UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x
Annual
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
fiscal year ended
December 31, 2006
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
Securities
registered pursuant to Section 12(b) of the Act:
|
|
Title
of each class
|
|
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 if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
YES
x
NO
o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
YES
o
NO
x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. YES
x
NO
o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this
Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filerx Accelerated
filero
Non-accelerated filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES
o
NO
x
As
of
June 30, 2006, the aggregate market value of the voting and non-voting common
stock held by non-affiliates was $1,202,477,929. As of February 9, 2007, the
registrant had 42,120,651 shares of Class A Common Stock outstanding. The
registrant also had 1,797,784 shares of Class B Stock outstanding on February
9,
2007 all of which are held by an affiliate of the registrant.
DOCUMENTS
INCORPORATED BY REFERENCE
Part
III
is incorporated by reference from the registrant's definitive Proxy Statement
for its Annual Meeting of Shareholders to be filed, pursuant to Regulation
14A,
no later than 120 days after the close of the registrant's fiscal
year.
BERRY
PETROLEUM COMPANY
TABLE
OF CONTENTS
PART
I
|
|
|
Page
|
|
Item
1.
|
Business
|
3 |
|
|
General
|
3 |
|
|
Crude
Oil and Natural Gas Marketing
|
5 |
|
|
Steaming
Operations
|
7 |
|
|
Electricity
|
8 |
|
|
Competition
|
10 |
|
|
Employees
|
10 |
|
|
Capital
Expenditures Summary
|
11 |
|
|
Production
|
12 |
|
|
Acreage
and Wells
|
12 |
|
|
Drilling
Activity
|
13 |
|
|
Environmental
and Other Regulations
|
13 |
|
Forward
Looking Statements
|
14 | |
|
Item
1A.
|
Risk
Factors
|
15 |
|
Item
1B.
|
Unresolved
Staff Comments
|
21 |
|
Item
2.
|
Properties
|
21 |
|
Item
3.
|
Legal
Proceedings
|
21 |
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
21 |
|
|
Executive
Officers
|
21 |
|
|
|
PART
II
|
|
|
|
|
Item
5.
|
Market
for the Registrant's Common Equity and Related Shareholder Matters
and
Issuer Purchases of Equity Securities
|
22 |
|
Item
6.
|
Selected
Financial Data
|
25 |
|
Item
7.
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operation
|
27 |
|
Item
7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
44 |
|
Item
8.
|
Financial
Statements and Supplementary Data
|
47 |
|
Item
9.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
74 |
|
Item
9A.
|
Controls
and Procedures
|
74 |
|
Item
9B.
|
Other
Information
|
75 |
|
|
|
|
PART
III
|
|
|
|
|
Item
10.
|
Directors
and Executive Officers and Corporate Governance
|
75 |
|
Item
11.
|
Executive
Compensation
|
75 |
|
Item
12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
76 |
|
Item
13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
76 |
|
Item
14.
|
Principal
Accounting Fees and Services
|
76 |
|
|
|
|
PART
IV
|
|
|
|
|
Item
15.
|
Exhibits,
Financial Statement Schedules
|
76 |
2
PART
I
Item
1. Business
General. We
are an
independent energy company engaged in the production, development, acquisition,
exploitation of and exploration for, crude oil and natural gas. While we were
incorporated in Delaware in 1985 and have been a publicly traded company since
1987, we can trace our roots in California oil production back to 1909. In
2003,
we purchased and began operating properties in the Rocky Mountain/Mid-Continent
region. Our corporate headquarters are in Bakersfield, California and we have
a
regional office in Denver, Colorado. Information contained in this report on
Form 10-K reflects our business during the year ended December 31, 2006 unless
noted otherwise.
Our
website is located at http://www.bry.com.
The
website can be used to access recent news releases and Securities and Exchange
Commission (SEC) filings, crude oil price postings, our Annual Report, Proxy
Statement, Board committee charters, code of business conduct and ethics, the
code of ethics for senior financial officers, and other items of interest.
SEC
filings, including supplemental schedules and exhibits, can also be accessed
free of charge through the SEC website at http://www.sec.gov.
Corporate
strategy. Our
objective is to increase shareholder value through consistent growth in our
production and reserves, both through the drill bit and acquisitions. We strive
to operate our properties in an efficient manner to maximize the cash flow
and
earnings of our assets. The strategies to accomplish these goals
include:
| · |
Developing
our existing resource base.
We
intend to increase both production and reserves annually. We are
focused
on the timely and prudent development of our large resource base
through
developmental and step-out drilling, down-spacing, well completions,
remedial work and by application of enhanced oil recovery (EOR) methods
and optimization technologies, as applicable. In 2006, we invested
in a
large undeveloped probable reserve position in the Piceance basin
in
Colorado, and are planning for significant drilling there over the
next
several years. We also have large hydrocarbon resources in place
in the
San Joaquin Valley basin, California (diatomite) and an emerging
resource
play in the Uinta basin, Utah (Lake Canyon). We have a proven track
record
of developing reserves and increasing production in all of our operating
regions.
|
| · |
Acquiring
additional assets with significant growth
potential.
We
will continue to evaluate oil and gas properties with proved reserves,
probable reserves and/or sizeable acreage positions that we believe
contain substantial hydrocarbons which can be developed at reasonable
costs. We have identified the Rocky Mountain/Mid-Continent region
as our
primary area of interest for growth. Significant recent acquisitions
in
the region include: $105 million acquisition in 2005 of mostly proved
reserves in the Niobrara gas play in the Denver-Julesburg (DJ) basin
and
two transactions in 2006 pursuant to which we have committed over
$312 million to acquire or earn natural gas acreage in the Piceance
basin. We will continue to review asset acquisitions that meet our
economic criteria with a primary focus on large repeatable development
potential in these regions. Additionally, we seek to increase our
net
revenue interest in assets that we already operate. In California,
we
continue to evaluate available properties for acquisition to take
advantage of our extensive operational and technical expertise in
the
development and production of heavy
oil.
|
| · |
Utilizing
joint ventures with respected partners to enter new
basins.
We
believe that early entry into some basins offers the best potential
for
establishing low cost acreage positions in those basins. In areas
where we
do not have existing operations, we seek to utilize the skills and
knowledge of other industry participants upon entering these new
basins so
that we can reduce our risk and improve our ultimate success in the
area.
|
| · |
Accumulating
significant acreage positions near our producing
operations.
We
have been successful in adding strategic acreage positions in less
than
three years with the intent of appraising the potential of the acreage
for
the economic production of hydrocarbons. As of December 31, 2006
these
positions include 483,000 and 145,400 gross acres in the DJ and Uinta
basins, respectively, which are adjacent to, or in the proximity
of, our
producing assets within those basins. This strategy allows us to
leverage
our operating and technical expertise within the area and build on
established core operations. We are appraising these acreage blocks
by
shooting and utilizing 3-D seismic data, participating in drilling
programs in areas of mutual interest with partners and utilizing
current
geological, geophysical and drilling technologies. We also intend
to
pursue acreage in large resource plays that may result in repeatable-type
development.
|
| · |
Investing
our capital in a disciplined manner and maintaining a strong financial
position.
The oil and gas business is capital intensive. Therefore we will
focus on
utilizing our available capital on projects where we are likely to
have
success in increasing production and/or reserves at attractive returns.
We
believe that maintaining a strong financial position will allow us
to
capitalize on investment opportunities and be better prepared for
a lower
commodity price environment. We expect to continue to hedge oil and
gas
prices and to utilize long-term sales contracts with the objective
of
achieving the cash flow necessary for the development of our
assets.
|
3
Business
strengths.
| · |
Balanced
high quality asset portfolio with a long reserve life.
Since
2002, we have grown and diversified our California heavy oil asset
base
through acquisitions in three core areas in the Rocky
Mountain/Mid-Continent region that have significant growth potential.
Our
base of legacy California assets provides us with a steady stream
of cash
flow to re-invest into our significant drilling inventory and the
appraisal of our prospects. Our wells are generally characterized
by long
production lives and predictable performance. At December 31, 2006
our implied reserve life was 15.3 years and our implied proved
developed reserve life was
10.4 years.
|
| · |
Track
record of efficient proved reserve and production
growth.
For the three years ended December 31, 2006, our average annual
reserve replacement rate was 260% at an average cost of $12.74 per
barrel
of oil equivalent (BOE). See Item 7 Management’s Discussion and Analysis
of Financial Condition and Results of Operation for further explanation
of
the reserve replacement rate. During the same period our proved reserves
and production increased at an annualized compounded rate of 11.2%
and
15.7%, respectively. We were able to deliver that growth predominantly
through low-risk drilling. We have achieved an average drilling success
rate of 98%. We believe we can continue to deliver strong growth
through
the drill bit by exploiting our large undeveloped leasehold position.
We
also plan to complement this drill bit growth through selective and
focused acquisitions.
|
| · |
Experienced
management and operational teams.
We
have significantly expanded and deepened our core team of technical
staff
and operating managers, who have broad industry experience, including
experience in California heavy oil thermal recovery operations and
Rocky
Mountain tight gas sands development and completion. We continue
to
utilize technologies and steam practices that we believe will allow
us to
improve the ultimate recoveries of crude oil on our mature California
properties. We also utilize 3-D seismic technology for evaluation
of
sub-surface geologic trends of our many prospects.
|
| · |
Operational
control and financial flexibility.
We
exercise operating control over approximately 99% of our proved reserve
base. We generally prefer to retain operating control over our properties,
allowing us to control operating costs more effectively, the timing
of
development activities and technological enhancements, the marketing
of
production and the allocation of our capital budget. In addition,
the
timing of most of our capital expenditures is discretionary which
allows
us a significant degree of flexibility to adjust the size and timing
of
our capital budget. We finance our drilling budget primarily through
our
internally generated operating cash flows and we also have a
$750 million senior unsecured revolving credit facility with a
current borrowing base of
$500 million.
|
| · |
Established
risk management policies.
We
actively manage our exposure to commodity price fluctuations by hedging
a
material portion of our forecasted production. We use hedges to help
us
mitigate the effects of price declines and to secure operating cash
flows
in order to fund our capital expenditures program. Our long-term
crude oil
contracts with refiners and our long-term firm natural gas pipeline
transportation agreements help us mitigate price differential volatility
and assure product delivery to markets. The operation of our cogeneration
facilities provides a partial hedge against increases in natural
gas
prices because of the high correlation between electricity and natural
gas
prices under our electricity sale
contracts.
|
Proved
Reserves and Revenues. As
of
December 31, 2006, our estimated proved reserves were 150.3 million BOE, of
which 66% are heavy crude oil, 9% light crude oil and 25% natural gas. We have
a
geographically diverse asset base with 66% of our reserves located in
California, and 34% in the Rocky Mountain/Mid-Continent region. Of our proved
reserves 68% were proved developed. Proved undeveloped reserves make up 32%
of
our proved total. The projected capital to develop these proved undeveloped
reserves is $382 million, at an estimated cost of approximately $7.96 per BOE.
Approximately 78% of the capital to develop these reserves is expected to be
expended in the next five years. Production in 2006 was 9.3 million BOE, up
11%
from production of 8.4 million BOE in 2005.
Our
properties generally have long reserve lives and reasonably stable and
predictable well production characteristics with a ratio of proved reserves
to
production (based on the year ended December 31, 2006) of approximately
15.3 years as compared to 14.6 years at year-end 2005.
4
We
have
six asset teams, three in California and three in the Rocky
Mountain/Mid-Continent region. California’s three teams are South Midway-Sunset
(SMWSS), North Midway-Sunset (NMWSS) (which includes diatomite) and Southern
California (Socal) (which includes Poso Creek, Ethel D, Placerita and Montalvo).
The three Rocky Mountain/Mid-Continent region teams are DJ, Uinta and Piceance.
The following table sets forth the estimated quantities of proved reserves
and
production attributable to our asset teams as of December 31, 2006. We operate
99% of these assets:
|
State
|
Name
|
Type
|
Average
Daily Production (BOE/D)
|
%
of Daily Production
|
Proved
Reserves (BOE) in thousands
|
%
of Proved Reserves
|
Oil
& Gas Revenues before hedging (in millions)
|
%
of Oil & Gas Revenues
|
|||||||||||
|
CA
|
SMWSS
|
Heavy
oil
|
10,101
|
39.8%
|
50,124
|
33.4%
|
$179.3 |
40.2%
|
|||||||||||
|
UT
|
Uinta
|
Light
oil/Natural gas
|
5,949
|
23.4
|
21,093
|
14.0
|
101.1
|
22.7
|
|||||||||||
|
CA
|
Socal
|
Heavy
oil
|
4,824
|
19.0
|
33,441
|
22.2
|
100.8
|
22.6
|
|||||||||||
|
CO
|
DJ
|
Natural
gas
|
2,676
|
10.5
|
18,620
|
12.4
|
34.0
|
7.6
|
|||||||||||
|
CA
|
NMWSS
|
Heavy
oil
|
1,125
|
4.4
|
16,343
|
10.9
|
23.8
|
5.3
|
|||||||||||
|
CO
|
Piceance
|
Natural
gas
|
723
|
2.9
|
10,641
|
7.1
|
7.3
|
1.6
|
|||||||||||
|
Totals
|
25,398
|
100%
|
150,262
|
100%
|
$446.3
|
100%
|
We
continue to engage DeGolyer and MacNaughton (D&M) to appraise the extent and
value of our proved oil and gas reserves and the future net revenues to be
derived from our properties for the year ended December 31, 2006. D&M is an
independent oil and gas consulting firm located in Dallas, Texas. In preparing
their reports, D&M reviewed and examined geologic, economic, engineering and
other data considered applicable to properly determine our reserves. They also
examined the reasonableness of certain economic assumptions regarding forecasted
operating and development costs and recovery rates in light of the economic
environment on December 31, 2006. See Supplemental Information About Oil &
Gas Producing Activities (Unaudited) for our oil and gas reserve
disclosures.
Acquisitions.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operation.
Operations.
In
California, we operate all of our principal oil and gas producing properties.
The Midway-Sunset and
Socal
assets contain predominantly heavy crude oil which requires heat (except
Montalvo, which averages production from below 11,500 feet deep), supplied
in
the form of steam, which is injected into the oil producing formations to reduce
the oil viscosity, thereby allowing the oil to flow to the wellbore for
production. We utilize cyclic steam and/or steam flood recovery methods on
all
assets in addition to primary recovery methods at our Montalvo field. Field
operations related to oil production include the initial recovery of the crude
oil and its transport through treating facilities into storage tanks. After
the
treating process is completed, which includes removal of water and solids by
mechanical, thermal and chemical processes, the crude oil is metered through
automatic custody transfer units or gauged before sale and subsequently
transferred into crude oil pipelines owned by other companies or transported
via
truck.
In
the
Rocky Mountain/Mid-Continent region, crude oil produced from the Uinta assets
is
transported by truck, while its gas production, net of field usage, is
transported by gathering or distribution systems to the Questar Pipeline.
Natural gas produced from the DJ basin gas assets is transported to one of
three
main pipelines. Our Piceance basin natural gas is gathered and sold to an
affiliate of our industry partner. We have pipeline gathering systems and gas
compression facilities for delivery into various interstate gas lines.
Crude
Oil and Natural Gas Marketing.
Economy.
