro-Canada Resources (USA) Inc. to develop their Coyote Flats prospect in the
Uinta Basin. The property is located approximately 45 miles southwest of the
Company’s Brundage Canyon property. The Company is obligated to drill three test
wells into the Ferron sand to a depth of approximately 7,500 feet and also drill
a six-well Emery coalbed methane pilot, at approximately 4,500 feet. Upon the
completion of this total nine well drilling program, the Company will earn an
interest in the approximately 69,250 gross acres (33,500 net). The Company has
drilled one Ferron sand test well in early 2005 which was deemed to be a dry
hole. The Company plans to drill the remaining two Ferron sand test wells and
the Emery coalbed methane pilot wells during 2005. The Company estimates that
its total cost under this agreement will be approximately $10.3 million, which
consists of $1.3 million paid at signing and approximately $9 million for the
drilling of the obligation wells. Future development plans will be
determined jointly by the Company and its 50% partner, Petro-Canada Resources.
In
January 2005, the Company acquired certain interests in the Niobrara fields in
northeastern Colorado for approximately $105 million. The properties consist of
approximately 127,000 gross (69,500 net) acres. Current production is
approximately 9 MMcf of natural gas per day, with estimated proved reserves of
87 Bcf. The acquisition also includes approximately 200 miles of a pipeline
gathering system and gas compression facilities for delivery into interstate gas
lines. In 2005, the Company plans to drill approximately 60 gross wells as part
of the development of this asset.
In
January 2005, the Company acquired a working interest in approximately 390,000
gross (172,250 net) prospective acres, located in eastern Colorado, western
Kansas and southwestern Nebraska, from Bill Barrett Corporation. The
Company and its 50% partner will jointly explore and develop shallow Niobrara
biogenic natural gas, Sharon Springs Shale gas and deeper Pennsylvanian
formation oil assets on the acreage. The Company paid approximately $5 million
for its working interest in the acreage. The
Company believes the potential of the Tri-State area can be exploited by using
new drilling
techniques, with 3-D seismic technology to assess structural complexity, and
estimate potentially recoverable oil and gas and determine drilling
locations. The
Company anticipates drilling eight gross wells with its partner in 2005 to test
the Niobrara gas potential.
Royalty
Conversion. In
December 2004 certain royalty owners exercised their right to convert their
royalty interest into a working interest on the Company's Formax property in the
Midway-Sunset field. This resulted in a reduction to the Company of 1.8
million barrels of reserves and represents approximately 450 BOE/day at year end
production levels. The Company has no other similar conversion rights
by any other current royalty owners.
Oil
and Gas Production. The
Company’s oil and gas production reached record levels in 2004, averaging 20,537
BOE/day, up 24% from its 2003 level of 16,549 BOE/day, the previous record for
the Company and up 30% from 14,387 BOE/day in 2002. This significant increase
was due primarily to the success of the Company's continued development of its
Brundage Canyon properties in Utah, acquired in August 2003. With the drilling
of 26 new wells in 2003 and 54 additional wells in
2004,
these properties contributed 4,400 BOE/day for all of 2004. With the continued development of its
California and Brundage Canyon properties and the initial development of it
newly acquired assets in the Rocky Mountain and Mid-Continent region, the
Company anticipates that oil and gas production will average in excess of 23,000
BOE/day in 2005 or an approximate 12% increase in production over 2004.
Electricity
Generation. The
Company produced 2,121 MWh/D of electricity in 2004, compared to 2,100 MWh/D in
2003 and 2,050 MWh/D produced in 2002. During 2004, the Company received an
average sales price, before hedging, for its electricity per MWh of $70.24
compared to $62.91 in 2003 and $40.06 in 2002. During 2004, electricity prices
were, relative to the cost of natural gas to generate electricity, improved from
2003. In January 2004, three Standard Offer contracts were extended on similar
terms to those in effect for 2003. This volume represented approximately 77% of
the Company’s electricity sales output. Under the terms of the Standard Offer
contracts, the price received for the electricity is based on the cost of
natural gas at the California border. The Company consumes approximately 37,000
MMBtu of natural gas per day for use in generating steam and of this total,
approximately 72% is consumed in the Company’s cogeneration operations. By
maintaining a correlation between electricity and natural gas prices, the
Company is able to better control its cost of producing steam. Depending on the
outcome of a proceeding that is currently under way at the CPUC to review and
revise the methodology to determine SRAC energy prices, this correlation between
electricity and natural gas prices may change at some point in the
future.
Three of
the SO contracts expired on December 31, 2004. However, by order of the CPUC in
January 2004, the respective utilities were ordered to continue to offer SO1
contracts for an additional term of five years to certain QFs, such as the
Company. In December 2004, the Company executed a five year contract with Edison
for the Placerita Unit 2 facility, and five year contracts with PG&E for the
Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Edison and
PG&E have challenged, in the California Court of Appeal, the legality of the
CPUC decision that ordered the utilities to enter into the one-year SO contracts
for 2004, and the decision that ordered the utilities to enter five-year SO
contracts. Arguments in this case were heard by the court in March 2005. Based
on the current pricing mechanism for its electricity under the contracts, the
Company expects that its electricity revenues will be in the $45 to $50 million
range for 2005 and that these operations will be marginally profitable before
any DD&A charges.
In 2002,
the Company recorded income of $3.6 million, which represented the recovery of a
portion of the $6.6 million of the receivables from electricity sales that were
written off in 2001 due to non-payment by utilities contractually obligated to
purchase the Company’s electricity.
Oil
and Gas Operating Expenses. The
Company believes 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 Company revised its allocation of cogeneration costs to oil and
gas operations during 2004. Operating costs information has been revised to
reflect this allocation which is based on the conversion efficiency (of fuel to
electricity and steam) of the Company's cogeneration plants. The following table
presents information about the Company's operating expenses for each of the
years in the two-year period ended December 31, 2004:
| |
|
Amount
per BOE |
|
Amount
(in thousands) |
|
|
|
|
|
|
|
% |
|
|
|
|
|
% |
|
|
|
|
2004 |
|
2003 |
|
Change |
|
2004 |
|
2003 |
|
Change |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs |
|
$ |
10.96 |
|
$ |
10.36 |
|
|
6 |
% |
$ |
82,419 |
|
$ |
62,554 |
|
|
32 |
% |
|
DD&A |
|
|
3.96
|
|
|
2.86
|
|
|
38 |
% |
|
29,752
|
|
|
17,258
|
|
|
72 |
% |
|
G&A |
|
|
2.71
|
|
|
2.13
|
|
|
27 |
% |
|
20,354
|
|
|
12,868
|
|
|
58 |
% |
|
Interest
expense |
|
|
0.27
|
|
|
0.23
|
|
|
17 |
% |
|
2,067
|
|
|
1,414
|
|
|
46 |
% |
|
Total |
|
$ |
17.90 |
|
$ |
15.58 |
|
|
15 |
% |
$ |
134,592 |
|
$ |
94,094 |
|
|
43 |
% |
Table of Contents
The
Company's total operating expenses for 2004, stated on a unit-of-production
basis, increased 15% over 2003. The increase was primarily related to the
following items:
|
|
|
Operating costs for 2004, on a per barrel basis, increased 6% over 2003.
The cost of the Company's steaming operations for its heavy oil properties
represents a significant portion of the Company's operating costs and will
vary depending on both the cost of natural gas used as fuel and the volume
of steam injected during the year. Steam costs were higher in 2004 as the
cost for natural gas per MMBtu increased to $5.46 from $4.88 in 2003, an
increase of 12%. The Company also injected an average of 69,200 BSPD in
2004, up 9% from 63,300 BSPD in 2003. Assuming stable crude oil and
natural gas prices, the Company plans to inject steam at levels in 2005
comparable to 2004 levels and anticipates operating costs in 2005, on a
per BOE basis, to average between $13.25 and $14.25 in its California
operations, between $8.50 and $9.50 in its Utah operations and between
$11.75 and $12.75 for the total Company. |
|
|
|
DD&A
was $3.96 per BOE in 2004, up 38% from $2.86 per BOE in 2003.