The
global and California crude oil markets continue to remain strong though
volatile. Product prices continued to exhibit an overall-strengthening trend
through August 2006 and then retreated somewhat. The range of West Texas
Intermediate (WTI) crude prices for 2006, based upon NYMEX settlements, was
a
low of $55.81 and a high of $77.03. We expect that crude prices will continue
to
be volatile in 2007.
|
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Average
NYMEX settlement price for WTI
|
|
$
|
66.25
|
|
$
|
56.70
|
$
|
41.47
|
|
|
|
Average
posted price for Berry’s:
|
|
|
||||||||
|
Utah
light crude oil
|
56.34
|
|
53.03
|
|
38.60
|
|||||
|
California
13 degree API heavy crude oil
|
|
|
54.38
|
|
44.36
|
|
32.84
|
|||
|
Average
crude price differential between WTI and Berry’s:
|
||||||||||
|
Utah
light crude oil
|
|
|
9.91
|
3.67
|
2.87
|
|||||
|
California
13 degree API heavy crude oil
|
11.87
|
|
12.34
|
|
8.63
|
|||||
5
The
above
posting prices and differentials are not necessarily amounts paid or received
by
us due to the contracts discussed below. While the crude oil price differential
between WTI and California’s heavy crude differential widened dramatically
during 2004 and 2005, it was relatively stable in 2006. On December 31, 2006
the
differential was $11.69 and ranged from a low of $11.39 to a high of $12.73
per
barrel during the year. Crude oil price differentials between WTI and Utah’s
light crude oil were fairly consistent during 2004 and 2005 and were between
$3
and $5 per barrel, but differentials widened considerably in 2006. On December
31, 2006 the differential was $13.75 and ranged from a low of $5.50 to a high
of
$13.75 per barrel during the year.
Oil
Contracts. We
market
our crude oil production to competing buyers including independent and major
oil
refining companies.
California
- We have the ability to deliver significant volumes of crude oil over a
multi-year period. On November 21, 2005, we entered into a new crude oil sales
contract for our California production for deliveries beginning February 1,
2006
and ending January 31, 2010. The per barrel price, calculated on a monthly
basis
and blended across the various producing locations, is the higher of 1) the
WTI
NYMEX crude oil price less a fixed differential approximating $8.15, or 2)
heavy
oil field postings plus a premium of approximately $1.35. The initial term
of
the contract is for four years with a one-year renewal at our option. The
agreement effectively eliminates our exposure to the risk of a widening WTI
to
California heavy crude price differential over the next four years and allows
us
to effectively hedge our production based on WTI pricing similar to the previous
contract. If this contract had been in place during 2005, it would have allowed
us to improve our California revenues over the posted prices by approximately
$25 million in 2005, but $16 million below what was actually received by us
under the contract in place in 2005. This contract allowed us to improve our
California revenues by $21 million over the posted price in 2006.
Prior
to
November 2005, we secured a three-year sales agreement, beginning in late 2002,
with a major oil company whereby we sold over 90% of our California production
under a negotiated pricing mechanism. This contract ended on January 31, 2006.
Pricing in this agreement was based upon the higher of the average of the local
field posted prices plus a fixed premium, or WTI minus a fixed differential
near
$6.00 per barrel. This contract allowed us to improve our California revenues
over the posted price by approximately $41 million and $13 million in 2005
and
2004, respectively.
Utah
- As
of December 31, 2006, our Utah light crude oil is sold under multiple contracts
with different purchasers for varying pricing terms and ranging from one month
to nine months. As of December 31, 2006 we had firm contracts for 4,250 barrels
per day (Bbl/D). These contracts are currently priced at approximately $13
to
$20 per barrel below WTI with certain volumes tied to field posting, and in
some
cases our realized price is further reduced by transportation charges. As
operator we deliver all produced volumes pursuant to these contracts, although
our working interest partners or royalty owners may take their respective
volumes in kind and market their own volumes. Our net volumes from our Brundage
Canyon properties approximate 80% of the total gross volumes. Assuming all
the
Brundage Canyon wells are producing, the gross production could exceed these
contracted volumes. We experienced increasing difficulty in locating additional
buyers of our crude oil production from this region in 2006. Our Utah crude
oil
is a paraffinic crude, locally known as a black wax crude, and can be processed
efficiently by only a limited number of refineries. Increased production of
crude oil in the region, the ability of refiners to process other higher sulfur
crudes as a result of capital upgrades, as well as the increasing availability
of Canadian crude oil, is putting downward pressure on the sales price of our
crude oil.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract
with
a subsidiary of Holly Corporation (Holly) for our Uinta basin crude oil. Under
the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007.
Upon completion of their Woods Cross refinery expansion in Salt Lake City,
which
is expected in mid 2008, Holly will increase their total purchased volumes
to
5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes
transportation, is a fixed percentage of WTI and approximates our expected
field
posted price of $13 to $16 below WTI. This contract provides the pricing
assurance we need to proceed with the long-term development of our Uinta basin
assets. From October 1, 2003 through April 30, 2006 we were able to
sell our Utah crude oil at approximately $2.00 per barrel below WTI and from
May 1, 2006 through September 30, 2006, we were selling the majority
of our Utah crude at approximately $9.00 per barrel below WTI. Due to this
lower
pricing, and based on sales of 3,500 Bbl/D, our revenues were lower by
approximately $9.2 million in 2006 as compared to 2005. If this pricing
continues throughout 2007, with our Holly contract in place and on the same
volumes, we estimate our revenues will be lower by approximately
$8.6 million versus our 2006 revenues. We may adjust our capital
expenditures in the Uinta basin due to various factors, including the timing
of
refinery demand for the Uinta barrels and the actual or expected change in
our
realized price.
6
Natural
Gas Marketing. We
market
produced natural gas from Colorado, Kansas, Utah, Wyoming and
California. Generally, natural gas is sold at monthly index related prices
plus an adjustment for transportation. Certain volumes are sold at a daily
spot
related price.
|
2006
|
2005
|
2004
|
|||||||||||||||||||
| Annual average closing price per MMBtu for: | |||||||||||||||||||||
|
NYMEX
Henry Hub (HH) prompt month natural gas contract
|
$
|
6.98
|
|
$
|
9.01
|
$
|
6.18
|
||||||||||||||
|
Rocky
Mountain Questar first-of-month indices (Brundage Canyon
sales)
|
5.36
|
6.73
|
5.05
|
||||||||||||||||||
|
Rocky
Mountain CIG first-of-month indices (Tri-State and Piceance
sales)
|
5.63
|
6.95
|
5.17
|
||||||||||||||||||
|
Average
natural gas price per MMBtu differential between NYMEX HH
and:
|
|||||||||||||||||||||
|
Questar
|
1.86
|
2.28
|
1.13
|
||||||||||||||||||
|
CIG
|
1.60
|
2.06
|
1.01
|
We
have
physical access to interstate gas pipelines to move gas to or from market.
To
assure delivery of gas, we have entered into several long-term gas
transportation contracts as follows:
Firm
Transportation Summary.
|
Name
|
From
|
To
|
|
|
Quantity
(Avg. MMBtu/D)
|
|
|
Term
|
|
|
2006
base costs per MMBtu
|
|
|
Remaining
contractual obligation (in thousands)
|
|
Kern
River Pipeline
|
Opal,
WY
|
Kern
County, CA
|
|
|
12,000
|
|
|
5/2003
to 4/2013
|
|
$
|
0.643
|
|
$
|
17,826
|
|
Rockies
Express Pipeline
|
Piceance
|
Clarington,
OH
|
10,000
|
1/2008
to 12/2017
|
1.094
|
(1)
|
38,703
|
|||||||
|
Questar
Pipeline
|
Brundage
Canyon
|
Salt
Lake City, UT
|
|
|
2,500
|
|
|
9/2003
to 4/2012
|
|
|
0.174
|
|
|
846
|
|
Questar
Pipeline
|
Brundage
Canyon
|
Salt
Lake City, UT
|
|
|
2,800
|
|
|
9/2003
to 9/2007
|
|
|
0.174
|
|
|
136
|
|
KMIGT
|
Yuma
County, CO
|
Grant,
KS
|
|
|
2,500
|
|
|
1/2005
to 10/2013
|
|
|
0.227
|
|
|
1,416
|
|
Cheyenne
Plains Gas Pipeline
|
Tri-State,
CO
|
Panhandle
Eastern Pipeline
|
|
|
11,000
|
|
|
1/2007
to 12/2016
|
|
|
0.370
|
|
|
14,868
|
|
Total
|
|
|
|
|
40,800
|
|
|
|
|
|
|
|
$
|
73,795
|
(1)
We will experience lower rates from first in-service date until the pipeline
is
complete.
Royalties.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to
the
financial statements.
Concentration
of Credit Risk. See
Note
4 to the financial statements.
Steaming
Operations.
Cogeneration
Steam Supply. As
of
December 31, 2006, approximately 62% of our proved reserves, or 93 million
barrels, consisted of heavy crude oil produced from depths of less than 2,000
feet. In pursuing our goal of being a cost-efficient heavy oil producer in
California, we have consistently focused on minimizing our steam cost. We
believe one of the main methods to keep steam costs low is through the ownership
and efficient operation of three cogeneration facilities located on our
properties. Two of these cogeneration facilities, a 38 megawatt (MW) and an
18
MW facility, are located in our Midway-Sunset field. We also own a 42 MW
cogeneration facility which is located in the Placerita field. Steam generation
from these cogeneration facilities is more efficient than conventional steam
generation as both steam and electricity are concurrently produced from a common
fuel stream. By maintaining a correlation between electricity and natural gas
prices, we are better able to control the cost of producing steam.
Conventional
Steam Generation. In
addition to these cogeneration plants, we own 16 conventional boilers. The
quantity of boilers operated at any point in time is dependent on 1) the steam
volume required for us to achieve our targeted production and 2) the price
of
natural gas compared to the price of crude oil sold.
Total
barrels of steam per day (BSPD) capacity as of December 31, 2006 is as
follows:
|
Total
steam generation capacity of Cogeneration plants
|
38,000
|
|||
|
Additional
steam purchased under contract with a third party
|
2,000
|
|||
|
Total
steam generation capacity of conventional boilers
|
67,000
|
|||
|
Total
steam capacity
|
107,000
|
7
The
average volume of steam injected for the years ended December 31, 2006 and
2005
was 81,246 and 70,032 BSPD, respectively.
Ownership
of these varied steam generation facilities and sources allows for maximum
operational control over the steam supply, location, and to some extent, control
over the aggregated cost of steam generation. Our steam supply and flexibility
are crucial for the maximization of California thermally enhanced heavy oil
production, cost control and ultimate reserve recovery.
We
are
adding additional steam capacity for our development projects at Midway-Sunset,
primarily diatomite, and Poso Creek to achieve maximum production from these
properties. We regularly review our options to secure the most economical source
for obtaining additional steam.
We
operated most of our conventional steam generators in 2006 to achieve our goal
of increasing heavy oil production. Approximately 65% of the volume of natural
gas purchased to generate steam and electricity is based upon SoCal Border
indices. We pay distribution/transportation charges for the delivery of gas
to
our various locations where we consume gas for steam generation purposes,
however, in some cases this transportation cost is embedded in the price of
gas.
Approximately 26% of supply volume is purchased in Wyoming and moved to the
Midway-Sunset field using our firm transportation capacity on the Kern River
Pipeline. This gas is purchased based upon the Rocky Mountain Northwest Pipeline
(NWPL) index. The remaining 9% of supply volume for the Poso Creek steaming
operations is purchased based upon the PG&E Citygate index.
|
2006
|
2005
|
2004
|
|||||||||||||||||
| Average SoCal Border Monthly Index Price per MMBtu | $ |
6.29
|
$ |
7.37
|
$ |
5.60
|
|||||||||||||
|
Average
Rocky Mountain NWPL Monthly Index Price per MMBtu
|
5.66
|
6.96
|
5.24
|
||||||||||||||||
|
Average
PG&E Citygate Monthly Index Price per MMBtu
|
6.70
|
7.72
|
5.85
|
We
historically have been a net purchaser of natural gas, and thus our net income
was negatively impacted when natural gas prices rose higher than its oil
equivalent. In 2005, on a gas balance basis, we achieved parity due to our
eastern Colorado (Tri-State) Niobrara gas acquisition. Thus, in 2006 and looking
forward, we have been a net seller of gas and will benefit operationally when
gas prices are higher. Increased production at Tri-State and the acquisition
and
development of the Piceance basin assets, which are all gas, has allowed us
to
improve our long natural gas position in 2006. The balance between natural
gas
consumed and produced during the fourth quarter ended December 31, 2006 was
approximately as follows (MMBtu/D):
|
Natural
gas consumed in:
|
|||||||
|
Cogeneration
operations
|
27,000
|
||||||
|
Conventional
boilers
|
18,000
|
||||||
|
Total
natural gas consumed
|
45,000
|
||||||
|
Less:
Our estimate of approximate natural gas consumed to produce electricity
(1)
|
(22,000
|
)
|
|||||
|
Total
approximate natural gas volumes consumed to produce steam
|
23,000
|
||||||
|
Natural
gas produced:
|
|||||||
|
Tri-State
(Niobrara)
|
19,000
|
||||||
|
Brundage
Canyon (associated gas)
|
15,000
|
||||||
|
Piceance
and other
|
8,000
|
||||||
|
Total
natural gas volumes produced in operations
|
42,000
|
||||||
(1)
We estimate this volume based on electricity revenues divided by the purchase
price, including transportation, per MMBtu for the respective
period.
Electricity.
Generation.
The
total
annual average electrical generation of our three cogeneration facilities is
approximately 93 megawatts (MW), of which we consume approximately 8 MW for
use
in our operations. Each facility is centrally located on an oil producing
property. Thus the steam generated by the facility is capable of being delivered
to the wells that require steam for the EOR process. Our investment in our
cogeneration facilities has been for the express purpose of lowering the steam
costs in our heavy oil operations and securing operating control of the
respective steam generation. Expenses of operating the cogeneration plants
are
analyzed regularly to determine whether they are advantageous versus
conventional steam boilers. Cogeneration costs are allocated between electricity
generation and oil and gas operations based on the conversion efficiency (of
fuel to electricity and steam) of each cogeneration facility and certain direct
costs to produce steam. Cogeneration costs allocated to electricity will vary
based on, among other factors, the thermal efficiency of our cogeneration
plants, the price of natural gas used for fuel in generating electricity and
steam, and the terms of our power contracts. We view any profit or loss from
the
generation of electricity as a decrease or increase, respectively, to our total
8
cost
of
producing heavy oil in California. DD&A related to our cogeneration
facilities is allocated between electricity operations and oil and gas
operations using a similar allocation method.
Sales
Contracts. Historically,
we have sold electricity produced by our cogeneration facilities, each of which
is a Qualifying Facility (QF) under the Public Utilities Regulatory Policy
Act
of 1978, as amended (PURPA), to two California public utilities; Southern
California Edison Company (Edison) and PG&E, under long-term contracts
approved by the California Public Utilities Commission (CPUC). These contracts
are referred to as standard offer (SO) contracts under which we are paid an
energy payment that reflects the utility’s Short Run Avoided Cost (SRAC) plus a
capacity payment that reflects a recovery of capital expenditures that would
otherwise have been made by the utility. An SO2 contract is more beneficial
as
it requires the utility to pay a higher capacity payment than an SO1contract.
The SRAC energy price is currently determined by a formula approved by the
CPUC
that reflects the utility’s marginal fuel cost and a conversion efficiency that
represents a hypothetical resource to generate electricity in the absence of
the
cogenerator. During most periods natural gas is the marginal fuel for California
utilities, so this formula provides a hedge against our cost of gas to produce
electricity and steam in our cogeneration facilities. A proceeding is now
underway at the CPUC to review and revise the methodology used to determine
SRAC
energy prices and to determine to what extent the utilities would be required
to
enter into further contracts with QFs. It is not known when the CPUC will issue
a decision on SRAC pricing revisions. Also, there is no assurance that any
new
methodology will continue to provide a hedge against our fuel cost or that
a
revised pricing mechanism or terms will be as beneficial as the current contract
pricing and terms.
The
original SO2 contract for Placerita Unit 1 continues in effect through March
2009. This unit makes up approximately 6% of our total approximate barrels
of
steam per day (BSPD). The modified SRAC pricing terms of this contract reflected
a fixed energy price of 5.37 cents/kilowatt hour (KWh) through June 2006, at
which time the energy price reverted to the SRAC pricing methodology. We are
paid a capacity payment that is fixed through the term of the contract.