DD&A in 2004 was higher due to the shorter reserve life of the
Brundage Canyon properties in Utah and the cumulative effect of increased
development activities in recent years. The Company expects DD&A to
trend higher over the next few years due to the shorter reserve life of
the Rocky Mountain assets compared to the Company's California properties
and continued development of its California and Rocky Mountain properties.
The Company anticipates its oil and gas DD&A charges for 2005 will
range from $4.25 to $4.75 per BOE. |
| |
· |
G&A
expenses in 2004 were $2.71 per BOE, up 27% from $2.13 per BOE in 2003.
Stock based compensation costs increased by $2.8 million in 2004, which
are primarily non-cash charges resulting from mark-to-market adjustments
under the variable method of accounting prior to the change of certain
exercise provisions of the Company's stock option plan on July 29, 2004
and non-cash compensation expense under the fair value method of
accounting. Compensation expenses increased by $2.3 million due to
increased staffing resulting from the Company's growth, an increase in
compensation levels and bonuses and costs related to a change in chief
executive officers. Additionally, the Company incurred increased legal and
accounting fees during 2004 of approximately $1 million, primarily due to
compliance with Sarbanes-Oxley and other financial reporting related
matters. For 2005, the Company anticipates that its G&A expenses will
range from approximately $16 million to $19 million or $1.75 to $2.25 per
BOE. |
| |
· |
Interest
expense in 2004 was $.27 per BOE, up from $.23 per BOE in 2003. The
Company’s borrowings at year-end 2004 were $28 million, down from $50
million in 2003. The Company borrowed $40 million in August 2003 to fund
the acquisition of its Brundage Canyon property. The Company reduced its
debt from 2003 levels during the latter half of 2004. Upon the close of
its Niobrara gas acquisition in January of 2005 the Company’s outstanding
borrowings rose to over $130 million. The Company anticipates that its
interest cost for 2005 will be approximately $4 million to $5 million, or
$.45 to $.60 per BOE. |
The
following table presents information about the Company's operating expenses for
each of the years in the two-year period ended December 31, 2003:
|
|
|
Amount
per BOE |
|
Amount
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
Change |
|
2003 |
|
2002 |
|
Change |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs |
|
$ |
10.36 |
|
$ |
8.61 |
|
|
20 |
% |
$ |
62,554 |
|
$ |
45,217 |
|
|
38 |
% |
|
DD&A |
|
|
2.86
|
|
|
2.55
|
|
|
12 |
% |
|
17,258
|
|
|
13,388
|
|
|
29 |
% |
|
G&A |
|
|
2.13
|
|
|
1.75
|
|
|
22 |
% |
|
12,868
|
|
|
9,215
|
|
|
40 |
% |
|
Interest
expense |
|
|
0.23
|
|
|
0.20
|
|
|
15 |
% |
|
1,414
|
|
|
1,042
|
|
|
36 |
% |
|
Total |
|
$ |
15.58 |
|
$ |
13.11 |
|
|
19 |
% |
$ |
94,094 |
|
$ |
68,862 |
|
|
37 |
% |
The
Company's total operating expenses for 2003, stated on a unit-of-production
basis, increased 19% over 2002. The increase was primarily related to the
following items:
| |
· |
Operating
costs for 2003, on a per barrel basis, increased 20% over 2002. The cost
of the Company's steaming operations for its heavy oil properties
represents a significant portion of the Company's operating costs and will
vary depending on both the cost of natural gas used as fuel in the
steaming operations and the volume of steam injected during the year.
Steam costs were higher in 2003 as the cost for natural gas per MMBtu
increased to $4.88 from $3.13 in 2002. The Company also injected an
average of 63,300 BSPD in 2003, up 5% from 60,060 BSPD in 2002.
|
| |
· |
DD&A
was $2.86 per BOE in 2003, up 12% from $2.55 per BOE in 2002. DD&A in
2003 was higher due to the shorter reserve life of the Brundage Canyon
properties in Utah and the cumulative effect of increased development
activities in recent years. |
| |
· |
G&A
expenses in 2003 were $2.13 per BOE, up 22% from $1.75 per BOE in 2002.
The majority of the increase was due to stock option compensation of $3.9
million in 2003 compared to $1.3 million in 2002, which are primarily
non-cash charges resulting from mark-to-market adjustments under the
variable method of accounting. Also contributing to the increase in 2003
was higher compensation expenses, the opening of a regional office in the
Rocky Mountains, a higher level of acquisition activity and increased
accounting and consulting charges incurred in 2003.
|
| |
· |
Interest
expense in 2003 was $.23 per BOE, up from $.20 per BOE in 2002. The
Company’s borrowings at year-end 2003 were $50 million, up from $15
million in 2002 due to the acquisition of its Brundage Canyon properties
in August 2003. |
Electricity
Operating Costs. The
Company allocates cogeneration costs 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.
As a result of this allocation, cogeneration costs allocated to electricity will
vary based on, among other factors, the thermal efficiency of the Company's
cogeneration plants, the price of natural gas used for fuel in generating
electricity and steam, and the terms of the Company's power contracts. The
Company’s investment in its cogeneration facilities has been for the express
purpose of lowering the steam costs in its heavy oil operations and securing
operating control of the respective steam generation. As such, the Company views
any profit or loss from the generation of electricity as a decrease or increase,
respectively, to its total cost of producing its heavy oil in California. The
gross profit (sales of electricity less electricity operating costs) for the
years ended December 31, 2004, 2003 and 2002 was $1.5 million, $1.8 million and
$.9 million, respectively. On a per barrel basis, the Company views this gross
profit as a decrease of $.19, $.32 and $.18 to the Company's total oil and gas
operating expenses. DD&A related to the Company's cogeneration facilities is
allocated between electricity operations and oil and gas operations using a
similar allocation method.
Income
Taxes. The
Company experienced an effective tax rate of 23% in 2004, up from 12% and 20%
reported in 2003 and 2002, respectively. The increase in effective tax rate
during 2004 is primarily due to a much higher (over 100% increase) pre-tax
income in 2004 over 2003. The Company's expansion outside of California and
investment in non-thermal projects are also key factors in the increase. The
Company is able to achieve an effective tax rate below the statutory tax rate of
approximately 40% primarily as a result of significant EOR tax credits earned by
the Company’s continued investment in the development of its thermal EOR
projects, both through capital expenditures and continued steam injection The
Company believes it will continue to earn significant EOR tax credits. The
Company expects its effective tax rate will trend higher as it diversifies its
activities outside California and expects to have an effective tax rate in the
30% to 35% range in 2005, based on WTI prices averaging between $40 and
$50.
Coalbed
Methane Prospect. During
2002 and early 2003, the Company leased a total of approximately 208,000 net
acres in Kansas and 54,000 net acres in Illinois to explore for economic
concentrations of coalbed methane at a total lease cost of approximately $6
million. A five-well pilot was drilled in the Wabaunsee County portion of the
Kansas acreage in the fourth quarter of 2002. After testing, the Company
concluded that this pilot would not produce commercial quantities of natural gas
and, therefore, wrote off the cost to drill these wells and the associated
acreage in 2003 for a pre-tax charge to operations of $2.5 million.
In August
2003, the Company completed the sale of approximately 43,000 leased net acres in
Jackson County, Kansas for approximately $1.7 million, while retaining an
overriding royalty interest in the property. The Company recovered its cost
associated with this acreage.
The
Company also drilled a second five-well pilot in Jasper County, Illinois in the
fourth quarter of 2002. After testing it was determined that gas volumes were
not likely to be sufficient to realize commercial production; therefore, the
costs to drill these wells and an impairment of the acreage was recorded in the
fourth quarter of 2003, which resulted in a pre-tax charge of $1.7 million.
In 2005,
the Company will evaluate if it is advantageous to retain the properties, but
currently has no capital allocated for further testing of these
properties.
Dry
hole, Abandonment and Impairment. At
December 31, 2004, the Company was in the process of drilling one exploratory
well on its Midway-Sunset property and one exploratory well on its Coyote Flats
prospect. These two wells were determined non-commercial in February 2005. Costs
of $.5 million which were incurred as of December 31, 2004 were charged to
expense and are reflected on the Company's income statement under "Dry-hole,
abandonment and impairment." Remaining costs related to these wells are
approximately $2.5 million which will be charged to expense during the first
quarter of 2005.