In
December 2004, we executed a five-year SO1 contract with Edison for the
Placerita Unit 2 facility, and five-year SO1 contracts with PG&E for the
Cogen 18 and Cogen 38 facilities, each effective January 1, 2005. Pursuant
to
these contracts, we are paid the purchasing utility’s SRAC energy price and a
capacity payment that is subject to adjustment from time to time by the CPUC.
Edison and PG&E challenged, in the California Court of Appeals, the legality
of the CPUC decision that ordered the utilities to enter into these five-year
SO1 contracts, and similar one-year SO1 contracts that were ordered for 2004.
The Court ruled that the CPUC had the right to order the utilities to execute
these contracts. The Court also ruled that the CPUC was obligated to review
the
prices paid under the contracts and to adjust the prices retroactively to the
extent it was later determined that such prices did not comply with the
requirements of PURPA. To date, the CPUC has taken no final action based on
this
court ruling.
We
believe that QFs, such as our facilities, provide an important source of
distributive power generation into California's electricity grid, and as such,
that our facilities will be economic to operate for at least the current
five-year contract term. Based on the current pricing mechanism for our
electricity under the contracts (which includes electricity purchased for
internal use), we expect that our electricity revenues will be in the $45
million to $55 million range for 2007.
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. The facility also must meet certain energy efficiency standards. Each
of
our cogeneration facilities is a QF, pursuant to PURPA.
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
(1)
|
20
|
-
|
6,500
|
|||||||
|
Placerita
Unit 2
|
SO1
|
Edison
|
Dec-09
|
16
|
4
|
6,500
|
|||||||
|
|
|
|
|
|
|
|
|||||||
|
Midway-Sunset
|
|
|
|
|
|
|
|||||||
|
Cogen
18
|
SO1
|
PG&E
|
Dec-09
|
12
|
4
|
6,700
|
|||||||
|
Cogen
38
|
SO1
|
PG&E
|
Dec-09
|
37
|
-
|
18,000
|
(1)
On July 1, 2006, the contract pricing converted to the SRAC pricing of the
original contract.
9
Competition. The
oil
and gas industry is highly competitive. As an independent producer we have
little control over the price we receive for our crude oil and natural gas.
As
such, higher costs, fees and taxes assessed at the producer level cannot
necessarily be passed on to our customers. In acquisition activities,
competition is intense as integrated and independent companies and individual
producers are active bidders for desirable oil and gas properties and
prospective acreage. Although many of these competitors have greater financial
and other resources than we have, we believe we are in a position to compete
effectively due to our business strengths (identified on page 4) and our
determination to grow our business.
Employees. On
December 31, 2006, we had 243 full-time employees, up from 209 full-time
employees on December 31, 2005.
10
Capital
Expenditures Summary (Excluding Acquisitions).
The
following is a summary of the developmental capital expenditures incurred during
2006 and 2005 and budgeted capital expenditures for 2007 (in thousands):
| 2007 |
2006
|
2005
|
|||||||||||||||||
|
(Budgeted)
(1)
|
|||||||||||||||||||
| CALIFORNIA | |||||||||||||||||||
| Midway-Sunset field | |||||||||||||||||||
| New wells |
$
|
46,108
|
$
|
42,350
|
$
|
17,369
|
|||||||||||||
|
Remedials/workovers
|
|
2,355
|
|
|
2,261
|
|
|
1,079
|
|
||||||||||
|
Facilities
- oil & gas
|
|
19,156
|
|
|
20,558
|
|
|
7,879
|
|
||||||||||
|
Facilities
- cogeneration
|
|
55
|
|
|
415
|
|
|
3,053
|
|
||||||||||
|
General
|
|
1,875
|
|
|
479
|
|
|
1,271
|
|
||||||||||
|
|
|
69,549
|
|
|
66,063
|
|
|
30,651
|
|
||||||||||
|
Other
California fields
|
|
|
|
|
|
|
|||||||||||||
|
New
wells
|
|
10,270
|
|
|
8,641
|
|
|
6,965
|
|
||||||||||
|
Remedials/workovers
|
|
2,185
|
|
|
2,788
|
|
|
5,303
|
|
||||||||||
|
Facilities
- oil & gas
|
|
5,230
|
|
|
6,599
|
|
|
3,677
|
|
||||||||||
|
Facilities
- cogeneration
|
|
2,616
|
|
|
177
|
|
|
1,446
|
|
||||||||||
|
General
|
245
|
25
|
46
|
||||||||||||||||
|
|
|
20,546
|
|
|
18,230
|
|
|
17,437
|
|
||||||||||
|
Total
California
|
|
90,095
|
|
|
84,293
|
|
|
48,088
|
|
||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
|
ROCKY
MOUNTAIN/MID-CONTINENT
|
|
|
|
|
|
|
|||||||||||||
|
Uinta
Basin
|
|
|
|
|
|
|
|||||||||||||
|
New
wells
|
|
34,689
|
|
|
103,183
|
|
|
50,354
|
|
||||||||||
|
Remedials/workovers
|
|
-
|
|
|
1,213
|
|
|
3,415
|
|
||||||||||
|
Facilities
|
|
3,098
|
|
|
5,966
|
|
|
1,860
|
|
||||||||||
|
General
|
-
|
1,072
|
4
|
||||||||||||||||
|
|
|
37,787
|
|
|
111,434
|
|
|
55,633
|
|
||||||||||
|
Piceance
Basin
|
|
|
|
|
|
|
|||||||||||||
|
New
wells
|
94,534
|
36,654
|
-
|
||||||||||||||||
|
Facilities
|
23,190
|
3,561
|
-
|
||||||||||||||||
|
|
|
117,724
|
|
|
40,215
|
|
|
-
|
|
||||||||||
|
DJ
Basin
|
|
|
|
|
|
|
|||||||||||||
|
New
wells/workovers
|
|
12,241
|
|
|
19,468
|
|
|
11,257
|
|
||||||||||
|
Remedials/workovers
|
1,248
|
1,511
|
693
|
||||||||||||||||
|
Facilities
|
|
5,151
|
|
|
7,883
|
|
|
2,569
|
|
||||||||||
|
General
|
366
|
427
|
387
|
||||||||||||||||
|
Land
and seismic
|
|
880
|
|
|
-
|
|
|
-
|
|
||||||||||
|
|
|
19,886
|
|
|
29,289
|
|
|
14,906
|
|
||||||||||
|
Williston
Basin - New wells
|
|
-
|
|
|
1,611
|
|
|
-
|
|
||||||||||
|
Total
Rocky Mountain and
|
|
|
|
|
|
|
|||||||||||||
|
Mid-Continent
|
|
175,397
|
|
|
182,549
|
|
|
70,539
|
|
||||||||||
|
Other
Fixed Assets
|
|
2,000
|
|
|
19,574
|
|
|
647
|
|
||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
|
TOTAL
|
$
|
267,492
|
|
$
|
286,416
|
|
$
|
119,274
|
|
(1) Budgeted
capital expenditures may be adjusted for numerous reasons including, but not
limited to, oil and natural gas price levels and equipment availability,
permitting and regulatory issues.
See Item
7 Management's Discussion and Analysis of Financial Condition and Results of
Operation.
11
Production. The
following table sets forth certain information regarding production for the
years ended December 31, as indicated:
|
2006
|
2005
|
2004
|
|||||||||||||||||||
| Net annual production: (1) | |||||||||||||||||||||
| Oil (Mbbl) |
7,182
|
7,081
|
7,044
|
||||||||||||||||||
|
Gas
(MMcf)
|
|
12,526
|
|
|
7,919
|
|
|
2,839
|
|
||||||||||||
|
Total
equivalent barrels (MBOE) (2)
|
|
9,270
|
|
|
8,401
|
|
|
7,517
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Average
sales price:
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Oil
(per Bbl) before hedging
|
|
$
|
52.92
|
|
$
|
47.04
|
|
$
|
33.43
|
|
|||||||||||
|
Oil
(per Bbl) after hedging
|
|
|
50.55
|
|
|
40.83
|
|
|
29.89
|
|
|||||||||||
|
Gas
(per Mcf) before hedging
|
|
|
5.48
|
|
|
7.88
|
|
|
6.13
|
|
|||||||||||
|
Gas
(per Mcf) after hedging
|
|
|
5.57
|
|
|
7.73
|
|
|
6.12
|
|
|||||||||||
|
Per
BOE before hedging
|
|
|
48.38
|
|
|
47.01
|
|
|
33.64
|
|
|||||||||||
|
Per
BOE after hedging
|
|
|
46.67
|
|
|
41.62
|
|
|
30.32
|
|
|||||||||||
|
Average
operating cost - oil and gas production (per BOE)
|
|
|
12.69
|
|
|
11.79
|
|
|
10.09
|
|
Mbbl
-
Thousands of barrels
MMcf
-
Million cubic feet
Bcf
-
Billion cubic feet
BOE
-
Barrels of oil equivalent
MBOE
-
Thousand barrels of oil equivalent
(1)
Net production represents that owned by us and produced to our
interests.
(2)
Equivalent oil and gas information is at a ratio of 6 thousand cubic feet (Mcf)
of natural gas to 1 barrel (Bbl) of oil. A barrel of oil is equivalent to 42
U.S. gallons
Acreage
and Wells. As
of
December 31, 2006, our properties accounted for the following developed and
undeveloped acres:
|
|
Developed Acres |
|
Undeveloped
Acres
|
|
Total
|
||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||
| California |
7,559
|
7,559
|
7,038
|
7,038
|
14,597
|
14,597
|
|||||||||||||||||||||||||||||||||
|
Colorado
|
86,504
|
70,504
|
166,994
|
80,602
|
253,498
|
151,106
|
|||||||||||||||||||||||||||||||||
|
Illinois
|
|
-
|
-
|
6,161
|
5,552
|
6,161
|
5,552
|
|
|||||||||||||||||||||||||||||||
|
Kansas
|
|
-
|
-
|
467,623
|
293,311
|
467,623
|
293,311
|
|
|||||||||||||||||||||||||||||||
|
Nebraska
|
-
|
-
|
124,025
|
57,756
|
124,025
|
57,756
|
|||||||||||||||||||||||||||||||||
|
North
Dakota
|
-
|
-
|
207,476
|
49,186
|
207,476
|
49,186
|
|||||||||||||||||||||||||||||||||
|
Utah
(1) (2)
|
|
13,960
|
13,800
|
145,425
|
88,454
|
159,385
|
102,254
|
|
|||||||||||||||||||||||||||||||
|
Wyoming
|
|
3,800
|
750
|
3,146
|
1,130
|
6,946
|
1,880
|
|
|||||||||||||||||||||||||||||||
|
Other
|
|
80
|
19
|
-
|
-
|
80
|
19
|
|
|||||||||||||||||||||||||||||||
|
|
|
111,903
|
92,632
|
1,127,888
|
583,029
|
1,239,791
|
675,661
|
|
(1)
Includes 44,583 gross undeveloped acres (22,292 net) where we have an interest
in 75% of the deep rights and 25% of the shallow rights.
(2)
Does not include 125,000 gross (70,000 net) acres and 125,000 gross (23,000
net)
acres at Lake Canyon (shallow) and Lake Canyon (deep), respectively, which
we
can earn upon fulfilling specific drilling obligations.
Gross
acres represent acres in which we have a working interest; net acres represent
our aggregate working interests in the gross acres.
As
of
December 31, 2006, we have 3,050 gross productive wells (2,531 net). Gross
wells represent the total number of wells in which we have a working interest.
Net wells represent the number of gross wells multiplied by the percentages
of
the working interests owned by us. One or more completions in the same bore
hole
are counted as one well. Any well in which one of the multiple completions
is an
oil completion is classified as an oil well.
12
Drilling
Activity. The
following table sets forth certain information regarding our drilling activities
for the periods indicated:
|
2006
|
|
2005
|
2004
|
||||||||||||||||||||||||||||||||||||
|
Gross
|
Net |
Gross
|
Net |
Gross
|
Net | ||||||||||||||||||||||||||||||||||
| Exploratory wells drilled (1): | |||||||||||||||||||||||||||||||||||||||
| Productive |
7
|
3
|
13 |
6
|
5
|
5 | |||||||||||||||||||||||||||||||||
|
Dry
(2)
|
|
5
|
1
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|||||||||||||||||||||||
|
Development
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
Productive
|
|
532
|
356
|
|
|
213
|
|
|
176
|
|
|
123
|
|
|
111
|
|
|||||||||||||||||||||||
|
Dry
(2)
|
|
7
|
5
|
|
|
7
|
|
|
5
|
|
|
-
|
|
|
-
|
|
|||||||||||||||||||||||
|
Total
wells drilled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
Productive
|
|
539
|
359
|
|
|
226
|
|
|
182
|
|
|
128
|
|
|
116
|
|
|||||||||||||||||||||||
|
Dry
(2)
|
|
12
|
6
|
|
|
8
|
|
|
6
|
|
|
-
|
|
|
-
|
|
(1)
2005 does not include one gross well drilled by our industry partner that was
being evaluated at December 31, 2005.
(2)
A
dry well is a well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas
well.
|
2006
|
|||||||||||||
|
Gross
|
Net | ||||||||||||
| Total productive wells drilled: | |||||||||||||
|
Oil
|
|
|
258
|
254
|
|||||||||
|
Gas
|
|
|
281
|
105
|
Dry
hole, abandonment and impairment.
See
Item
7 Management’s Discussion and Analysis of Financial Condition and Results of
Operation.
Company
Owned Drilling Rigs.
During
2005 and 2006, we purchased three drilling rigs, two of which are operational.
Our third rig is being refurbished and is scheduled to begin drilling in the
Piceance in 2007. Owning these rigs allows us to successfully meet a portion
of
our drilling needs in the Uinta and Piceance basins. See Note 10 to the
financial statements.
Other.
At
year-end, we had no subsidiaries, no special purpose entities and no off-balance
sheet debt. We did not enter into any material related party transactions in
2006.
Environmental
and Other Regulations. We
are
committed to responsible management of the environment and prudent health and
safety policies, as these areas relate to our operations. We strive to achieve
the long-term goal of sustainable development within the framework of sound
environmental, health and safety practices and standards. We strive to make
environmental, health and safety protection an integral part of all business
activities, from the acquisition and management of our resources to the
decommissioning and reclamation of our wells and facilities.
We
have
programs in place to identify and manage known risks, to train employees in
the
proper performance of their duties and to incorporate viable new technologies
into our operations. The costs incurred to ensure compliance with environmental,
health and safety laws and other regulations are normal operating expenses
and
are not material to our operating cost. There can be no assurances, however,
that changes in, or additions to, laws and regulations regarding the protection
of the environment will not have an impact in the future. We maintain insurance
coverage that we believe is customary in the industry although we are not fully
insured against all environmental or other risks.
Environmental
regulation. Our
oil
and gas exploration, production and related operations are subject to numerous
and frequently changing federal, state, tribal and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Environmental laws and regulations may require
the
acquisition of certain permits prior to or in connection with drilling
activities or other operations, restrict or prohibit the types, quantities
and
concentration of substances that can be released into the environment including
releases in connection with drilling and production, restrict or prohibit
drilling activities or other operations that could impact wetlands, endangered
or threatened species or other protected areas or natural resources, require
remedial action to mitigate pollution from ongoing or former operations, such
as
cleanup of environmental contamination, pit cleanups and plugging of abandoned
wells, and impose substantial liabilities for pollution resulting from our
operations. See Item 1A Risk Factors—"We are subject to complex federal, state,
regional, local and other laws and regulations that could give rise to
substantial liabilities from environmental contamination or otherwise adversely
affect our cost, manner or feasibility of doing business."