During
2003, the Company recorded a pre-tax write down of $4.2 million related to two
CBM pilot projects. For the periods ended December 31, 2004 and December 31,
2002, the fair value of the Company's oil and gas properties exceeded their
carrying cost and as a result, the Company did not write down any of its oil and
gas properties.
Other.
In 2002,
the Company recorded income of $3.6 million, which represented the recovery of
receivables from electricity sales that were written off in 2001 due to
non-payment by utilities contractually obligated to purchase the Company's
electricity.
Financial
Condition, Liquidity and Capital Resources
Substantial
capital is required to replace and grow reserves. The Company achieves reserve
replacement and growth primarily through successful development and exploration
drilling and the acquisition of properties. Fluctuations in commodity prices
have been the primary reason for short-term changes in the Company's cash flow
from operating activities. The net long-term growth in the Company's cash flow
from operating activities is the result of growth in production as affected by
period to period fluctuations in commodity prices.
The
Company establishes a capital budget for each calendar year based on its
development opportunities and the expected cash flow from operations for that
year. The Company may revise its capital budget during the year as a result of
acquisitions and/or drilling outcomes. Excess cash generated from operations is
normally applied to debt reduction during the year.
Working
Capital and Cash Flows. The
Company's working capital balance fluctuates as a result of the timing and
amount of borrowings or repayments under its credit arrangements. Generally, the
Company uses excess cash to pay down borrowings under its credit arrangement. As
a result, the Company often has a working capital deficit or a relatively small
amount of positive working capital. Working capital as of December 31, 2004 was
negative ($3.8) million, up from a negative ($3.5) million at December 31, 2003.
Cash flow from operations is dependent upon the Company's ability to increase
production through development, exploration and acquisition activities and the
price of natural gas and oil. The Company's cash flow from operations also is
impacted by changes in working capital. Net cash provided by operating
activities increased to $125 million, up 92% from $65 million in 2003 and up
116% from $58 million in 2002. The increase in 2004 was a direct result of the
increases in crude oil prices and production levels in 2004 compared to 2003 and
2002. Sales of oil and gas increased $91 million in 2004 compared to 2003, with
crude oil prices, net of hedges, increasing 34% and production increasing 24% in
2004 compared to 2003. Cash flow was impacted by a 59% increase, or $19.2
million, in accounts payable and revenue and royalties payable due to increased
capital expenditures in 2004, the continued development of both the California
and Utah assets and due to a $9.1
million increase in a price sensitive royalty on one of the Company's California
properties. Cash flow was also impacted by a 47% increase, or $11.1 million, in
accounts receivable due to the increases in oil prices and production volumes
and a full year of production at Brundage Canyon. The Company’s net decrease in
borrowings on its credit line was $22 million in 2004. Cash was used for capital
expenditures of $72 million, to fund $3 million in property acquisitions and to
pay dividends of $11.4 million.
Capital
Expenditures. Total
capital expenditures in 2004, excluding acquisitions, were $72 million and
included the drilling of 60 new wells and completing 34 workovers on its
California properties and the drilling of 56 new wells and completion of 46
workovers on its Brundage Canyon properties in Utah.
Assuming
stable oil and gas prices, excluding any future acquisitions in 2005, the
Company plans to spend at least $107 million on capital projects including $36
million to drill 76 new wells and perform 38 workovers in California and $71
million to drill 107 new wells and perform 32 workovers in the Rocky Mountain
and Mid-Continent regions from internally generated cash flow. With this
increased development, the Company anticipates that production will average in
excess of 23,000 BOE/day in 2005, up over 12% from an average 20,537 BOE per day
in 2004.
Credit
Facility. The
Company successfully completed a new $200 million unsecured three-year credit
facility in July 2003. The facility replaced the previous $150 million unsecured
facility which was due to mature in January 2004. The 2003 facility recognizes
the Company's strong financial position and provides significant low-cost
capital for the Company to meet its growth objectives. In August 2003, the
Company drew upon this facility to finance the $45 million purchase of the
Brundage
Canyon, Utah assets. As of December 31, 2004, the Company had $172 million
available under the facility. The Company drew on its credit facility to fund
its acquisition of certain assets in the Niobrara field in January 2005. As of
March 1, 2005, the Company's borrowing under its credit facility totaled $144
million. Exclusive of any further acquisitions in 2005, the Company plans to
reduce debt levels from excess cash generated from operating activities.
The
facility is a revolving credit facility for up to $200 million with ten banks.
At December 31, 2004 and 2003, the Company had $28 million and $50 million,
respectively, outstanding under the facility. In addition to the $28 million in
borrowings under the Agreement, the Company has $.5 million of outstanding
Letters of Credit and the remaining credit available under the facility is
therefore, $172 million at December 31, 2004. The maximum amount available is
subject to an annual borrowing base redetermination in accordance with the
lenders' customary procedures and practices. The facility matures on July 10,
2006. Interest on amounts borrowed is charged at LIBOR plus a margin of 1.25% to
2.00%, or the higher of the lead bank’s prime rate or the federal funds rate
plus 50 basis points plus a margin of 0.0% to 0.75%, with margins on the various
rate options based on the ratio of credit outstanding to the borrowing base. The
Company pays a commitment fee of 30 to 50 basis points on the unused portion,
which is also based on the ratio of credit outstanding to the borrowing base.
Given that the credit markets have improved over the last year and the Company
believes that its borrowing capacity has expanded, the Company intends to
negotiate a new credit facility in 2005.
The
weighted average interest rate on outstanding borrowings at December 31, 2004
was 3.37%. The facility contains restrictive covenants which, among other
things, require the Company to maintain a certain tangible net worth and minimum
EBITDA, as defined. The Company was in compliance with all such covenants as of
December 31, 2004.
At
year-end, the Company had no subsidiaries, no special purpose entities and no
off-balance sheet debt. The Company did not enter into any significant related
party transactions in 2004.
Contractual
Obligations
|
The
Company's contractual obligations as of December 31, 2004 are as follows
(in thousands): |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
than |
|
1-3
|
|
3-5 |
|
More
than |
|
|
Contractual
Obligations |
|
Total |
|
1
year |
|
years |
|
years |
|
5
years |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt |
|
$ |
28,000 |
|
$ |
- |
|
$ |
28,000 |
|
$ |
- |
|
$ |
- |
|
|
Abandonment
obligations |
|
|
8,214
|
|
|
304
|
|
|
871
|
|
|
1,064
|
|
|
5,975
|
|
|
Operating
lease obligations |
|
|
1,423
|
|
|
621
|
|
|
676
|
|
|
126
|
|
|
-
|
|
|
Drilling
obligation |
|
|
10,525
|
|
|
925
|
|
|
4,250
|
|
|
5,350
|
|
|
-
|
|
|
Firm
natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
transportation
contract |
|
|
23,438
|
|
|
2,814
|
|
|
5,628
|
|
|
5,628
|
|
|
9,368
|
|
|
Total |
|
$ |
71,600 |
|
$ |
4,664 |
|
$ |
39,425 |
|
$ |
12,168 |
|
$ |
15,343 |
|
Oil
and Gas Hedging. From time
to time, the Company enters into crude oil and natural gas hedge contracts, the
terms of which depend on various factors, including Management’s view of future
crude oil prices and the Company’s future financial commitments. This hedging
program is designed to moderate the effects of a severe price downturn while
allowing Berry to participate in the upside. Currently, the hedges are in the
form of swaps, however, the Company may use a variety of hedge instruments in
the future. These hedging activities resulted in a net reduction in revenue per
BOE to the Company of $3.31 in 2004, $1.96 in 2003 and $.72 in
2002.
While the
use of these hedging arrangements reduces the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements.
In addition, the use of hedging transactions may involve basis risk. The
Company's oil hedges are based on reported settlement prices on the NYMEX. The
basis risk between NYMEX and the Company's California heavy crude oil is
mitigated by the Company's crude oil sales contract under which the Company
sells over 90% of its California production. Pricing in the existing agreement
is based upon the higher of the average of the local field posted prices plus a
fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel.
This contract expires on December 31, 2005.
The use
of hedging transactions also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. With respect to the
Company’s hedging activities, the Company utilizes multiple counterparties on
its hedges and monitors each counterparty’s credit rating.
Application
of Critical Accounting Policies
The
preparation of financial statements in conformity with generally accepted
accounting principles requires Management to make estimates and assumptions for
the reporting period and as of the financial statement date. These estimates and
assumptions affect the reported amounts of assets and liabilities, the
disclosure of contingent liabilities and the reported amounts of revenues and
expenses. Actual results could differ from those amounts.
A
critical accounting policy is one that is important to the portrayal of the
Company's financial condition and results, and requires Management to make
difficult subjective and/or complex judgments. Critical accounting policies
cover accounting matters that are inherently uncertain because the future
resolution of such matters is unknown. The Company believes the following
accounting policies are critical policies.
Successful
Efforts Method of Accounting. The
Company accounts for its oil and gas exploration and development costs using the
successful efforts method. Geological and geophysical costs and the costs of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes. All
exploratory wells are evaluated for economic viability within one year of well
completion. Exploratory wells that discover potentially economic reserves that
are in areas where a major capital expenditure would be required before
production could begin, and where the economic viability of that major capital
expenditure depends upon the successful completion of further exploratory work
in the area, remain capitalized as long as the additional exploratory work is
under way or firmly planned.
Oil
and Gas Reserves. Oil and
gas reserves include proved reserves that represent estimated quantities of
crude oil and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. The Company's oil and gas
reserves are based on estimates prepared by independent engineering consultants.
Reserve engineering is a subjective process that requires judgment in the
evaluation of all available geological, geophysical, engineering and economic
data. Projected future production rates, the timing of future capital
expenditures as well as changes in commodity prices may significantly impact
estimated reserve quantities. Depreciation, depletion and amortization
(DD&A) expense and impairment of proved properties are impacted by the
Company's estimation of proved reserves. These estimates are subject to change
as additional information and technologies become available. Accordingly, oil
and natural gas quantities ultimately recovered and the timing of production may
be substantially different than projected. Reduction in reserve estimates may
result in increased DD&A expense, increased impairment of proved properties
and a lower standardized measure of discounted future net cash
flows.
Carrying
Value of Long-lived Assets.
Downward
revisions in the Company’s estimated reserve quantities, increases in future
cost estimates or depressed crude oil or natural gas prices could cause the
Company to reduce the carrying amounts on its properties. The Company performs
an impairment analysis of its proved properties annually by comparing the future
undiscounted net revenue per the annual reserve valuation prepared by the
Company’s independent reserve engineers to the net book carrying value of the
assets. An analysis of the proved properties will also be performed whenever
events or changes in circumstances indicate an asset’s carrying value may not be
recoverable from future net revenue. Assets are grouped at the field level and
if it is determined that the net book carrying value cannot be recovered by the
estimated future undiscounted cash flow, they are written down to fair value.
For its unproved properties, the Company performs an impairment analysis
annually or whenever events or changes in circumstances indicate an asset’s net
book carrying value may not be recoverable. Cash flows used in the impairment
analysis are determined based on management’s estimates of crude oil and natural
gas reserves, future crude oil and natural gas prices and costs to extract these
reserves.
Derivatives
and Hedging. The
Company follows the provisions of Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting
for Derivative Instruments and Hedging Activities. SFAS
133 requires the accounting recognition of all derivative instruments as either
assets or liabilities at fair value. Derivative instruments that are not hedges
must be adjusted to fair value through net income. Under the provisions of SFAS
133, the Company may designate a derivative instrument as hedging the exposure
to change in fair value of an asset or liability that is attributable to a
particular risk (a fair value hedge) or as hedging the exposure to variability
in expected future cash flows that are attributable to a particular risk (a cash
flow hedge). Both at the inception of a hedge and on an ongoing basis, a fair
value hedge must be expected to be highly effective in achieving offsetting
changes in fair value attributable to the hedged risk during the periods that a
hedge is designated. Similarly, a cash flow hedge must be expected to be highly
effective in achieving offsetting cash flows attributable to the hedged risk
during the term of the hedge. The expectation of hedge effectiveness must be
supported by matching the essential terms of the hedged asset, liability or
forecasted transaction to the derivative contract or by effectiveness
assessments using statistical measurements. The Company's policy is to assess
hedge effectiveness at the end of each calendar quarter.
Income
Taxes. The
Company computes income taxes in accordance with SFAS No. 109, Accounting
for Income Taxes. SFAS
No. 109 requires an asset and liability approach which results in the
recognition of deferred income taxes on the difference between the tax basis of
an asset or liability and its carrying amount in the Company's financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively. Considerable judgment is required in determining when
these events may occur and whether recovery of an asset is more likely than not.
Additionally, the Company's federal and state income tax returns are generally
not filed before the financial statements are prepared, therefore the Company
estimates the tax basis of its assets and liabilities at the end of each
calendar year as well as the effects of tax rate changes, tax credits, and tax
credit carryforwards. Adjustments related to differences between the estimates
used and actual amounts reported are recorded in the period in which income tax
returns are filed. These adjustments and changes in estimates of asset recovery
could have an impact on results of operations. The Company generates enhanced
oil recovery tax credits from the production of its heavy crude oil in
California which results in a deferred tax asset. The Company believes that
these credits will be fully utilized in future years and consequently has not
recorded any valuation allowance related to these credits. Due to uncertainties
involved with tax matters, the future effective tax rate may vary significantly
from the estimated current year effective tax rate.
Asset
Retirement Obligations. The
Company has significant obligations to plug and abandon oil and natural gas
wells and related equipment at the end of oil and gas production operations. The
computation of the Company's asset retirement obligations (ARO) was prepared in
accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations, which
requires the Company to record the fair value of liabilities for retirement
obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted
in an immaterial difference in the liability that had been previously recorded
by the Company. Estimating the future ARO requires Management to make estimates
and judgments regarding timing, current estimates of plugging and abandonment
costs, as well as what constitutes adequate remediation. The Company obtained
estimates from third parties and used the present value of estimated cash flows
related to its ARO to determine the fair value. Inherent in the present value
calculation are numerous assumptions and judgments including the ultimate costs,
inflation factors, credit adjusted discount rates, timing of settlement and
changes in the legal, regulatory, environmental and political environments.
Changes in any of these assumptions can result in significant revisions to the
estimated ARO. To the extent future revisions to these assumptions impact the
present value of the existing ARO liability, a corresponding adjustment will be
made to the related asset. Due to the subjectivity of assumptions and the
relatively long life of the Company's assets, the costs to ultimately retire the
Company's wells may vary significantly from previous estimates.
Environmental
Remediation Liability. The
Company reviews, on a quarterly basis, its estimates of costs of the cleanup of
various sites including sites in which governmental agencies have designated the
Company as a potentially responsible party. In accordance with SFAS No. 5,
Accounting
for Contingencies, when it
is probable that obligations have been incurred and where a minimum cost or a
reasonable estimate of the cost of remediation can be determined, the applicable
amount is accrued. Determining when expenses should be recorded for these
contingencies and the appropriate amounts for accrual is an estimation process
that includes the subjective judgment of Management. In many cases, Management's
judgment is based on the advice and opinions of legal counsel and other
advisers, the interpretation of laws and regulations, which can be interpreted
differently by regulators or courts of law, the experience of the Company and
other companies in dealing with similar matters and the decision of Management
on how it intends to respond to a particular matter. A change in estimate could
impact the Company's oil and gas operating costs and the liability, if
applicable, recorded on the Company's balance sheet.
Recent
Accounting Developments
In
December 2004, the Financial Accounting Standards Board (FASB) issued SFAS
123(R), Share-Based
Payments, which
is a revision of SFAS 123. SFAS 123(R) supersedes APB 25 and amends Statement of
Accounting Standards No. 95, Statement
of Cash Flows.
Generally, the approach in SFAS 123(R) will require all share-based payments to
employees, including grants of employee stock options, to be recognized based on
their fair values. SFAS 123(R) must be adopted by the Company no later than the
third quarter of 2005. The
Company voluntarily adopted SFAS 123 as of January 1, 2004 and does not expect
SFAS 123(R) will have a material impact on the Company's financial position, net
income or cash flows.