13
Regulation
of oil and gas. The
oil
and gas industry, including our operations, is extensively regulated by numerous
federal, state and local authorities, and with respect to tribal lands, Native
American tribes.
These
types of regulations include requiring permits for the drilling of wells, the
drilling bonds and the reports concerning operations. Regulations may also
govern the location of wells, the method of drilling and casing wells, the
rates
of production or "allowables," the surface use and restoration of properties
upon which wells are drilled, the plugging and abandoning of wells, and
notifying of surface owners and other third parties. Certain laws and
regulations may limit the amount of oil and natural gas we can produce from
our
wells or limit the number of wells or the locations at which we can drill.
We
are also subject to various laws and regulations pertaining to Native American
tribal surface ownership, to Native American oil and gas leases and other
exploration agreements, fees, taxes, or other burdens, obligations and issues
unique to oil and gas ownership and operations within Native American
reservations.
Federal
energy regulation.
The
enactment of PURPA, as amended, and the adoption of regulations thereunder
by
the Federal Energy Regulatory Commission (FERC) provided incentives for the
development of cogeneration facilities such as ours. A domestic electricity
generating project must be a QF under FERC regulations in order to benefit
from
certain rate and regulatory incentives provided by PURPA.
PURPA
provides two primary benefits to QFs. First, QFs generally are relieved of
compliance with extensive federal and state regulations that control the
financial structure of an electricity generating plant and the prices and terms
on which electricity may be sold by the plant. Second, FERC's regulations
promulgated under PURPA require that electric utilities purchase electricity
generated by QFs at a price based on the purchasing utility's avoided cost,
and
that the utility sell back-up power to the QF on a non-discriminatory basis.
The
term "avoided cost" is defined as the incremental cost to an electric utility
of
electric energy or capacity, or both, which, but for the purchase from QFs,
such
utility would generate for itself or purchase from another source. The Energy
Policy Act of 2005 amends PURPA to allow a utility to petition FERC to be
relieved of its obligation to enter into any new contracts with QFs if the
FERC
determines that a competitive wholesale electricity market is available to
QFs
in its service territory. Such a determination has not been made for our service
areas in California. This amendment does not affect any of our current SO
contracts. FERC issued an order on October 20, 2006 implementing this amendment
to PURPA and on December 20, 2006 issued a subsequent order granting limited
rehearing of the October 20, 2006 order. FERC regulations also permit QFs and
utilities to negotiate agreements for utility purchases of power at rates lower
than the utilities' avoided costs.
State
energy regulation.
The CPUC
has broad authority to regulate both the rates charged by, and the financial
activities of, electric utilities operating in California and to promulgate
regulation for implementation of PURPA. Since a power sales agreement becomes
a
part of a utility's cost structure (generally reflected in its retail rates),
power sales agreements with independent electricity producers, such as we,
are
potentially under the regulatory purview of the CPUC and in particular the
process by which the utility has entered into the power sales agreements. While
we are not subject to regulation by the CPUC, the CPUC's implementation of
PURPA
is important to us.
Forward
Looking Statements
“Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-K that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “will,” “might,”
“intend,” “continue,” “target(s),” “expect,” “achieve,” “strategy,” “future,”
“may,” “could,” “goal(s),”, “forecast,” “anticipate,” or other comparable words
or phrases, or the negative of those words, and other words of similar meaning
indicate forward-looking statements and important factors which could affect
actual results. Forward-looking statements are made based on management’s
current expectations and beliefs concerning future developments and their
potential effects upon Berry Petroleum Company. These items are discussed at
length in Part I, Item 1A on page 15 of this Form 10-K filed with the
Securities and Exchange Commission, under the heading “Risk
Factors.”
14
Item
1A. Risk Factors
Other
Factors Affecting the Company's Business and Financial
Results
Oil
and gas prices fluctuate widely, and low prices for an extended period of time
are likely to have a material adverse impact on our business, results of
operations and financial condition.
Our
revenues, profitability and future growth and reserve calculations depend
substantially on reasonable prices for oil and gas. These prices also affect
the
amount of our cash flow available for capital expenditures, working capital
and
payments on our debt and our ability to borrow and raise additional capital.
The
amount we can borrow under our senior unsecured revolving credit facility (see
Note 6 to the financial statements) is subject to periodic asset
redeterminations based in part on changing expectations of future crude oil
and
natural gas prices. Lower prices may also reduce the amount of oil and gas
that
we can produce economically.
Among
the
factors that can cause fluctuations are:
| · |
domestic
and foreign supply, and perceptions of supply, of oil and natural
gas;
|
| · |
level
of consumer demand;
|
| · |
political
conditions in oil and gas producing regions;
|
| · |
weather
conditions;
|
| · |
world-wide
economic conditions;
|
| · |
domestic
and foreign governmental regulations;
and
|
| · |
price
and availability of alternative
fuels
|
We
have
multiple hedges placed on our oil and gas production. See Item 7A Quantitative
and Qualitative Disclosures About Market Risk.
Our
heavy crude in California is less economic than lighter crude oil and natural
gas.
As of
December 31, 2006, approximately 66% of our proved reserves, or
99 million barrels, consisted of heavy oil. Light crude oil represented 9%
and natural gas represented 25% of our oil and gas reserves. Heavy crude oil
sells for a discount to light crude oil, as more complex refining equipment
is
required to convert heavy oil into high value products. We currently sell our
heavy crude oil in California under a long-term contract for approximately
$8.15
below WTI NYMEX, the U.S. benchmark crude oil, pricing. Additionally, most
of
our crude oil in California is produced using the enhanced oil recovery process
of steam injection. This process is more costly than primary and secondary
recovery methods.
In
November 2005, we entered into a new crude oil sales contract for our California
production for deliveries beginning February 1, 2006 and ending January 31,
2010. The per barrel price, calculated on a monthly basis and blended across
the
various producing locations, is the higher of 1) the WTI NYMEX crude oil price
less a fixed differential approximating $8.15, or 2) heavy oil field postings
plus a premium of approximately $1.35.
A
widening of commodity differentials may adversely impact our revenues and per
barrel economics. Both
our
produced crude oil and natural gas are subject to pricing in the local markets
where the production occurs. It is customary that such products are priced
based
on local or regional supply and demand factors. California heavy crude oil
sells
at a discount to WTI, primarily due to the additional cost to refine gasoline
or
light product out of a barrel of heavy crude. In addition, our Utah light crude
contracts are currently priced at approximately $13 to $20 per barrel below
WTI
with certain volumes tied to field posting, and in some cases our realized
price
is further reduced by transportation charges. Natural gas field prices are
normally priced off of Henry Hub NYMEX price, the benchmark for U.S. natural
gas. While we attempt to contract for the best possible price in each of our
producing locations, there is no assurance that past price differentials will
continue into the future. Numerous factors may influence local pricing, such
as
refinery capacity, particularly for paraffinic crude, pipeline capacity and
specifications, upsets in the mid-stream or downstream sectors of the industry,
trade restrictions and governmental regulations. We may be adversely impacted
by
a widening differential on the products we sell. Our oil and natural gas hedges
are based on WTI or natural gas index prices, so we may be subject to basis
risk
if the differential on the products we sell widens from those benchmarks if
we
do not have a contract tied to those benchmarks. Additionally, insufficient
pipeline capacity and the lack of demand in any given operating area may cause
the differential to widen in that area compared to other oil and gas producing
areas.
Market
conditions or operational impediments may hinder our access to crude oil and
natural gas markets or delay our production. Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand
for
and supply of oil and natural gas and the proximity of reserves to pipelines
and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines,
processing facilities and refineries owned and operated by third parties. Our
failure to obtain such services on acceptable terms could materially harm our
business. We may be required to shut in wells for a lack of a market or because
of
15
inadequacy
or unavailability of natural gas pipelines, gathering system capacity,
processing facilities or refineries. If that were to occur, then we would be
unable to realize revenue from those wells until arrangements were made to
deliver the production to market. See
firm
transportation summary schedule at Item 1 Business.
Factors
that can cause price volatility for crude oil and natural gas
include:
| · |
availability
and capacity of refineries;
|
| · |
availability
of gathering systems with sufficient capacity to handle local
production;
|
| · |
seasonal
fluctuations in local demand for
production;
|
| · |
local
and national gas storage capacity;
|
| · |
interstate
pipeline capacity; and
|
| · |
availability
and cost of gas transportation facilities.
|
Utah
- As
of December 31, 2006, our Utah light crude oil is sold under multiple contracts
with different purchasers for varying pricing terms and ranging from one month
to nine months. As of December 31, 2006 we had firm contracts for 4,250 barrels
per day (Bbl/D). These contracts are currently priced at approximately $13
to
$20 per barrel below WTI with certain volumes tied to field posting, and in
some
cases our realized price is further reduced by transportation charges. As
operator we deliver all produced volumes pursuant to these contracts, although
our working interest partners or royalty owners may take their respective
volumes in kind and market their own volumes. Our net volumes from our Brundage
Canyon properties approximate 80% of the total gross volumes. Assuming all
the
Brundage Canyon wells are producing, the gross production could exceed these
contracted volumes. We experienced increasing difficulty in locating additional
buyers of our crude oil production from this region in 2006. Our Utah crude
oil
is a paraffinic crude, locally known as a black wax crude, and can be processed
efficiently by only a limited number of refineries. Increased production of
crude oil in the region, the ability of refiners to process other higher sulfur
crudes as a result of capital upgrades, as well as the increasing availability
of Canadian crude oil, is putting downward pressure on the sales price of our
crude oil.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract
with
a subsidiary of Holly Corporation (Holly) for our Uinta basin crude oil. Under
the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July 1, 2007.
Upon completion of their Woods Cross refinery expansion in Salt Lake City,
which
is expected in mid 2008, Holly will increase their total purchased volumes
to
5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes
transportation, is a fixed percentage of WTI and approximates our expected
field
posted price of $13 to $16 below WTI. From October 1, 2003 through
April 30, 2006 we were able to sell our Utah crude oil at approximately
$2.00 per barrel below WTI and from May 1, 2006 through September 30,
2006, we were selling the majority of our Utah crude at approximately $9.00
per
barrel below WTI. Due to this lower pricing, and based on sales of 3,500 Bbl/D,
our revenues were lower by approximately $9.2 million in 2006 as compared
to 2005. If this pricing continues throughout 2007, with our Holly contract
in
place and on the same volumes, we estimate our revenues will be lower by
approximately $8.6 million versus our 2006 revenues. We may adjust our
capital expenditures in the Uinta basin due to various factors, including the
timing of refinery demand for the Uinta barrels and the actual or expected
change in our realized price.
We
may be subject to the risk of adding additional steam generation equipment
if
the electrical market deteriorates significantly.
We are
dependent on several cogeneration facilities that, combined, provide
approximately 40% of our steam requirement. These facilities are dependent
on
reasonable power contracts for the sale of electricity. If, for any reason,
including if utilities that purchase electricity from us are no longer required
by regulation to enter into power contracts with us, we were unable to enter
into new or replacement contracts or were to lose any existing contract, we
may
not be able to supply 100% of the steam requirements necessary to maximize
production from our heavy oil assets. An additional investment in various steam
sources may be necessary to replace such steam, and there may be risks and
delays in being able to install conventional steam equipment due to permitting
requirements. The financial cost and timing of such new investment may adversely
affect our production, capital outlays and cash provided by operating
activities. We have power contracts covering our electricity generation which
contracts expire in 2009.
The
future of the electricity market in California is
uncertain.
We
utilize cogeneration plants in California to generate lower cost steam compared
to conventional steam generation methods. Electricity produced by our
cogeneration plants is sold to utilities and the steam costs are allocated
to
our oil and gas operations. While we have electricity sales contracts in place
with the utilities that are currently scheduled to terminate in 2009, legal
and
regulatory decisions, (especially related to the pricing of electricity under
the contracts), can adversely affect the economics of our cogeneration
facilities and thereby, the cost of steam for use in our oil and gas
operations.
A
shortage of natural gas in California could adversely affect our business.
We
may be
subject to the risks associated with a shortage of natural gas and/or the
transportation of natural gas into and within California. We are highly
dependent on sufficient volumes of natural gas necessary to use for fuel in
generating steam in our heavy oil operations in California. If the required
volume of natural gas for use in our operations were to be unavailable or too
highly priced to produce heavy oil economically, our production could be
adversely impacted. We have firm transportation to move 12,000 MMBtu/D on the
Kern River Pipeline from the Rocky Mountains to Kern County, CA, which accounts
for approximately one-third of our current requirement.
16
Our
use of oil and gas price and interest rate hedging contracts involves credit
risk and may limit future revenues from price increases or reduced expenses
from
lower interest rates, as well as result in significant fluctuations in net
income and shareholders' equity.
We use
hedging transactions with respect to a portion of our oil and gas production
with the objective of achieving a more predictable cash flow, and to reduce
our
exposure to a significant decline in the price of crude oil and natural gas.
We
also utilize interest rate hedges to fix the rate on a portion of our variable
rate indebtedness, as only a portion of our total indebtedness has a fixed
rate
and we are therefore exposed to fluctuations in interest rates. While the use
of
hedging transactions limits the downside risk of price declines or rising
interest rates, as applicable, their use may also limit future revenues from
price increases or reduced expenses from lower interest rates, as applicable.
Hedging transactions also involve the risk that the counterparty may be unable
to satisfy its obligations.
Our
future success depends on our ability to find, develop and acquire oil and
gas
reserves.
To
maintain production levels, we must locate and develop or acquire new oil and
gas reserves to replace those depleted by production. Without successful
exploration, exploitation or acquisition activities, our reserves, production
and revenues will decline. We may not be able to find, develop or to acquire
additional reserves at an acceptable cost. In addition, substantial capital
is
required to replace and grow reserves. If lower oil and gas prices or operating
difficulties result in our cash flow from operations being less than expected
or
limit our ability to borrow under credit arrangements, we may be unable to
expend the capital necessary to locate and to develop or acquire new oil and
gas
reserves.
Actual
quantities of recoverable oil and gas reserves and future cash flows from those
reserves ,
future production, oil and gas prices, revenues, taxes, development expenditures
and operating expenses most likely will vary from
estimates. Estimating
accumulations of oil and gas is complex. The process relies on interpretations
of available geologic, geophysical, engineering and production data. The extent,
quality and reliability of this data can vary. The process also requires certain
economic assumptions, such as oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds, some of which
are mandated by the SEC. The accuracy of a reserve estimate is a function
of:
| · |
quality
and quantity of available data;
|
| · |
interpretation
of that data; and
|
| · |
accuracy
of various mandated economic
assumptions.
|
Any
significant variance could materially affect the quantities and present value
of
our reserves. In addition, we may adjust estimates of proved reserves to reflect
production history, results of development and exploration and prevailing oil
and gas prices.
In
accordance with SEC requirements, we base the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate.
If
oil or gas prices decrease or if our exploration and development activities
are
unsuccessful, we may be required to take writedowns. We
may be
required to writedown the carrying value of our oil and gas properties when
oil
or gas prices are low, including the impact of basis differentials, or if there
are substantial downward adjustments to our estimated proved reserves, increases
in estimates of development and/or operating costs or deterioration in
exploration or production results.
We
capitalize costs to acquire, find and develop our oil and gas properties under
the successful efforts accounting method. If net capitalized costs of our oil
and gas properties exceed fair value, we must charge the amount of the excess
to
earnings. We review the carrying value of our properties annually and at any
time when events or circumstances indicate a review is necessary, based on
prices in effect as of the end of the reporting period. The carrying value
of
oil and gas properties is computed on a field-by-field basis. Once incurred,
a
writedown of oil and gas properties is not reversible at a later date even
if
oil or gas prices increase. See Item 7A Quantitative and Qualitative Disclosures
About Market Risk for our hedge position on February 9, 2007.
Competitive
industry conditions may negatively affect our ability to conduct operations.