In
December 2004, the FASB issued FASB Staff Position (FSP) FAS 109-1, Application
of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction
Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004,
This position clarifies how to apply SFAS No. 109 to the new law's tax deduction
for income attributable to "domestic production activities." The Company does
not expect this statement will have a material impact on the Company's financial
position, net income or cash flows.
In
January 2005, the FASB issued SFAS No. 153, Exchanges
of Nonmonetary Assets - an amendment of APB Opinion No. 28. This
statement, which addresses the measurement of exchanges of nonmonetary assets,
is effective prospectively for nonmonetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. The adoption of this statement is not
expected to impact the Company's financial position, net income, or cash
flows.
Impact
of Inflation
The
impact of inflation on the Company has not been significant in recent years
because of the relatively low rates of inflation experienced in the United
States.
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 the Company's business.
The
Company's revenues, profitability and future growth depend substantially on
reasonable prices for oil and gas. These prices also affect the amount of cash
flow available for capital expenditures and the ability to borrow and raise
additional capital. The amount the Company can borrow under its credit facility
is subject to periodic asset redeterminations based in part on changing
expectations of future crude oil and natural gas prices. Lower prices may also
reduce the amount of oil and gas that can be economically produced.
Among the
factors that can cause fluctuations are:
| |
· |
the
domestic and foreign supply of oil and natural
gas; |
| |
· |
the
price and availability of alternative
fuels; |
| |
· |
the
level of consumer demand; |
| |
· |
the
price of foreign imports; |
| |
· |
world-wide
economic conditions; |
| |
· |
political
conditions in oil and gas producing
regions; |
| |
· |
the
change in the value of the U.S. dollar as global oil prices are priced in
U. S. dollars; and |
| |
· |
domestic
and foreign governmental regulations. |
The
Company's heavy crude in California is less economic than lighter crude oil and
natural gas. As of
December 31, 2004, approximately 88% of the Company's proved reserves, or 97
million barrels, consisted of heavy oil. Heavy oil sells for less than light
sweet crudes, over the past ten years, approximately $6.00 per barrel less. However, this
differential widened during 2004, averaging $8.57 and has averaged over $14.00
during the first two months of 2005. Additionally, most of the Company's heavy
oil production requires heat, in the form of steam, to mobilize the oil for
production from the wellbore. Steam costs represent a significant portion of the
Company's operating costs and are costs that the production of light crude oil
or natural gas do not have. This thermal enhanced process and the related costs
further reduce the Company's margins on its heavy crude oil. The Company
consumes natural gas to generate steam and thus is at risk when natural gas
prices rise without a corresponding rise in crude oil prices.
A
widening of commodity differentials may adversely impact the Company’s revenues
and per barrel economics. Both the
Company’s produced crude oil and natural gas is subject to pricing in the local
markets where the production occurs. It is customary that such product is priced
based on local or regional supply and demand factors. California heavy crude
sells at a substantial discount to WTI, the U.S. benchmark crude oil, primarily
due to the additional cost to refine more gasoline or light product out of a
barrel of heavy crude. The Company’s Utah light crude also is normally priced
below WTI. Natural gas field prices are normally priced off of NYMEX traded
prices or Henry Hub, the benchmark for U.S. natural gas. While the Company
attempts to contract for the best possible price in each of its producing
locations, there is no assurance that past price differentials will continue
into the future. Numerous factors may influence local pricing, such as refinery
capacity, pipeline capacity and specifications, upsets in the mid-stream or
downstream sectors of the business, trade restrictions, governmental
regulations, etc. The Company may be adversely impacted by a widening
differential on the products it sells.
The
future of the electricity market in California is
uncertain. The
Company utilizes cogeneration plants in California to generate lower cost steam
compared to conventional steam generation methods. Electricity produced by the
Company's cogeneration plants is sold to utilities and the steam costs are
allocated to the Company’s oil and gas operations. While the Company has new
five-year electricity sales contracts in place with the utilities beginning on
January 1, 2005, legal and regulatory decisions, especially related to the
pricing of electricity under the contracts, can adversely affect the economics
of the Company’s cogeneration facilities and thereby, the cost of steam for use
in the Company’s oil and gas operations. In addition, the utilities are seeking
to overturn the CPUC order to offer such contracts.
The
Company may be subject to the risk of adding additional steam generation
equipment if the electrical market deteriorates
significantly.
The
Company may be subject to the risk of adding additional steam generation
equipment if the electrical market deteriorates significantly. The Company is
dependent on several cogeneration facilities that provide over half of its steam
requirement. These facilities are dependent on reasonable electrical contracts
to provide economic steam for use in the Company's operations. If, for any
reason, the Company was unable to enter into an electrical contract or were to
lose an existing contract, the Company may not be able to supply 100% of the
steam requirements necessary to maximize production from its heavy oil assets.
An additional investment in various steam sources may be necessary to replace
such steam. The financial cost and timing of such investment may adversely
affect the Company's production and cash provide by operating
activities.
A
shortage of natural gas in California could adversely affect the Company's
business. The
Company may be subject to the risks associated with a shortage of natural gas
and/or the transportation of natural gas into California. The Company is highly
dependent on sufficient volumes of natural gas that it uses for fuel in
generating steam for use in its heavy oil operations in California. If the
required volume of natural gas for use in its operations were to be unavailable
or too highly priced to produce heavy oil economically, the Company's production
could be adversely impacted.
The
Company's use of oil and gas price hedging contracts involves credit risk and
may limit future revenues from price increases and result in significant
fluctuations in net income. The
Company uses hedging transactions with respect to a portion of its oil and gas
production to achieve more predictable cash flow and to reduce its exposure to a
significant decline in the price of crude oil. While the use of hedging
transactions limits the downside risk of price declines, their use may also
limit future revenues from price increases. Hedging transactions also involve
the risk that the counterparty may be unable to satisfy its obligations.
The
Company's future success depends on its ability to find, develop and acquire oil
and gas reserves. To
maintain production levels, the Company must locate and develop or acquire new
oil and gas reserves to replace those depleted by production. Without successful
exploration, exploitation or acquisition activities, the Company's reserves,
production and revenues will decline. The Company may not be able to find and
develop or acquire additional reserves at an acceptable cost. In addition,
substantial capital is required to replace and grow reserves. If lower oil and
gas prices or operating difficulties result in the Company's cash flow from
operations being less than expected or limit its ability to borrow under credit
arrangements, the Company may be unable to expend the capital necessary to
locate and develop or acquire new oil and gas reserves.
Actual
quantities of recoverable oil and gas reserves and future cash flows from those
reserves most likely will vary from estimates. Estimating
accumulations of oil and gas is complex. The process relies on interpretations
of available geologic, geophysical, engineering and production data. The extent,
quality and reliability of this data can vary. The process also requires certain
economic assumptions, some of which are mandated by the Securities and Exchange
Commission (SEC), such as oil and gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. The accuracy of a reserve
estimate is a function of:
| |
· |
the
quality and quantity of available data; |
| |
· |
the
interpretation of that data; |
| |
· |
the
accuracy of various mandated economic
assumptions; and |
| |
· |
the
judgment of the persons preparing the
estimate. |
Actual
quantities of recoverable oil and gas reserves, future production, oil and gas
prices, revenues, taxes, development expenditures and operating expenses most
likely will vary from estimates. Any
significant variance could materially affect the quantities and present value of
the Company's reserves. In addition, the Company 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, the Company bases the estimated discounted
future net cash flows from proved reserves on prices and costs on the date of
the estimate. Actual future prices and costs may be materially higher or lower
than the prices and costs as of the date of the estimate.
If
oil and gas prices decrease, the Company may be required to take writedowns.
The
Company may be required to writedown the carrying value of its oil and gas
properties when oil and gas prices are low, including basis differentials, or
there are substantial downward adjustments to its estimated proved reserves,
increases in estimates of development costs or deterioration in exploration or
production results.
The
Company capitalizes costs to acquire, find and develop its oil and gas
properties under the successful efforts accounting method. The net capitalized
costs of the Company's oil and gas properties may not exceed the fair market
value.
If net
capitalized costs of its oil and gas properties exceed fair value, the Company
must charge the amount of the excess to earnings. The Company reviews the
carrying value of its properties annually and at any time when events or
circumstances indicate a review is necessary, based on prices in effect as of
the end of the reporting period. The carrying value of oil and gas properties is
computed on a field-by-field basis. Once incurred, a writedown of oil and gas
properties is not reversible at a later date even if oil or gas prices increase.
The
Company may be subject to risks in connection with
acquisitions. The
successful acquisition of producing properties requires an assessment of several
factors, including:
| |
· |
future
oil and gas prices; |
| |
· |
title
to properties; and |
| |
· |
potential
environmental and other liabilities. |
The
accuracy of these assessments is inherently uncertain. In connection with these
assessments, the Company performs a review of the subject properties that it
believes to be generally consistent with industry practices. A review will not
necessarily reveal all existing or potential problems nor will it permit the
Company to become sufficiently familiar with the properties to fully assess
their deficiencies and capabilities. Inspections may not always be performed on
every well, and structural and environmental problems are not necessarily
observable even when an inspection is undertaken. Even when problems are
identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of the problems. The Company often is
not entitled to contractual indemnification for certain liabilities and acquires
properties on an “as is” basis.
Competitive
industry conditions may negatively affect our ability to conduct
operations.
Competition in the oil and gas industry is intense, particularly with respect to
the acquisition of producing properties and proved undeveloped acreage. Major
and independent oil and gas companies actively bid for desirable oil and gas
properties, as well as for the equipment and labor required to operate and
develop their properties. Many of the Company's competitors have financial
resources that are substantially greater, which may adversely affect the
Company's ability to compete with these companies.
Drilling
is a high-risk activity. The
Company's future success will partly depend on the success of its drilling
program. In addition to the numerous operating risks described in more detail
below, these activities involve the risk that no commercially productive oil or
gas reservoirs will be discovered. In addition, the Company is 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. |
The
oil and gas business involves many operating risks that can cause substantial
losses; insurance may not protect the Company 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, the Company 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 the
Company experiences any of these problems, its ability to conduct operations
could be adversely affected.
The
Company maintains insurance against some, but not all, of these potential risks
and losses. The Company may elect not to obtain insurance if it believes that
the cost of available insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not fully insurable.
If a significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect the Company.
The
Company is subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or feasibility of doing
business. The
Company's development, exploration, production and marketing operations are
regulated extensively at the federal, state and local levels. In addition, a
portion of the Company's leases in the Uinta Basin are, and some of the
Company's future leases may be, regulated by Native American tribes.
Environmental and other governmental laws and regulations have increased the
costs to plan, design, drill, install, operate and abandon oil and natural gas
wells. Under these laws and regulations, the Company could also be liable for
personal injuries, property damage and other damages. Failure to comply with
these laws and regulations may result in the suspension or termination of the
Company's operations and subject it to administrative, civil and criminal
penalties. Moreover, public interest in environmental protection has increased
in recent years, and environmental organizations have opposed, with some
success, certain drilling projects.
Part of
the regulatory environment in which the Company operates includes, in some
cases, federal requirements for obtaining environmental assessments,
environmental impact studies and/or plans of development before commencing
exploration and production activities. In addition, the Company's activities are
subject to the regulation by oil and natural gas-producing states and Native
American tribes of conservation practices and protection of correlative rights.
These regulations affect the Company's operations and limit the quantity of oil
and natural gas the Company may produce and sell. A major risk inherent in the
Company's drilling plans is the need to obtain drilling permits from state,
local and Native American tribal authorities. Delays in obtaining regulatory
approvals, drilling permits, the failure to obtain a drilling permit for a well
or the receipt of a permit with unreasonable conditions or costs could have a
material adverse effect on the Company's ability to explore on or develop its
properties. Additionally, the oil and natural gas regulatory environment could
change in ways that might substantially increase the financial and managerial
costs to comply with the requirements of these laws and regulations and,
consequently, adversely affect the Company's profitability.
Other
independent oil and gas companies’ limited access to capital may change the
Company's development and exploration plans. Many
independent oil and gas companies have limited access to the capital necessary
to finance their activities. As a result, some of the other working interest
owners of the Company's wells may be unwilling or unable to pay their share of
the costs of projects as they become due. These problems could cause the Company
to change, suspend or terminate drilling and development plans with respect to
the affected project.
Commonly
Used Oil and Gas Terms
Below are
explanations of some commonly used terms in the oil and gas business.
API
gravity - The
industry standard method of expressing specific gravity of crude oils. Higher
API gravities mean lower specific gravity and lighter oils.
Basis
risk - The risk
associated with the sales point price for oil or gas production varying from the
reference (or settlement) price for a particular hedging transaction.
Bbl
- One
stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or condensate.
Bcf
- Billion
cubic feet.
Bcfe
- Billion
cubic feet equivalent, determined using the ratio of six Mcf gas to one Bbl of
crude oil or condensate.
BOE
- Barrel of
Oil equivalent.
BSPD
- Barrels
of steam per day.
Btu
- British
thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 to 59.5 degrees Fahrenheit.
California
Public Utilities Commission (CPUC) - A
California government agency which regulates privately owned electric,
telecommunications, natural gas, water and transportation
companies.
Cash-flow
hedge - Derivative
instruments used to mitigate the risk of variability in cash flows from crude
oil and natural gas sales due to changes in market prices. These derivative
instruments either fix the price a party receives for its production or, in the
case of option contracts, set a minimum price or a price within a fixed
range.
Cogeneration
- The
simultaneous production of steam and electricity using a single fuel source
(natural gas).
Completion
- The
installation of permanent equipment for the production of oil or natural gas, or
in the case of a dry hole, the reporting of abandonment to the appropriate
agency.
DD&A
- Depreciation,
Depletion and Amortization
Developed
acreage - The
number of acres that are allocated or assignable to producing wells or wells
capable of production.
Development
well - A well
drilled within the proved area of an oil or natural gas field to the depth of a
stratigraphic horizon known to be productive, including a well drilled to find
and produce probable reserves.
Dry
hole or well - A well
found to be incapable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production expenses and
taxes.
Enhanced
Oil Recovery (EOR) - Efforts to
improve the flow of oil from a reservoir that has already been produced by
conventional means.
Exploitation
- Drilling
wells in areas proven to be productive.
Exploration
or exploratory well - A well
drilled to find and produce oil or natural gas reserves that is not a
development well.
Farm-out
- A
transfer of all or part of the operating rights from the working interest owner
to an asignee, who assumes all or some of the burden of development, in return
for an interest in the property.
Federal
Energy Regulatory Commission (FERC) - A
government agency which regulates the transmission of oil and natural gas by
pipeline and wholesale sales of electricity in interstate commerce.
Field. An area
consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature or stratigraphic
condition.
Gross
acres or gross wells - The total
acres or wells in which a working interest is owned.
Heavy
oil - Oil with
an API gravity below 20 degrees.
Henry
Hub (HH) - The
standard delivery point for natural gas traded on the New York Mercantile
Exchange (Sabine Pipe Line Company's Henry Hub in Louisiana).
Infill
drilling - Drilling
wells between established producing wells on a lease; a drilling program to
reduce the spacing between wells in order to increase production and/or recovery
of in-place hydrocarbons from the lease.
Kilowatt
(KW) - 1,000
watts, which are the standard measure of electrical power
MBbls
- One
thousand barrels of crude oil or other liquid hydrocarbons.
Mcf
- One
thousand cubic feet.
Mcfe
- One
thousand cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of crude oil or condensate.
Megawatt
(MW) - One
million watts.
MMS
- The
Minerals Management Service of the United States Department of the Interior.
MMBbls
- One
million barrels of crude oil or other liquid hydrocarbons.
MMcf
- One
million cubic feet.
MMcfe
- One
million cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of crude oil or condensate.
Net
acres or net wells - The sum
of the fractional working interests owned in gross acres or gross wells, as the
case may be.
NYMEX
- The
New York Mercantile Exchange.
Productive
well - A well
that is found to be capable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of such production exceed production expenses
and taxes.
Proved
developed producing reserves - Proved
developed reserves that are expected to be recovered from completion intervals
currently open in existing wells and capable of production to market.