Competition
in the oil and gas industry is intense, particularly with respect to the
acquisition of producing properties and of proved undeveloped acreage. Major
and
independent oil and gas companies actively bid for desirable oil and gas
properties, as well as for the equipment, supplies, labor and services required
to operate and develop their properties. Some of these resources may be limited
and have higher prices due to current strong demand. Many of our competitors
have financial resources that are substantially greater, which may adversely
affect our ability to compete within the industry.
17
Drilling
is a high-risk activity.
Our
future success will partly depend on the success of our drilling program. In
addition to the numerous operating risks described in more detail below, these
drilling activities involve the risk that no commercially productive oil or
gas
reservoirs will be discovered. In addition, we are often uncertain as to the
future cost or timing of drilling, completing and producing wells. Furthermore,
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including:
| · |
obtaining
government and tribal required
permits;
|
| · |
unexpected
drilling conditions;
|
| · |
pressure
or irregularities in formations;
|
| · |
equipment
failures or accidents;
|
| · |
adverse
weather conditions;
|
| · |
compliance
with governmental or landowner requirements;
and
|
| · |
shortages
or delays in the availability of drilling rigs and the delivery of
equipment and/or services, including experienced
labor.
|
The
oil and gas business involves many operating risks that can cause substantial
losses; insurance may not protect us against all of these risks. These risks
include:
| · |
fires;
|
| · |
explosions;
|
| · |
blow-outs;
|
| · |
uncontrollable
flows of oil, gas, formation water or drilling
fluids;
|
| · |
natural
disasters;
|
| · |
pipe
or cement failures;
|
| · |
casing
collapses;
|
| · |
embedded
oilfield drilling and service
tools;
|
| · |
abnormally
pressured formations;
|
| · |
major
equipment failures, including cogeneration facilities;
and
|
| · |
environmental
hazards such as oil spills, natural gas leaks, pipeline ruptures
and
discharges of toxic gases.
|
If
any of
these events occur, we could incur substantial losses as a result
of:
| · |
injury
or loss of life;
|
| · |
severe
damage or destruction of property, natural resources and
equipment;
|
| · |
pollution
and other environmental damage;
|
| · |
investigatory
and clean-up responsibilities;
|
| · |
regulatory
investigation and penalties;
|
| · |
suspension
of operations; and
|
| · |
repairs
to resume operations.
|
If
we
experience any of these problems, our ability to conduct operations could be
adversely affected. If a significant accident or other event occurs and is
not
fully covered by insurance, it could adversely affect us. In accordance with
customary industry practices, we maintain insurance coverage against some,
but
not all, potential losses in order to protect against the risks we face. For
instance, we do not carry business interruption insurance. We may elect not
to
carry insurance if our management believes that the cost of available insurance
is excessive relative to the risks presented. In addition, we cannot insure
fully against pollution and environmental risks. The occurrence of an event
not
fully covered by insurance could have a material adverse effect on our financial
condition and results of operations. While we intend to obtain and maintain
insurance coverage we deem appropriate for these risks, there can be no
assurance that our operations will not expose us to liabilities exceeding such
insurance coverage or to liabilities not covered by insurance.
We
are subject to complex federal, state, regional, local and other laws and
regulations that could give rise to substantial liabilities from environmental
contamination or otherwise adversely affect our cost, manner or feasibility
of
doing business. All
facets of our operations are regulated extensively at the federal, state,
regional and local levels. In addition, a portion of our leases in the Uinta
basin are, and some of our future leases may be, regulated by Native American
tribes. Environmental laws and regulations impose limitations on our discharge
of pollutants into the environment, establish standards for our management,
treatment, storage, transportation and disposal of hazardous materials and
of
solid and hazardous wastes, and impose on us obligations to investigate and
remediate contamination in certain circumstances. We also must satisfy, in
some
cases, federal and state requirements for providing environmental assessments,
environmental impact studies and/or plans of development before we commence
exploration and production activities. Environmental and other requirements
applicable to our operations generally have become more stringent in recent
years, and compliance with those requirements more expensive. Frequently
changing environmental and other governmental laws and regulations have
increased our costs to plan, design, drill, install, operate and abandon oil
and
natural gas wells and other facilities, and may impose substantial liabilities
if we fail to comply with such regulations or for any contamination resulting
from our operations. Failure to comply with these laws and regulations may
also
result in the suspension or termination of our operations and
18
subject
us to administrative, civil and criminal penalties. Furthermore, our business,
results from operations and financial condition may be adversely affected by
any
failure to comply with, or future changes to, these laws and
regulations.
In
addition, we could also be liable for the investigation or remediation of
contamination, as well as other liabilities concerning hazardous materials
or
contamination such as claims for personal injury or property damage. Such
liabilities may arise at many locations, including properties in which we have
an ownership interest but no operational control, properties we formerly owned
or operated and sites where our wastes have been treated or disposed of, as
well
as at properties that we currently own or operate, and may arise even where
the
contamination does not result from any noncompliance with applicable
environmental laws. Under a number of environmental laws, such liabilities
may
also be joint and several, meaning that we could be held responsible for more
than our share of the liability involved, or even the entire share. We have
incurred expenses and penalties in connection with remediation of contamination
in the past, and we may do so in the future. From time to time we have
experienced accidental spills, leaks and other discharges of contaminants at
some of our properties, as have other similarly situated oil and gas companies.
Some of the properties that we have acquired, or in which we may hold an
interest but not operational control, may have past or ongoing contamination
for
which we may be held responsible. Some of our operations are in environmentally
sensitive areas, including coastal areas, wetlands, areas that may provide
habitat for endangered or threatened species, and other protected areas, and
our
operations in such areas must satisfy additional regulatory requirements.
Moreover, public interest in environmental protection has increased in recent
years, and environmental organizations have opposed certain drilling projects
and/or access to prospective lands and have filed litigation to attempt to
stop
such projects, including decisions by the Bureau of Land Management regarding
several leases in Utah that we have been awarded.
Our
activities are also subject to the regulation by oil and natural gas-producing
states and one Native American tribe of conservation practices and protection
of
correlative rights. These regulations affect our operations and limit the
quantity of oil and natural gas we may produce and sell. A major risk inherent
in our drilling plans is the need to obtain drilling permits from federal,
state, local and Native American tribal authorities. Delays in obtaining
regulatory approvals or drilling permits, the failure to obtain a drilling
permit for a well or the receipt of a permit with unreasonable conditions that
are more expensive than we have anticipated could have a negative effect on
our
ability to explore on or develop our properties. Additionally, the oil and
natural gas regulatory environment could change in ways that might substantially
increase the financial and managerial costs to comply with the requirements
of
these laws and regulations and, consequently, adversely affect our
profitability.
Recent
and future environmental regulations, including additional state and federal
restrictions on greenhouse gasses that may be passed in response to climate
change concerns, could increase our costs to operate and produce our properties
and also reduce the demand for the oil and gas we produce. On September 27,
2006, California’s governor signed into law Assembly Bill (AB) 32, which
establishes a statewide cap on greenhouse gases (GHG) for 2020 based on 1990
emission levels. The California Air Resources Board (CARB) has been designated
as the lead agency to establish and adopt regulations to implement AB 32 (GHG
Regulations) by January 1, 2012. We will continue to monitor the establishment
of GHG Regulations through industry trade groups and other organizations in
which we are a member. While California’s GHG Regulations apply only to
operations within California, similar regulations may be adopted in other states
in which we conduct business or on a Federal level in the future.
Furthermore,
we benefit from federal energy laws and regulations that relieve our
cogeneration plants, all of which are QFs, from compliance with extensive
federal and state regulations that control the financial structure of
electricity generating plants, as well as the prices and terms on which
electricity may be sold by those plants. These federal energy regulations also
require that electric utilities purchase electricity generated by our
cogeneration plants at a price based on the purchasing utility's avoided cost,
and that the utility sell back-up power to us on a non-discriminatory basis.
The
term "avoided cost" is defined as the incremental cost to an electric utility
of
electric energy or capacity, or both, which, but for the purchase from QFs,
such
utility would generate for itself or purchase from another source. The
Energy Policy Act of 2005 amends PURPA to allow a utility to petition FERC
to be
relieved of its obligation to enter into any new contracts with QFs if the
FERC
determines that a competitive wholesale electricity market is available to
QFs
in its service territory. Such a determination has not been made for our service
areas in California. This amendment does not affect any of our current SO
contracts. FERC issued an order on October 20, 2006 implementing this amendment
to PURPA and on December 20, 2006 issued a subsequent order granting limited
rehearing of the October 20, 2006 order. FERC regulations also permit QFs and
utilities to negotiate agreements for utility purchases of power at rates lower
than the utilities' avoided costs.
Property
acquisitions are a component of our growth strategy, and our failure to complete
future acquisitions successfully could reduce our earnings and slow our
growth.
Our
business strategy has emphasized growth through strategic acquisitions, but
we
may not be able to continue to identify properties for acquisition or we may
not
be able to make acquisitions on terms that we consider economically acceptable.
There is intense competition for acquisition opportunities in our industry.
Competition for acquisitions may increase the cost of, or cause us to refrain
from, completing acquisitions. Our strategy of completing acquisitions is
dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. If we are unable to achieve
strategic acquisitions, our growth may be impaired, thus impacting earnings,
cash from operations and reserves.
19
Acquisitions
are subject to the uncertainties of evaluating recoverable reserves and
potential liabilities.
Our
recent growth is due in part to acquisitions of producing properties with
additional development potential and properties with minimal production at
acquisition but significant growth potential, and we expect acquisitions will
continue to contribute to our future growth. Successful acquisitions require
an
assessment of a number of factors, many of which are beyond our control. These
factors include recoverable reserves, exploration potential, future oil and
natural gas prices, operating costs, production taxes and potential
environmental and other liabilities. Such assessments are inexact and their
accuracy is inherently uncertain. In connection with our assessments, we perform
a review of the acquired properties, which we believe is generally consistent
with industry practices. However, such a review will not reveal all existing
or
potential problems. In addition, our review may not allow us to become
sufficiently familiar with the properties, and we do not always discover
structural, subsurface and environmental problems that may exist or arise.
Our
review prior to signing a definitive purchase agreement may be even more
limited.
We
generally are not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities, on acquisitions. Often, we
acquire interests in properties on an "as is" basis with limited remedies for
breaches of representations and warranties. If material breaches are discovered
by us prior to closing, we could require adjustments to the purchase price
or if
the claims are significant, we or the seller may have a right to terminate
the
agreement. We could also fail to discover breaches or defects prior to closing
and incur significant unknown liabilities, including environmental liabilities,
or experience losses due to title defects, for which we would have limited
or no
contractual remedies or insurance coverage.
There
are risks in acquiring producing properties, including difficulties in
integrating acquired properties into our business, additional liabilities and
expenses associated with acquired properties, diversion of management attention,
and costs of increased scope, geographic diversity and complexity of our
operations. Increasing
our reserve base through acquisitions is an important part of our business
strategy. Our failure to integrate acquired businesses successfully into our
existing business, or the expense incurred in consummating future acquisitions,
could result in our incurring unanticipated expenses and losses. In addition,
we
may have to assume cleanup or reclamation obligations or other unanticipated
liabilities in connection with these acquisitions. The scope and cost of these
obligations may ultimately be materially greater than estimated at the time
of
the acquisition.
In
connection with future acquisitions, the process of integrating acquired
operations into our existing operations may result in unforeseen operating
difficulties and may require significant management attention and financial
resources that would otherwise be available for the ongoing development or
expansion of existing operations
Possible
future acquisitions could result in our incurring additional debt, contingent
liabilities and expenses, all of which could have a material adverse effect
on
our financial condition and operating results.
The
loss of key personnel could adversely affect our
business.
We
depend to a large extent on the efforts and continued employment of our
executive management team and other key personnel. The loss of the services
of
these or other key personnel could adversely affect our business, and we do
not
maintain key man insurance on the lives of any of these persons. Our drilling
success and the success of other activities integral to our operations will
depend, in part, on our ability to attract and retain experienced geologists,
engineers, landmen and other professionals. Competition for many of these
professionals is intense. If we cannot retain our technical personnel or attract
additional experienced technical personnel, our ability to compete could be
harmed.
We
have limited control over the activities on properties that we do not operate.
Although
we operate most of the properties in which we have an interest, other companies
operate some of the properties. We have limited ability to influence or control
the operation or future development of these nonoperated properties or the
amount of capital expenditures that we are required to fund their operation.
Our
dependence on the operator and other working interest owners for these projects
and our limited ability to influence or control the operation and future
development of these properties could have a material adverse effect on the
realization of our targeted returns or lead to unexpected future
costs.
We
may not adhere to our proposed drilling schedule. Our
final
determination of whether to drill any scheduled or budgeted wells will depend
on
a number of factors, including:
| · |
results
of our exploration efforts and the acquisition, review and analysis
of our
seismic data, if any;
|
| · |
availability
of sufficient capital resources to us and any other participants
for the
drilling of the prospects;
|
| · |
approval
of the prospects by other participants after additional data has
been
compiled;
|
| · |
economic
and industry conditions at the time of drilling, including prevailing
and
anticipated prices for oil and natural gas and the availability and
prices
of drilling rigs and crews; and
|
| · |
availability
of leases, license options, farm-outs, other rights to explore and
permits
on reasonable terms for the
prospects.
|
Although
we have identified or budgeted for numerous drilling prospects, we may not
be
able to lease or drill those prospects within our expected time frame, or at
all. In addition, our drilling schedule may vary from our expectations because
of future uncertainties and rig availability and access to our drilling
locations utilizing available roads. As of December 31, 2006, we own three
20
drilling
rigs, one of which is drilling on our property, and have additional one-year
contract commitments on another three drilling rigs. See contractual obligations
in Item 7 Management’s Discussion and Analysis of Financial Condition and
Results of Operation.
We
may incur losses as a result of title deficiencies.
We
acquire from third parties or directly from the mineral fee owners working
and
revenue interests in the oil and natural gas leaseholds and estates upon which
we will perform our exploration activities. The existence of a material title
deficiency can reduce the value or render a property worthless thus adversely
affecting the results of our operations and financial condition. Title insurance
covering mineral leaseholds is not always available and when available is not
always obtained. As is customary in our industry, we rely upon the judgment
of
staff and independent landmen who perform the field work of examining records
in
the appropriate governmental offices and abstract facilities before attempting
to acquire or place under lease a specific mineral interest and/or undertake
drilling activities. We, in some cases, perform curative work to correct
deficiencies in the marketability of the title to us. In cases involving title
problems, the amount paid for affected oil and natural gas leases or estates
can
be generally lost, and a prospect can become undrillable.
Item
1B. Unresolved Staff Comments
None.
Item
2. Properties
Information
required by Item 2 Properties is included under Item 1 Business.
Item
3. Legal Proceedings
While
we
are, from time to time, a party to certain lawsuits in the ordinary course
of
business, we do not believe any of such existing lawsuits will have a material
adverse effect on our operations, financial condition, or liquidity.
Item
4. Submission of Matters to a Vote of Security Holders
No
matters were submitted to a vote of security holders during the most recently
ended fiscal quarter.
Executive
Officers. Listed
below are the names, ages (as of December 31, 2006) and positions of our
executive officers and their business experience during at least the past five
years. All our officers are reappointed in May of each year at an organizational
meeting of the Board of Directors. There are no family relationships between
any
of the executive officers and members of the Board of Directors.
ROBERT
F.
HEINEMANN, 53, 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 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, 50, 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.
MICHAEL
DUGINSKI, 40, has been Executive Vice President of Corporate Development and
California since October 2005. Mr. Duginski was Senior Vice President of
Corporate Development from June 2004 through October 2005 and was Vice President
of Corporate Development from February 2002 through June 2004. Mr. Duginski,
a
mechanical engineer, was previously with Texaco, Inc. from 1988 to 2002 where
his positions included Director of New Business Development, Production Manager
and Gas and Power Operations Manager. Mr. Duginski is also an Assistant
Secretary.