Proved
developed reserves - Proved
reserves that can be expected to be recovered from existing wells with existing
equipment and operating methods.
Proved
developed nonproducing reserves - Proved
developed reserves expected to be recovered from zones behind casing in existing
wells.
Proved
reserves - The
estimated quantities of crude oil or natural gas that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
Proved
undeveloped reserves - Proved
reserves that are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion.
Public
Utility Regulatory Policies Act of 1978 (PURPA) - Federal
regulation which provides incentives for the development of cogeneration
facilities such as those owned by the Company.
Qualifying
Facilities (QF) - A
cogeneration facility which produces not only electricity, but also useful
thermal energy for use in an industrial or commercial process for heating or
cooling applications in certain proportions to the facility’s total energy
output, and which meets certain energy efficiency standards.
Short
Run Avoided Cost (SRAC) - An
energy payment that reflects the utility’s avoided short-term variable cost to
produce electricity.
Undeveloped
acreage - Lease
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and natural gas regardless
of whether such acreage contains proved reserves.
West
Texas Intermediate (WTI) - The
benchmark United States crude oil with an API gravity of approximately 40
degrees.
Working
interest - The
operating interest that gives the owner the right to drill, produce and conduct
operating activities on the property and a share of production.
Workover
-
Operations on a producing well to restore or increase production.
Price
Risk Management. From time
to time, the Company enters into crude oil and natural gas hedge contracts, the
terms of which depend on various factors, including Management’s view of future
crude oil and natural gas prices and the Company’s future financial commitments.
This
price hedging program is designed to moderate the effects of a severe crude oil
price downturn and protect certain operating margins in the Company's California
operations.
Currently, the hedges are in the form of swaps, however, the Company may use a
variety of hedge instruments in the future. The
Company generally attempts to hedge between 25% and 50% of its anticipated crude
oil production and up to 30% of its anticipated net natural gas purchased each
year. Management
regularly monitors the crude oil and natural gas markets and the Company’s
financial commitments to determine if, when, and at what level some form of
crude oil and/or natural gas hedging or other price protection is
appropriate. All of
these hedges have historically been deemed to be cash flow hedges with the
mark-to-market valuations provided by external sources, based on prices that are
actually quoted.
As of
December 31, 2004, the Company had hedge positions for 2005 of approximately 7,750
barrels per day of crude oil production at an average WTI price of approximately
$40.75 and 7,500 MMBtu per day of natural gas consumption at an average SoCal price
of approximately $5.25. At December 31, 2004 the Company had hedge
positions for 2006 of 5,000 MMBtu per day through June 2006 at an average
SoCal price of $4.85 and 1,000 MMBtu per day of natural gas production at a CIG
price of $6.21. In 2004, the average differential
between SoCal and Henry Hub (HH) was approximately $.60 per MMBtu and the
differential between CIG and HH was approximately $1.00 per MMBtu. Based
on NYMEX futures prices at December 31, 2004, (WTI $42.66; HH $6.32)
the Company would expect future cash payments or receipts, over
the remaining term of its existing crude oil and natural gas hedges, on a
pre-tax basis, as
follows:
| |
|
|
|
Impact
of percent change in futures prices |
|
|
|
|
12/31/04 |
|
on
earnings (in thousands) |
|
|
|
|
NYMEX
Futures |
|
-30% |
|
-15% |
|
+
15% |
|
+
30% |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI Price |
|
$ |
42.66 |
|
$ |
29.86 |
|
$ |
36.26 |
|
$ |
49.05 |
|
$ |
55.45 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) |
|
|
(5,098 |
) |
|
31,102
|
|
|
13,002
|
|
|
(23,199 |
) |
|
(41,299 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
HH Price |
|
|
6.32
|
|
|
4.43
|
|
|
5.38
|
|
|
7.27
|
|
|
8.22
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas gain/(loss) |
|
|
2,625
|
|
|
(3,216 |
) |
|
(295 |
) |
|
5,545
|
|
|
8,466
|
|
The
Company sells 100% of its electricity production, net of electricity used in its
oil and gas operations, under SO contracts to major utilities. Three of the four
SO contracts representing approximately 77% of the Company’s electricity for
sale expired in one-year contracts on December 31, 2003. However, as ordered by
CPUC, the utilities offered and the Company accepted one-year extensions on
these contracts in January 2004 and as order by the CPUC in late 2004, has
entered into new five-year contracts with the utilities. However, the sales
price under these contracts are subject to regulatory review and the pricing
methodology may not be linked to natural gas prices in the future. The Company
sells the remaining 20 MWh to a utility at $53.70 per MWh plus capacity through
a long-term sales contract that expires in June 2006.
Credit
Risk. The
Company attempts to minimize credit exposure to counterparties through
monitoring procedures and diversification. The Company’s exposure to changes in
interest rates results primarily from long-term debt. Total debt outstanding at
December 31, 2004 and 2003 was $28 million and $50 million, respectively.
Interest on amounts borrowed is charged at LIBOR plus 1.25% to 2.0%. Based on
year-end 2004 borrowings, a 1% change in interest rates would not have a
material impact on the Company’s financial statements.
Commodity
Price Risk. During
2004, WTI prices per barrel reached a high of $55.17, a low of $32.48 and
averaged $41.47 for the year compared to an average of $30.99 and $26.15 in 2003
and 2002, respectively. The price of crude oil is influenced by many factors
both regionally and globally. Additionally, approximately 83% of the Company's
current production is California heavy crude oil. California heavy crude oil has sold at a discount of approximately $6.00 to WTI
over the past ten years. The basis risk
between WTI and the Company's California heavy crude oil is mitigated by the
Company's crude oil sales contract under which the Company sells over 90% of its
California production. Pricing in the existing agreement is based upon the
higher of the average of the local field posted prices plus a fixed premium, or
WTI minus a fixed differential approximating $6.00 per barrel. This contract
expires on December 31, 2005.
During
2004 and through early 2005, the differential between California heavy crude oil
and WTI widened to over $14.00 per barrel and averaged $8.57 in 2004. While the
Company is confident that it will be able to secure a contract for its
California heavy crude oil in future periods, it is unlikely that the Company
will be able to obtain terms similar to the current contract. In 2004, the
Company estimates that its revenues benefited from this contract by
approximately $13 million, and at a current differential of approximately $14.00
per barrel, the Company estimates that its revenues in 2005 will benefit from
the contract by approximately $45 million.
Forward
Looking Statements
"Safe
harbor under the Private Securities Litigation Reform Act of 1995:” With the
exception of historical information, the matters discussed in this news release
are forward-looking statements that involve risks and uncertainties. Although
the Company believes that its expectations are based on reasonable assumptions,
it can give no assurance that its goals will be achieved. Important factors that
could cause actual results to differ materially from those in the
forward-looking statements herein include, but are not limited to: the timing
and extent of changes in commodity prices for oil, gas and electricity;
development, exploration, drilling and operating risks; a limited marketplace
for electricity sales within California, counterparty risk; acquisition risks;
competition, environmental risks, litigation uncertainties; the availability of
drilling rigs and other support services, legislative and/or judicial decisions
and other government or Tribal regulations.
BERRY
PETROLEUM COMPANY
Index
to Financial Statements and
Supplementary
Data
| |
Page |
| |
|
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting
Firm |
41 |
| |
|
|
Balance
Sheets at December 31, 2004 and 2003 |
42 |
| |
|
|
Statements
of Income for the Years Ended December 31, 2004, 2003 and 2002
|
43 |
| |
|
|
Statements
of Comprehensive Income for the Years Ended December 31, 2004, 2003 and
2002 |
43 |
| |
|
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2004, 2003 and
2002 |
44 |
| |
|
|
Statements
of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
|
45 |
| |
|
|
Notes
to the Financial Statements |
46 |
| |
|
|
Supplemental
Information About Oil & Gas Producing Activities
(unaudited) |
64 |
Financial
statement schedules have been omitted since they are either not required,
are not
applicable, or the required information is shown in the financial statements and
related
notes.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders
of Berry
Petroleum Company:
We have
completed an integrated audit of Berry Petroleum Company’s 2004 financial
statements and of its internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002 financial statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are presented below.