DAN
ANDERSON, 44, has been Vice President of Rocky Mountain/Mid-Continent Production
since October 2005. Mr. Anderson was Rocky Mountain/Mid-Continent Manager of
Engineering from August 2003 through October 2005. Mr. Anderson was previously
a
Senior Staff Petroleum Engineer with Williams Production RMT from August 2001
through August 2003. He previously was a Senior Staff Engineer with Barrett
Resources from October 2000 through August 2001.
21
WALTER
B.
AYERS, 63, has been Vice President of Human Resources since May 2006.
Mr. Ayers was previously a private consultant to the energy industry from
January 2002 until his employment with us. Mr. Ayers served as a
Manager of Human Resources for Mobil Oil Corporation from June 1965 until
December 2000 where his positions included Manager of Compensation and
various other human resource management positions primarily in the upstream
sector of Mobil.
GEORGE
T.
CRAWFORD, 46, has been Vice President of California Production since October
2005. Mr. Crawford was Vice President of Production from December 2000 through
October 2005 and was Manager of Production from January 1999 to December 2000.
Mr. Crawford, a petroleum engineer, previously served as the Production
Engineering Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998
in
numerous engineering and operational assignments including Production
Engineering Supervisor, Planning and Evaluation Consultant and Operations
Superintendent.
BRUCE
S.
KELSO, 51, has been Vice President of Rocky Mountain/Mid-Continent Exploration
since October 2005. Mr. Kelso was Rocky Mountain/Mid-Continent Exploration
Manager from August 2003 through October 2005. Mr. Kelso, a petroleum geologist,
was previously a Senior Staff Geologist assigned to Rocky Mountain assets with
Williams Production RMT, from January 2002 through August 2003. He previously
held the position of Vice President of Exploration and Development at Redstone
Resources, Inc. from 2000 to 2001.
SHAWN
M.
CANADAY, 31, 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 Chevron and
in
public accounting. Mr. Canaday is presently an Assistant Secretary. Effective
March 2, 2007, Mr. Canaday will replace Mr. Wilson as Controller.
KENNETH
A. OLSON, 51, has been Corporate Secretary since December 1985 and was Treasurer
from August 1988 until December 2004.
STEVEN
B.
WILSON, 43, has been Controller since January 2007. Mr. Wilson had been
Assistant Controller since November 2003 and before joining us in November
2003,
served as the vice president of finance and administration for Accela, Inc.,
a
software development company, for three years. Prior to that, he held finance
functions in select companies and in public accounting. Effective March 2,
2007,
Mr. Wilson will replace Mr. Canaday as Treasurer and will also be an Assistant
Secretary.
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 $.50 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option of
the
holder.
In
November 1999, we adopted a Shareholder Rights Agreement and declared a dividend
distribution of one such Right for each outstanding share of Capital Stock
on
December 8, 1999. Each share of Capital Stock issued after December 8, 1999
includes one Right. The Rights expire on December 8, 2009. See Note 7 to the
financial statements.
Our
Class
A Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol
BRY. The Class B Stock is not publicly traded. The market data and dividends
for
2006 and 2005 are shown below:
|
2006
|
2005
|
||||||||||||||||||||||||||||||||||||||
|
Price
Range
|
Dividends
|
Price
Range
|
Dividends
|
||||||||||||||||||||||||||||||||||||
| High | Low |
Per
Share
|
High (1) | Low (1) | Per Share (1) | ||||||||||||||||||||||||||||||||||
|
First
Quarter
|
$
|
39.98
|
$
|
28.60
|
$ |
.065
|
$ |
33.05
|
$ |
21.93
|
$ |
.060
|
|||||||||||||||||||||||||||
|
Second
Quarter
|
|
|
39.00
|
27.27
|
.065
|
|
|
27.48
|
|
|
20.39
|
|
|
.060
|
|
||||||||||||||||||||||||
|
Third
Quarter
|
|
|
35.77
|
26.07
|
.095
|
|
|
33.50
|
|
|
26.15
|
|
|
.115
|
|
||||||||||||||||||||||||
|
Fourth
Quarter
|
|
|
33.69
|
25.71
|
.075
|
|
|
34.33
|
|
|
26.15
|
|
|
.065
|
|
||||||||||||||||||||||||
|
Total
Dividend Paid
|
$
|
.300
|
$
|
.300
|
22
|
|
|
February
9, 2007
|
|
December
31, 2006
|
|
December
31, 2005 (1)
|
|
|||
|
Berry’s
Common Stock closing price per share as reported on NYSE Composite
Transaction Reporting System
|
|
$
|
30.55
|
|
$
|
31.01
|
$
|
28.60
|
|
|
(1)
The 2005 amounts have been restated to give retroactive effect to the
two-for-one stock split that became effective on May 17, 2006.
The
number of holders of record of our Common Stock was 543 as of February 9, 2007.
There was one Class B Shareholder of record as of February 9, 2007.
Dividends.
We
paid a
special dividend of $.02 per share on September 29, 2006 and increased our
regular quarterly dividend by 15%, from $.065 to $.075 per share beginning
with
the September 2006 dividend. Our regular annual dividend is currently $.30
per
share, payable quarterly in March, June, September and December. We paid a
special dividend of $.05 per share on September 29, 2005 and increased our
regular quarterly dividend by 8%, from $.06 to $.065 per share beginning with
the September 2005 dividend.
Since
our
formation in 1985 through December 31, 2006, we have paid dividends on our
Common Stock for 69 consecutive quarters and previous to that for eight
consecutive semi-annual periods. We intend to continue the payment of dividends,
although future dividend payments will depend upon our level of earnings,
operating cash flow, capital commitments, financial covenants and other relevant
factors. Dividend payments are limited by covenants in our 1) credit facility
to
the greater of $20 million or 75% of net income, and 2) bond indenture of up
to
$20 million annually irrespective of our coverage ratio or net income and up
to
$10 million in the event we are in a non-payment default.
As
of
December 31, 2006, dividends declared on 7,793,080 shares of certain Common
Stock are restricted, whereby we pay 37.5% of the dividends declared on these
shares to the surviving member of a group of individuals, the B group, for
as
long as this remaining member shall live.
Equity
Compensation Plan Information.
|
Number
of securities to be
|
|||||||||||||
|
|
|
issued
upon exercise of
|
|
Weighted
average exercise
|
|
Number
of securities
|
|||||||
|
|
|
outstanding
options, warrants
|
|
price
of outstanding options,
|
|
remaining
available for future
|
|||||||
|
Plan
category
|
|
and
rights
|
|
warrants
and rights
|
|
issuance
|
|||||||
|
Equity
compensation plans approved by security holders
|
3,318,991
|
$20.97
|
1,252,344
|
||||||||||
|
|
|
||||||||||||
|
Equity
compensation plans not approved by security holders
|
|
none
|
none
|
none
|
Issuer
Purchases of Equity Securities.
In
June
2005, we announced that our Board of Directors authorized a share repurchase
program for up to an aggregate of $50 million of our outstanding Class A Common
Stock. From June 2005 through December 31, 2006, we have purchased 818,000
shares in the open market for approximately $25 million. In 2006, our
repurchases increased diluted earnings by $.03 per share.
In
December 2005, we adopted a plan under Rule 10b5-1 of the Securities Exchange
Act of 1934 to facilitate the repurchase of our shares of common stock. Rule
10b5-1 allows a company to purchase its shares at times when it would not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. This plan
expired on December 1, 2006. This 10b5-1 plan was authorized under, and
administered consistent with, our $50 million share repurchase program. We
may
repurchase shares in the open market from time to time during our normal trading
windows or under a new plan under 10b5-1. All repurchases of common stock are
made in compliance with regulations set forth by the SEC and are subject to
market conditions, applicable legal requirements and to other factors.
This
share repurchase program does not obligate us to acquire any particular amount
of common stock and the plan may be suspended at any time at our
discretion.
23
|
Period
|
Total
number of shares purchased
|
Average
price paid per share
|
Total
number of shares purchased as part of publicly announced plans or
programs
|
Maximum
number (or approximate dollar value) of shares that may yet be purchased
under the plans or programs
|
||||
|
Fiscal
Year 2005 (1)
|
217,800
|
$
29.00
|
217,800
|
$
43,684,500
|
||||
|
First
Quarter 2006
|
60,000
|
30.04
|
60,000
|
41,882,036
|
||||
|
Second
Quarter 2006
|
347,700
|
31.55
|
347,700
|
30,912,780
|
||||
|
Third
Quarter 2006
|
92,500
|
32.37
|
92,500
|
27,918,703
|
||||
|
October
2006
|
100,000
|
29.48
|
100,000
|
24,971,116
|
||||
|
Total
|
818,000
|
$
30.60
|
818,000
|
$
24,971,116
|
(1)
The 2005 share amounts have been restated to give retroactive effect to the
two-for-one stock split that became effective on May 17, 2006.
Performance
Graph
This
graph shall not be deemed “filed” for purposes of Section 18 of the
Securities and Exchange Act of 1934 (the “Exchange Act”) or otherwise subject to
the liabilities of that section nor shall it be deemed incorporated by reference
in any filing under the Securities Act of 1933 or the Exchange Act, regardless
of any general incorporation language in such filing.
Total
returns assume $100 invested on December 31, 2001 in shares of Berry Petroleum
Company, the Russell 2000, the Standard & Poors 500 Index (S&P 500) and
two Peer Groups, assuming reinvestment of dividends for each measurement period.
In the proxy statement filed in 2006, we added Peer Group 1, which contains
10
companies, which we used for comparisons that year, and in this Form 10-K we
added Peer Group 2. We believe Peer Group 2 is a better comparison index for
our
performance graph based on similar types of assets and market capitalization.
We
intend
to discontinue the use Peer Group 1 after this year's report on Form 10-K.
The
information shown is historical and is not necessarily indicative of future
performance. The ten companies which make up Peer Group 1 are as follows: Bill
Barrett Corp. (publicly traded since December 10, 2004), Cabot Oil & Gas
Corp., Cimarex Energy Co. (publicly traded since September 30, 2002), Comstock
Resources Inc., Denbury Resources Inc., Encore Acquisition Co. (publicly traded
since March 9, 2001), Energy Partners Ltd., Range Resources Corp., St. Mary
Land
& Exploration Co. and Whiting Petroleum Corp. (publicly traded since
November 20, 2003).
The
16
companies which make up Peer Group 2 (to be used going forward) are as follows:
Bill
Barrett Corp., Cabot Oil & Gas Corp., Cimarex Energy Co., Comstock Resources
Inc., Denbury Resources Inc., Encore Acquisition Co., Forest Oil Corp., Houston
Exploration Co., Petrohawk Energy Corp., Plains Exploration & Production
Co., Quicksilver Resources Inc., Range Resources Corp., St. Mary Land &
Exploration Co., Stone Energy Corp., Swift Energy Co., Whiting Petroleum
Corp.
24
|
Copyright
© 2007 Standard & Poor's, a division of The McGraw-Hill Companies,
Inc. All rights reserved.
|
|||||||
|
www.researchdatagroup.com/S&P.htm
|
|||||||
|
|
|
12/01
|
12/02
|
12/03
|
12/04
|
12/05
|
12/06
|
|
Berry
Petroleum Company
|
100.00
|
111.30
|
135.80
|
325.26
|
393.93
|
431.40
|
|
|
S
& P 500
|
100.00
|
77.90
|
100.24
|
111.15
|
116.61
|
135.03
|
|
|
Russell
2000
|
100.00
|
79.52
|
117.09
|
138.55
|
144.86
|
171.47
|
|
|
Peer
Group 1
|
100.00
|
125.10
|
172.17
|
267.33
|
393.25
|
402.45
|
|
|
Peer
Group 2
|
100.00
|
101.28
|
133.38
|
202.06
|
291.67
|
294.64
|
|
Item
6. Selected
Financial Data
The
following table sets forth certain financial information and is qualified in
its
entirety by reference to the historical financial statements and notes thereto
included in Item 8 Financial Statements and Supplementary Data. The statement
of
income and balance sheet data included in this table for each of the five years
in the period ended December 31, 2006 were derived from the audited financial
statements and the accompanying notes to those financial statements (in
thousands, except per share, per BOE and % data).
25
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
||||||||||||||||||||
|
Audited
Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
|
Statement
of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Sales of oil and gas | $ |
430,197
|
$ |
349,691
|
$ |
226,876
|
$ |
135,848
|
$ |
102,026
|
|||||||||||||||||||||
|
Sales
of electricity
|
|
|
52,932
|
|
|
55,230
|
|
|
47,644
|
|
|
44,200
|
|
|
27,691
|
|
|||||||||||||||
|
Operating
costs - oil and gas production
|
|
|
117,624
|
|
|
99,066
|
|
|
73,838
|
|
|
57,830
|
41,108
|
|
|||||||||||||||||
|
Operating
costs - electricity generation
|
|
|
48,281
|
|
|
55,086
|
|
|
46,191
|
|
|
42,351
|
|
|
26,747
|
|
|||||||||||||||
|
Production
taxes
|
14,674
|
11,506
|
6,431
|
3,097
|
2,907
|
||||||||||||||||||||||||||
|
General
and administrative expenses (G&A)
|
|
|
36,841
|
|
|
21,396
|
|
|
22,504
|
|
|
14,495
|
|
|
10,417
|
|
|||||||||||||||
|
Depreciation,
depletion & amortization (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Oil
and gas production
|
|
|
67,668
|
|
|
38,150
|
|
|
29,752
|
|
|
17,258
|
|
|
13,388
|
|
|||||||||||||||
|
Electricity
generation
|
|
|
3,343
|
|
|
3,260
|
|
|
3,490
|
|
|
3,256
|
|
|
3,064
|
|
|||||||||||||||
|
Net
income
|
|
|
107,943
|
|
|
112,356
|
|
|
69,187
|
|
|
32,363
|
|
|
29,210
|
|
|||||||||||||||
|
Basic
net income per share (1)
|
|
|
2.46
|
|
|
2.55
|
|
|
1.58
|
|
|
.74
|
|
|
.67
|
|
|||||||||||||||
|
Diluted
net income per share (1)
|
|
|
2.41
|
|
|
2.50
|
|
|
1.54
|
|
|
.73
|
|
|
.67
|
|
|||||||||||||||
|
Weighted
average number of shares outstanding (basic) (1)
|
|
|
43,948
|
|
|
44,082
|
|
|
43,788
|
|
|
43,544
|
|
|
43,482
|
|
|||||||||||||||
|
Weighted
average number of shares outstanding (diluted) (1)
|
|
|
44,774
|
|
|
44,980
|
|
|
44,940
|
|
|
44,062
|
|
|
43,804
|
|
|||||||||||||||
|
Balance
Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Working
capital
|
|
$
|
(100,594
|
)
|
$
|
(54,757
|
)
|
$
|
(3,840
|
)
|
$
|
(3,540
|
)
|
$
|
(2,892
|
)
|
|||||||||||||||
|
Total
assets
|
|
|
1,198,997
|
|
|
635,051
|
|
|
412,104
|
|
|
340,377
|
|
|
259,325
|
|
|||||||||||||||
|
Long-term
debt
|
|
|
390,000
|
|
|
75,000
|
|
|
28,000
|
|
|
50,000
|
|
|
15,000
|
|
|||||||||||||||
|
Shareholders'
equity
|
|
|
427,700
|
|
|
334,210
|
|
|
263,086
|
|
|
197,338
|
|
|
172,774
|
|
|||||||||||||||
|
Cash
dividends per share (1)
|
|
|
.30
|
.30
|
.26
|
.24
|
.20
|
|
|||||||||||||||||||||||
|
Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Cash
flow from operations
|
|
|
243,229
|
|
|
187,780
|
|
|
124,613
|
|
|
64,825
|
|
|
57,895
|
|
|||||||||||||||
|
Exploration
and development of oil and gas properties
|
|
|
265,110
|
|
|
118,718
|
|
|
71,556
|
|
|
41,061
|
|
|
30,163
|
|
|||||||||||||||
|
Property/facility
acquisitions
|
|
|
257,840
|
|
|
112,249
|
|
|
2,845
|
|
|
48,579
|
|
|
5,880
|
||||||||||||||||
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
21,306
|
11,762
|
669
|
494
|
469
|
|
|||||||||||||||||||||||
|
Unaudited
Operating Data
|
|
|
|||||||||||||||||||||||||||||
|
Oil
and gas producing operations (per BOE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Average
sales price before hedging
|
|
$
|
48.38
|
|
$
|
47.01
|
|
$
|
33.64
|
|
$
|
24.48
|
|
$
|
20.11
|
|
|||||||||||||||
|
Average
sales price after hedging
|
|
|
46.67
|
|
|
41.62
|
|
|
30.32
|
|
|
22.52
|
|
|
19.39
|
|
|||||||||||||||
|
Average
operating costs - oil and gas production
|
|
|
12.69
|
|
|
11.79
|
|
|
10.09
|
|
|
9.57
|
|
|
7.83
|
|
|||||||||||||||
|
Production
taxes
|
1.58
|
1.37
|
.86
|
.51
|
.55
|
||||||||||||||||||||||||||
|
G&A
|
|
|
3.98
|
|
|
2.55
|
|
|
2.99
|
|
|
2.40
|
|
|
1.98
|
|
|||||||||||||||
|
DD&A
- oil and gas production
|
|
|
7.30
|
|
|
4.54
|
|
|
3.96
|
|
|
2.86
|
|
|
2.55
|
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Production
(MBOE)
|
|
|
9,270
|
|
|
8,401
|
|
|
7,517
|
|
|
6,040
|
|
|
5,251
|
|
|||||||||||||||
|
Production
(MMWh)
|
|
|
757
|
|
|
741
|
|
|
776
|
|
|
767
|
|
|
748
|
|
|||||||||||||||
|
Proved
Reserves Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Total
BOE
|
|
|
150,262
|
|
|
126,285
|
|
|
109,836
|
|
|
109,920
|
|
|
101,719
|
|
|||||||||||||||
|
Standardized
measure (2)
|
|
$
|
1,182,268
|
|
$
|
1,251,380
|
|
$
|
686,748
|
|
$
|
528,220
|
|
$
|
449,857
|
|
|||||||||||||||
|
Year-end
average BOE price for PV10 purposes
|
|
|
41.23
|
|
|
48.21
|
|
|
29.87
|
|
|
25.89
|
|
|
24.91
|
|
|||||||||||||||
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
Return
on average shareholders' equity
|
|
|
28.33
|
%
|
|
37.63
|
%
|
|
31.06
|
%
|
|
17.50
|
%
|
|
17.90
|
%
|
|||||||||||||||
|
Return
on average capital employed
|
|
|
18.21
|
%
|
|
32.74
|
%
|
|
26.29
|
%
|
|
15.44
|
%
|
|
16.42
|
%
|
|||||||||||||||
(1)
All earnings per share and share amounts have been restated to give retroactive
effect to the two-for-one stock split that became effective on May 17,
2006.
(2)
See Supplemental Information About Oil & Gas Producing
Activities.
26
Item
7. Management's
Discussion and Analysis of Financial Condition and Results of
Operation
Overview.
Our
mission is to increase shareholder value through consistent growth in our
production and reserves, both through the drill bit and acquisitions. We strive
to operate our properties in an efficient manner to maximize the cash flow
and
earnings of our assets. The strategies to accomplish these goals
include:
| · |
Developing
our existing resource base
|
| · |
Acquiring
additional assets with significant growth
potential
|
| · |
Utilizing
joint ventures with respected partners to enter new
basins
|
| · |
Accumulating
significant acreage positions near our producing
operations
|
| · |
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
Notable
Items in 2006.
| · |
Achieved
record production which averaged 25,398 BOE/D, up 10% from
2005
|
| · |
Achieved
record cash from operating activities of $243 million, up 29% from
2005
|
| · |
Achieved
net income of $108 million, down 4% from
2005
|
| · |
Added
33.4 million BOE of proved reserves before production ending 2006
at 150.3
million BOE
|
| · |
Achieved
reserve replacement rate of 359%
|
| · |
Expended
$554 million of capital expenditures, including $286 million of
developmental capital expenditures
|
| · |
Acquired
operatorship and 50% working interest in 6,300 gross acres of natural
gas
assets in the Garden Gulch property in the Grand Valley field in
the
Piceance basin, Colorado, at an acquisition cost of
$159 million
|
| · |
Entered
into an agreement to jointly develop natural gas properties in the
North
Parachute Ranch property in the Grand Valley field in the Piceance
basin,
Colorado, to earn a 95% working interest in 4,300 gross acres near
our
Garden Gulch assets
|
| · |
Announced
development of our diatomite asset (heavy oil) with a 100 well drilling
program scheduled for 2007 in the Midway-Sunset field,
California
|
| · |
Discovered
light oil accumulations in the Green River and Wasatch formations
at Lake
Canyon, Uinta basin, Utah
|
| · |
Added
financial capacity by increasing our senior unsecured revolving credit
facility to $750 million with an initial borrowing base of
$500 million
|
| · |
Issued
$200 million of ten year 8.25% senior subordinated notes in October
2006
|
| · |
Completed
two-for-one split of Class A Common Stock and Class B Stock
|
| · |
Increased
our regular quarterly dividend by 15% to $.075 per share ($.30 annually)
and declared a special dividend of $.02 per
share
|
Notable
Items and Expectations for 2007.
| · |
Expecting
2007 developmental capital expenditures to approximate $227 million
to
$267 million
|
| · |
Targeting
a 20% to 25% increase in 2007 year end proved reserves, or 175 to
185
MMBOE
|
| · |
Beginning
major development of our Piceance assets with over 55 to 65 wells
planned
|
| · |
Targeting
net average production of between 27,000 and 28,000
BOE/D
|
| · |
Entered
into a long-term crude oil sales contract for our Uinta basin, Utah
production
|
| · |
Potential
divestiture of non-strategic assets to focus on our large resource
development opportunities
|
Overview
of the Fourth Quarter of 2006.
We
achieved record production of 26,887 BOE/D even though we reduced production
in
the Uinta basin (estimated impact to the fourth quarter of 2006 was
approximately 2,000 Bbl/D) due to an unscheduled refinery shutdown. The refinery
resumed operations in mid-January 2007. Our price differential for our black
wax
crude oil in the Uinta basin widened causing lower realizations and negatively
impacted our earnings for the quarter. Improving the demand for this crude
has
been a major challenge. This situation, and generally weaker oil and gas prices,
lowered our realized prices by 11% compared to the third quarter of
2006.
View
to 2007. Our
challenge for 2007 is to manage our business in a rapidly changing price and
operating environment while adding significant reserves through the drill bit.
We have an extensive inventory of development drilling in several basins, and
expect our program to be the most influenced by production and reserve growth
in
the Piceance basin. We intend our capital program, excluding acquisitions,
to
closely reflect our cash flow from operations. Additional funds may be provided
by the divestiture of several non-strategic assets, including our Montalvo
properties, Bakken acreage and others. We have six asset teams, three in
California and three in the Rocky Mountain/Mid-Continent region, and each team
has specific targets on production, reserve growth, capital expenditures and
operating costs. We believe managing our assets in this manner will maximize
operational efficiencies and add the most value to our shareholders. We will
manage our balance sheet prudently, and while we are focused on the continuing
development of our existing assets, we will continue to evaluate acquisition
opportunities that fit our growth strategy.
27
View
to the First Quarter of 2007. Crude
oil
prices (WTI) were volatile in the first quarter ranging from $50.48 per barrel
WTI to $61.39 per barrel and we expect oil and gas prices to remain volatile
in
2007.
On
February 27, 2007 we entered into a long-term (six year) crude oil sales
contract for our Uinta basin production. This contract will allow us to improve
our margins on these barrels beginning on July 1, 2007 and provides us assurance
of deliverability and return on our investment. We are accelerating our
investment in our Poso Creek, California properties due to its excellent
response to our 2006 development activity. Our total net production volumes
in
the first quarter are expected to average between 24,000 and 26,000
BOE/D.
Piceance
Basin - Our New Core Area.
In
2006, we made two separate significant investments in the gas rich Piceance
basin in Colorado, targeting the Williams Fork section of the Mesaverde
formation. We spent $312 million (balance of $54 million due in 2007) to acquire
a high working interest in several prime blocks of acreage located in the Grand
Valley field. Most of the acreage was undeveloped and we added only 4.3 MMBOE
in
proved reserves from these acquisitions. We believe we have accumulated a very
sizable resource base which will allow us to add significant proved reserves
over the next five years. We believe we have over 1,000 drilling locations on
this acreage. We are anticipating initial gross production ranging from 1.3
to
2.0 MMcf per well with the ultimate risked gross recovery of approximately
1.5
Bcf per well. Well costs are expected to be in the $1.8 million to $2.5 million
range per well and we are targeting average depths of between 10,000 feet to
12,000 feet. We anticipate running four rigs in 2007 to develop this
asset.
Capital
expenditures.
Our
capital expenditures for 2006 totaled $553 million consisting of $258 million
for acquisitions, $265 million for exploration and development, $21 million
for
drilling rigs and other assets and $9 million of capitalized interest. We funded
these items from $243 million of operating cash flow and $310 million from
additional borrowings. This compares to our total capital expenditures in 2005
of $243 million, which consisted of $112 million of acquisitions, $119 million
in exploration and development and $12 million in drilling rigs and other
assets.
Excluding
the acquisition price of new properties, in 2007 we have a developmental capital
program of approximately $267 million and we will make a final payment of $54
million associated with our Piceance joint venture. We are proceeding with
this
program, but may revise our plans due to lower commodity price expectations,
to
the timing of crude deliveries out of the Uinta basin, to equipment
availability, to permitting or other factors.
Our
2007
capital program allows us to continue high activity levels and as a result,
we
are targeting 2007 production to average between 27,000 BOE/D to 28,000 BOE/D.
In 2007, we expect production to be approximately 62% heavy oil, 11% light
oil
and 27% natural gas and anticipate funding our development capital program
primarily from internally generated cash flow. We have currently secured the
necessary equipment and are meeting permit requirements to achieve the 2007
program.
Development,
Exploitation and Exploration Activity.
We
drilled 568 gross (382 net) wells during 2006, realizing a gross success rate
of
98 percent. Excluding any future acquisitions, our targeted 2007 developmental
capital budget is $267 million. As of December 31, 2006, we have four rigs
drilling on our properties under long-term contracts and have several more
rigs
scheduled to begin in early 2007.
Drilling
Activity. The
following table sets forth certain information regarding drilling activities
for
the year ended December 31, 2006:
|
Gross
Wells
|
Net
Wells
|
||||||||||
|
SMWSS
|
50
|
50
|
|||||||||
|
NMWSS
|
|
81
|
80
|
|
|||||||
|
Socal
(1)
|
|
38
|
38
|
|
|||||||
|
Piceance
|
68
|
11
|
|||||||||
|
Uinta
(2)
|
|
108
|
106
|
|
|||||||
|
DJ
(3)
|
223
|
97
|
|||||||||
|
Totals
|
|
568
|
382
|
|
|||||||
|
(1)
|
Includes
1 gross well (1 net well) that was a dry hole at North
Midway-Sunset.
|
|
(2)
|
Includes
2 gross wells (2 net wells) that were dry holes at Coyote Flats.
|
|
(3)
|
Includes
5 gross wells (2.4 net wells) that were dry holes in Tri-State and
4 gross
wells (.3 net well) that were dry holes in
Bakken.
|
28
Net
Oil and Gas Producing Properties at December 31, 2006.
|
Name,
State
|
%
Average Working Interest
|
Total
Net Acres
|
Proved
Reserves (BOE) in thousands
|
Proved
Developed Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Proved
Undeveloped Reserves (BOE) in thousands
|
%
of Total Proved Reserves
|
Average
Depth of Producing Reservoir (feet)
|
|||||||
| SMWSS, CA |
99
|
2,081
|
50,124
|
43,668
|
29.1%
|
6,455
|
4.3%
|
1,700
|
|||||||
|
Uinta,
UT
|
100
|
13,800
|
21,093
|
11,922
|
7.9
|
9,171
|
6.1
|
6,000
|
|||||||
|
Socal,
CA
|
100
|
3,580
|
33,441
|
17,972
|
12.0
|
15,469
|
10.3
|
1,200
to 11,500
|
|||||||
|
DJ,
CO/KS/NE
|
47
|
67,344
|
18,620
|
10,374
|
6.9
|
8,246
|
5.5
|
2,600
|
|||||||
|
NMWSS,
CA
|
100
|
1,898
|
16,343
|
16,343
|
10.9
|
-
|
-
|
1,500
|
|||||||
| Piceance, CO |
5
to 95
|
3,160
|
10,641
|
1,991
|
1.3
|
8,650
|
5.7
|
9,300
|
|||||||
| Totals |
150,262
|
102,270
|
68.1%
|
47,991
|
31.9%
|
||||||||||
Our
asset
base has changed considerably since early 2003. As of December 31, 2006, we
had
150 MMBOE of proved reserves and have abundant drilling inventories at several
of our core areas. Generally, our California assets are mature (diatomite and
Poso Creek are the exception) and generate more cash flow from operations than
is required to reinvest in these assets. We have high capital needs in the
Piceance, Uinta and the DJ basins, where we have large undeveloped resources.
We
anticipate spending most of our operating cash flow over the next several years
in converting the recoverable hydrocarbons to production, cash flow and
earnings.
California
California’s
three asset teams are South Midway-Sunset (SMWSS), North Midway-Sunset (NMWSS)
(which includes diatomite) and Southern California (Socal) (which include Poso
Creek, Ethel D, Placerita and Montalvo). Approximately $91 million will be
invested in California projects in 2007 with $9 million, $55 million and $27
million allocated for the SMWSS, NMWSS and Socal assets, respectively.
SMWSS,
San Joaquin Valley Basin (SJVB)
- We own
and operate working interests in 38 properties, including 23 owned in fee,
in
the Midway-Sunset field. Production from this field relies on thermal EOR
methods, primarily cyclic steaming.
2006
-
Development activities were focused on horizontal drilling.
2007
-
Capital is focused on further horizontal infill well drilling, targeting steam
injection wells and improved subsurface well monitoring.
Production
averaged approximately 10,000 Bbl/D in 2006. This
is
our most mature thermally enhanced asset and we are developing and testing
new
concepts to place heat into the remaining oil column to maximize recovery and
value. We are also improving our steam monitoring capabilities to verify
efficient steam placement.
NMWSS,
SJVB -
On
November 1, 2006, we announced our plans to commence
development of our Midway-Sunset diatomite oil project in California based
on
the performance of a two-year pilot program. We believe the project will be
a
significant asset for our California operations and for Berry. The project
will
add material production and reserves as a part of our growth strategy. Over
the
next four years, we intend to invest an additional $210 million in capital
to
drill 520 shallow development wells in the fairway of the asset and add steam
generation and processing facilities. We expect this development will increase
production by up to 7,000 Bbl/D by 2010 (in 2006 the project averaged 325
Bbl/D). As we develop the fairway, we will also appraise the potential of
recovering additional reserves in the outer portions of our acreage in
subsequent development phases. We
believe that the fairway contains 55% of the oil resource and has reservoir
properties similar to our initial pilot. This will enable a repeatable
development like those used in our other California assets.
2006
-
Completed commercial testing.