Financial
statements
In our
opinion, the accompanying balance sheets and the related statements of income,
comprehensive income, cash flows and shareholders’ equity present fairly, in all
material respects, the financial position of Berry Petroleum Company at
December 31, 2004 and 2003, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2004 in
conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
As
discussed in Note 2 to the financial statements, effective January 1, 2004, the
Company changed its method of accounting for stock-based compensation to conform
to Statement of Financial Accounting Standards No. 123, “Accounting for
Stock-Based Compensation.”
Internal
control over financial reporting
Also, in
our opinion, management’s assessment, included in "Management’s Report on
Internal Control Over Financial Reporting" appearing under Item 9A, that
the Company maintained effective internal control over financial reporting as of
December 31, 2004 based on criteria established in Internal
Control — Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal
Control — Integrated Framework issued by
the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness of
the Company’s internal control over financial reporting based on our audit. We
conducted our audit of internal control over financial reporting in accordance
with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects. An audit of internal control
over financial reporting includes obtaining an understanding of internal control
over financial reporting, evaluating management’s assessment, testing and
evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers LLP
Los
Angeles, California
March 30,
2005
BERRY
PETROLEUM COMPANY
Balance
Sheets
December
31, 2004 and 2003
(In
Thousands, Except Share Information)
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
Current
assets: |
|
|
|
|
|
|
Cash
and cash equivalents |
|
$ |
16,690 |
|
$ |
10,658 |
|
|
Short-term
investments available for sale |
|
|
659
|
|
|
663
|
|
|
Accounts
receivable |
|
|
34,621
|
|
|
23,506
|
|
|
Deferred
income taxes |
|
|
3,558
|
|
|
6,410
|
|
|
Fair
value of derivatives |
|
|
3,243
|
|
|
-
|
|
|
Prepaid
expenses and other |
|
|
2,230
|
|
|
2,049
|
|
|
Total
current assets |
|
|
61,001
|
|
|
43,286
|
|
| |
|
|
|
|
|
|
|
Oil
and gas properties (successful efforts basis), buildings
and equipment, net |
|
|
338,706
|
|
|
295,151
|
|
|
Deposits
on potential property acquisitions |
|
|
10,221
|
|
|
-
|
|
|
Other
assets |
|
|
2,176
|
|
|
1,940
|
|
| |
|
|
|
|
|
|
|
| |
|
$ |
412,104 |
|
$ |
340,377 |
|
| |
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts
payable |
|
$ |
27,750 |
|
$ |
20,867 |
|
|
Revenue
and royalties payable |
|
|
23,945
|
|
|
11,623
|
|
|
Accrued
liabilities |
|
|
6,132
|
|
|
4,214
|
|
|
Income
taxes payable |
|
|
1,067
|
|
|
4,412
|
|
|
Fair
value of derivatives |
|
|
5,947
|
|
|
5,710
|
|
|
Total
current liabilities |
|
|
64,841
|
|
|
46,826
|
|
| |
|
|
|
|
|
|
|
|
Long-term
liabilities: |
|
|
|
|
|
|
|
|
Deferred
income taxes |
|
|
47,963
|
|
|
38,559
|
|
|
Long-term
debt |
|
|
28,000
|
|
|
50,000
|
|
|
Abandonment
obligation |
|
|
8,214
|
|
|
7,311
|
|
|
Fair
value of derivatives |
|
|
-
|
|
|
343
|
|
|
|
|
|
84,177
|
|
|
96,213
|
|
|
Commitments
and contingencies (Notes 10 and 11) |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Shareholders'
equity: |
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no
shares outstanding |
|
|
-
|
|
|
-
|
|
|
Capital
stock, $.01 par value: |
|
|
|
|
|
|
|
|
Class
A Common Stock, 50,000,000 shares authorized; 21,060,420
shares issued and outstanding (20,904,372 in 2003) |
|
|
210
|
|
|
209
|
|
Class
B Stock, 1,500,000 shares authorized; 898,892
shares issued and outstanding (liquidation preference of
$899) |
|
|
9
|
|
|
9
|
|
|
Capital
in excess of par value |
|
|
60,676
|
|
|
56,475
|
|
|
Deferred
stock-based compensation |
|
|
-
|
|
|
(1,108 |
) |
|
Accumulated
other comprehensive loss |
|
|
(987 |
) |
|
(3,632 |
) |
|
Retained
earnings |
|
|
203,178
|
|
|
145,385
|
|
|
Total
shareholders' equity |
|
|
263,086
|
|
|
197,338
|
|
| |
|
|
|
|
|
|
|
| |
|
$ |
412,104 |
|
$ |
340,377 |
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Statements
of Income
Years
ended December 31, 2004, 2003 and 2002
(In
Thousands, Except Per Share Data)
| |
|
2004 |
|
2003 |
|
2002 |
|
|
Revenues: |
|
|
|
|
|
|
|
|
Sales
of oil and gas |
|
$ |
226,876 |
|
$ |
135,848 |
|
$ |
102,026 |
|
|
Sales
of electricity |
|
|
47,644
|
|
|
44,200
|
|
|
27,691
|
|
|
Interest
and dividend income |
|
|
261
|
|
|
236
|
|
|
536
|
|
|
Other
income |
|
|
165
|
|
|
580
|
|
|
1,116
|
|
|
|
|
|
274,946
|
|
|
180,864
|
|
|
131,369
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
Operating
costs – oil and gas production |
|
|
82,419
|
|
|
62,554
|
|
|
45,217
|
|
|
Operating
costs – electricity generation |
|
|
46,191
|
|
|
42,351
|
|
|
26,747
|
|
|
Depreciation,
depletion & amortization - oil and gas |
|
|
29,752
|
|
|
17,258
|
|
|
13,388
|
|
|
Depreciation,
depletion & amortization - electricity generation |
|
|
3,490
|
|
|
3,256
|
|
|
3,064
|
|
|
General
and administrative |
|
|
20,354
|
|
|
12,868
|
|
|
9,215
|
|
|
Interest |
|
|
2,067
|
|
|
1,414
|
|
|
1,042
|
|
|
Loss
on disposal of assets |
|
|
410
|
|
|
-
|
|
|
-
|
|
|
Dry
hole, abandonment and impairment |
|
|
745
|
|
|
4,195
|
|
|
-
|
|
|
Recovery
of electricity receivable |
|
|
-
|
|
|
-
|
|
|
(3,631 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
185,428
|
|
|
143,896
|
|
|
95,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes |
|
|
89,518
|
|
|
36,968
|
|
|
36,327
|
|
|
Provision
for income taxes |
|
|
20,331
|
|
|
4,605
|
|
|
7,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income |
|
$ |
69,187 |
|
$ |
32,363 |
|
$ |
29,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share |
|
$ |
3.16 |
|
$ |
1.49 |
|
$ |
1.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share |
|
$ |
3.08 |
|
$ |
1.47 |
|
$ |
1.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share) |
|
|
21,894
|
|
|
21,772
|
|
|
21,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
Stock
options |
|
|
523
|
|
|
215
|
|
|
115
|
|
|
Other |
|
|
53
|
|
|
44
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share |
|
|
22,470
|
|
|
22,031
|
|
|
21,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statements
of Comprehensive Income |
|
|
Years
Ended December 31, 2004, 2003 and 2002 |
|
(In
Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income |
|
$ |
69,187 |
|
$ |
32,363 |
|
$ |
29,210 |
|
Unrealized
gains (losses) on derivatives, net of income taxes
of ($521), ($709), and ($1,712) |
|
|
(781 |
) |
|
(3,632 |
) |
|
(2,569 |
) |
|
Reclassification
of unrealized losses included in net income net
of income taxes of $2,284, $1,712 and $0 |
|
|
3,426
|
|
|
2,569
|
|
|
-
|
|
|
Comprehensive
income |
|
$ |
71,832 |
|
$ |
31,300 |
|
$ |
26,641 |
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Statements
of Shareholders’ Equity
Years
Ended December 31, 2004, 2003 and 2002
(In
Thousands, Except Per Share Data)
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Class
A |
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Class
B |
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Par
Value |
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Compensation |
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Earnings |
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Comprehensive Income
(Loss) |
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Equity |
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