2007
-
Capital is focused on drilling the diatomite first phase development wells
and
adding steam generation equipment and various facilities. We
will
also be initiating steam drive pilots in one of our largest remaining
hydrocarbon resources in the Tulare sands on our Main Camp property in the
Midway-Sunset field.
During
2006 we redeveloped our Pan property on the non-diatomite section of NMWSS
by
drilling over 40 infill locations and adding steam generation capacity and
associated production facilities. Production responded by increasing from
approximately 100 Bbl/D to a peak of over 800 Bbl/D. Further infill drilling
locations are currently being evaluated.
29
Socal,
SJVB and Los Angeles Basin
- We
acquired the Poso Creek properties in early 2003 and have proceeded with a
successful thermal EOR redevelopment. At acquisition the property was producing
less than 50 BOE/D and we averaged 940 Bbl/D in 2006.
2006
-
Activity
was directed at delineating the extent of the reservoir, infill drilling and
expansion of the steam drive pilot.
Production
from this property increased as a result of thermal redevelopment steadily
throughout the year from approximately 500 Bbl/D to over 1,500 Bbl/D at December
31, 2006. Additional steam generation capacity was added during the first
half of the year along with 15 infill/delineation wells and late in the fourth
quarter we began drilling 20 additional infill wells.
2007
-
Capital is directed at drilling 34 infill producer locations, adding additional
steam generation capacity and expanding the steam drive area.
In
the
Placerita field in the Los Angeles basin, we own and operate working interests
in 13 properties, including 9 leases and 4 fee properties. Production relies
on
thermal recovery methods, primarily steam flooding.
2006
-
We
reassessed our existing steam drive and discovered additional remaining reserves
within the existing mature steam drive area. Several infill wells were drilled
and confirmed our assessment. Further reservoir analysis/simulation is in
progress to determine the optimum recovery method.
2007
-
Capital is directed at steam flood modifications and facility
improvements.
We
will
also be initiating steam drive pilots in the other largest remaining hydrocarbon
resources in the Monarch sands at Ethel D property in the Midway-Sunset field.
We are pursuing the divestment of our Montalvo properties in Ventura County,
California and have no capital allocated to the asset, which produced over
700
Bbl/D in 2006.
Rocky
Mountain/Mid-Continent
We
reorganized the structure of the Rocky Mountain/Mid-Continent region into three
regional asset teams in late 2006 to strengthen our technical and business
focus
in the region. The three asset teams are centered around the Piceance basin
Mesaverde gas development, the Uinta basin Green River and Wasatch oil
exploitation and the DJ basin Niobrara gas projects. Approximately $176 million
will be invested in Rocky Mountain region projects in 2007 with $118 million,
$37 million and $21 million earmarked for the Piceance, Uinta and DJ basins,
respectively.
Piceance
Basin, Colorado -
In
February 2006, we acquired a 50% working interest in 6,300 gross acres in the
Garden Gulch property in the Grand Valley natural gas field in the Piceance
basin of western Colorado for approximately $159 million. Then in June 2006,
we
entered into an agreement with an industry partner to jointly develop (our
commitment under the agreement is approximately $153 million) the North
Parachute Ranch property in the Grand Valley field in the Piceance immediately
east of the Garden Gulch property. In accordance with the agreement we acquired
a 5% non-operating working interest on 6,300 gross acres and a net operating
working interest of 95% in 4,300 gross acres. We have financial commitments
under both the 5% and the 95% working interests. See Note 5 to the financial
statements. This agreement for the North Parachute Ranch property expands upon
our reserves and drilling opportunities with an additional 400 locations.
Production from these wells is expected to be similar to Garden Gulch wells,
with initial gross production rates ranging from 1.3 to 2.0 MMcf/D.
2006
-
We
drilled
17 gross wells, 15 on the Garden Gulch property and two on the North Parachute
Ranch property. Our industry partner drilled 53 gross wells upon which we earned
5% non-operating working interest. Our net production in 2006 averaged 4,300
Mcf/D. We have contracts for four rigs as of December 31, 2006 to proceed with
our development plan. We have made significant progress in gearing up for
extensive development of this asset, including additional outlets for gas sales.
The
Garden Gulch acreage now has 13 wells producing and initial production from
the
North Parachute Ranch property began late in the fourth quarter.
2007
-
Capital is directed at drilling 55 to 65 Mesaverde wells along with associated
land, facility and water disposal projects.
Uinta
Basin, Utah - The
Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of
federal, tribal and private leases.
2006
-
We
continued
the development of the Green River formation, including testing 20-acre infill
wells
to
assist full development, including a 20-acre spacing pilot. During the year
infield gas gathering infrastructure was upgraded with additional compression
and a gas processing facility to handle increasing volumes of natural gas.
In
the fourth quarter of 2006, an Environmental Assessment (EA) was completed
in
the Ashley National Forest, clearing the way for 14 drillsites and up to 29
wells. We were able to drill and complete
one well before winter access restrictions went into effect. In 2006, we drilled
101 total net wells in Brundage with 100% success rate. Daily net production
averaged approximately 5,800 BOE/D.
30
2007
-
Capital is directed at the Ashley Forest, additional 20-acre infills and
high-graded locations across the field.
The
majority of this development program is targeted for the second half of the
year
due to winter wildlife stipulations.
In
the
Lake Canyon prospect, we hold, with an industry partner, a 169,000 gross acre
block which is located immediately west of our Brundage Canyon producing
properties. We will drill and operate the shallow wells which target light
oil
and natural gas in the Green River formation and retain up to a 75% working
interest. Our partner will drill and operate deep wells which target
hydrocarbons in the Mesaverde and Wasatch formations. We will hold up to a
25%
working interest in these deep wells. The Ute Tribe has the option to
participate in each well and obtain a 25% working interest which would reduce
our and our partner’s participation.
2006
-
In
January 2006, we announced commercial success from our first two wells on
this acreage, from the same Green River formation that is productive immediately
east (approximately three miles) in our Brundage Canyon field. Performance
from
these discovery wells suggests that expected reserves per well are on par with
the Brundage Canyon field (approximately 80,000 BOE gross) that is currently
being developed on 40-acre spacing. Production from these two shallow Green
River wells continues to be favorable. We have a 56.25% working interest in
these two wells, as the Ute Tribe elected to participate. In
the
third quarter, with Tribal participation, we drilled four additional shallow
Green River wells that are all productive.
In
the
second quarter of 2006, our industry partner initiated production from a deep
well completed in the Wasatch formation. Due
to
the success of this Wasatch discovery well, our
industry partner drilled two additional Wasatch wells in the fourth quarter
of
2006. These wells are currently waiting on completion. We
have
an 18.75% working interest in these two wells, as the Ute Tribe elected to
participate in one of the two wells. Our
daily
net production from the Lake Canyon wells averaged approximately 87
BOE/D.
2007
- We
are in the permitting process for an additional 16 shallow Green River wells
which are intended to continue exploratory and development drilling on the
eastern portion of our Lake Canyon acreage. Our working interest in these wells
will be either 75% or 56.25% depending on Tribal participation. Our industry
partner is also permitting additional deep wells for their 2007 drilling
program. Our 2007 capital is directed at a methodical appraisal covering a
sizeable portion of this acreage block, targeting Green River and Wasatch
reservoirs.
In
December 2004, we entered into a development agreement with an industry partner
to develop their Coyote Flats prospect. The property is located approximately
45
miles southwest of our Brundage Canyon property.
2006
- We
have
three successful appraisal Ferron gas wells on the east side of the Scofield
reservoir which have each tested flow rates exceeding 1,000 Mcf/D. We
renegotiated the farm out obligation terms with our industry partner to earn
a
50% working
interest in the approximate 69,250 gross (33,500 net) acres
in the
project without drilling the remaining Emery coalbed methane wells. Our
earning obligation was satisfied by installing a gathering system, compression
and 13 mile gas pipeline to connect the three previously announced Ferron
gas discoveries to sales pipelines. Construction is complete and first
sales were established in December 2006. Two of the three wells are currently
on
production with the third being temporarily shut-in pending a water disposal
solution. Our daily net production is approximately 780 Mcf/D.
2007
- No
capital has been directed at this project, pending results from production
tests
on the three discovery wells.
DJ
Basin (includes eastern Colorado producing assets) -
In 2005,
we made three acquisitions for approximately $111 million establishing a core
area in the Tri-State region (Eastern Colorado, western Kansas and southwestern
Nebraska ) totaling approximately 100,000 net producing acres and 315,000 net
total acres. Our primary acquisition was the Niobrara gas producing assets
in
Yuma County in northeastern Colorado in which we have a working interest of
approximately 52%. Our other two acquisitions in the region consisted of
undeveloped prospective acreage where our working interests range from 40%
to
50%.
2006
-
We
drilled
205 wells to add production from both proved undeveloped and probable reserves
and five exploratory wells and our
net
production averaged 16,100 Mcf/D.
We
participated in five 3-D seismic surveys covering in excess of 130 square
miles. In
the
third quarter, we installed additional compression, gas gathering pipelines
and
high pressure pipelines that expand the capacity and connections to new markets
on the Cheyenne Plains Lateral system. In our Kansas Tri-State prospect, we
have
drilled and completed a successful exploratory well that is an extension to
our
Prairie Star production in Cheyenne County, Kansas and have drilled two dry
holes in the year.
2007
-
Capital is directed at development drilling for Yuma County reserve growth,
additional 3-D seismic in Colorado and Kansas and additional exploration in
Kansas.
Obstacles
and Risks to Accomplishment of Strategies and Goals.
See Item
1A Risk Factors for a detailed discussion of factors that affect our business,
financial condition and results of operations.
31
 |
Results
of Operations. Approximately
88% of our revenues are generated through the sale of oil and natural
gas
production under either negotiated contracts or spot gas purchase
contracts at market prices. The remaining 12% of our revenues are
primarily derived from electricity sales from cogeneration facilities
which supply approximately 40% of our steam requirement for use in
our
California thermal heavy oil operations. We have invested in these
facilities for the purpose of lowering our steam costs which are
significant in the production of heavy crude oil.
Revenues.
Sales of oil and gas were up 23% in 2006 compared to 2005 and up
89% from
2004. This significant improvement was due to increases in both oil
and
gas prices and production levels. Improvements in production volume
are
due to acquisitions and sizable capital investments. Improvement
in prices
during 2006 were due to a tighter supply and demand balance and the
nervousness of the market about possible supply disruptions. Oil
and
natural gas prices contributed roughly half of the revenue increase
and
the increase in production volumes contributed the other half.
Approximately 77% of our oil and gas sales volumes in 2006 were crude
oil,
with 82% of the crude oil being heavy oil produced in California
which was
sold under contracts based on the higher of WTI minus a fixed differential
or the average posted price plus a premium. Our oil contracts allowed
us
to improve our California revenues over the posted price by approximately
$21 million, $41 million and $13 million in 2006, 2005 and 2004,
respectively.
|
The
following companywide results are in millions (except per share data) for the
years ended December 31:
|
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Sales
of oil
|
$
|
360
|
$
|
289
|
$
|
210
|
||||
|
Sales
of gas
|
70
|
61
|
17
|
|||||||
|
Total
sales of oil and gas
|
$
|
430
|
$
|
350
|
$
|
227
|
||||
|
Sales
of electricity
|
53
|
|
55
|
48
|
|
|||||
|
Interest
and other income, net
|
3
|
|
2
|
-
|
|
|||||
|
Total
revenues and other income
|
$
|
486
|
|
$
|
407
|
$
|
275
|
|
||
|
Net
income
|
$
|
108
|
|
$
|
112
|
$
|
69
|
|
||
|
Earnings
per share (diluted)
|
$
|
2.41
|
$
|
2.50
|
$
|
1.54
|
||||
The
following companywide results are in millions (except per share data) for the
three months ended:
|
|
|
December
31, 2006
|
December
31, 2005
|
September
30, 2006
|
|||||||
|
Sales
of oil
|
$
|
84
|
$
|
75
|
$
|
98
|
|||||
|
Sales
of gas
|
18
|
23
|
18
|
||||||||
|
Total
sales of oil and gas
|
$
|
102
|
$
|
98
|
$
|
116
|
|||||
|
Sales
of electricity
|
13
|
|
18
|
12
|
|||||||
|
Interest
and other income, net
|
1
|
|
1
|
1
|
|||||||
|
Total
revenues and other income
|
$
|
116
|
|
$
|
117
|
$
|
129
|
||||
|
Net
income
|
$
|
19
|
|
$
|
30
|
$
|
31
|
||||
|
Net
income per share (diluted)
|
$
|
.43
|
$
|
.69
|
$
|
.70
|
|||||
32
 |
 |
Oil
Contracts.
See Item
1 Business.
Hedging.
See Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to
the
financial statements.
Operating
data.
The
following table is for the years ended December 31:
|
2006
|
%
|
2005
|
%
|
2004
|
%
|
||||||||||||||||
| Oil and Gas | |||||||||||||||||||||
| Heavy Oil Production (Bbl/D) |
15,972
|
63
|
16,063
|
70
|
15,901
|
77
|
|||||||||||||||
|
Light
Oil Production (Bbl/D)
|
3,707
|
15
|
3,336
|
14
|
3,345
|
16
|
|||||||||||||||
|
Total
Oil Production (Bbl/D)
|
|
|
19,679
|
78
|
|
19,399
|
84
|
|
19,246
|
93
|
|||||||||||
|
Natural
Gas Production (Mcf/D)
|
|
|
34,317
|
22
|
|
21,696
|
16
|
|
7,752
|
7
|
|||||||||||
|
Total
(BOE/D)
|
|
|
25,398
|
100
|
|
23,015
|
100
|
|
20,537
|
100
|
|||||||||||
|
Percentage
increase from prior year
|
10%
|
12%
|
24%
|
||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Average
sales price before hedging
|
|
$
|
48.38
|
|
$
|
47.01
|
|
$
|
33.64
|
|
|||||||||||
|
Average
sales price after hedging
|
|
|
46.67
|
|
|
41.62
|
|
|
30.32
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Oil,
per Bbl:
|
|||||||||||||||||||||
|
Average
WTI price
|
$
|
66.25
|
$
|
56.70
|
$
|
39.21
|
|||||||||||||||
|
Price
sensitive royalties
|
(5.13
|
)
|
(4.42
|
)
|
(2.78
|
)
|
|||||||||||||||
|
Gravity
differential
|
(8.20
|
)
|
(5.22
|
)
|
(4.93
|
)
|
|||||||||||||||
|
Crude
oil hedges
|
(2.37
|
)
|
(6.21
|
)
|
(2.93
|
)
|
|||||||||||||||
|
Average
oil sales price after hedging
|
$
|
50.55
|
$
|
40.85
|
$
|
28.57
|
|||||||||||||||
|
Gas,
per MMBtu:
|
|||||||||||||||||||||
|
Average
Henry Hub price
|
$
|
6.97
|
$
|
8.05
|
$
|
6.13
|
|||||||||||||||
|
Natural
gas hedges
|
.10
|
(.11
|
)
|
(.01
|
)
|
||||||||||||||||
|
Location
and quality differentials
|
(1.18
|
)
|
(1.45
|
)
|
(.63
|
)
|
|||||||||||||||
|
Average
gas sales price after hedging
|
$
|
5.89
|
$
|
6.49
|
$
|
5.49
|
33
The
following table is for the three months ended:
|
December
31, 2006
|
%
|
December
31, 2005
|
%
|
September
30, 2006
|
%
|
|||||
|
Oil
and Gas
|
||||||||||
|
Heavy
Oil Production (Bbl/D)
|
16,833
|
63
|
15,997
|
68
|
16,076
|
61
|
||||
|
Light
Oil Production (Bbl/D)
|
3,363
|
13
|
3,438
|
14
|
4,118
|
16
|
||||
|
Total
Oil Production (Bbl/D)
|
|
20,196
|
76
|
19,435
|
82
|
20,194
|
77
|
|||
|
Natural
Gas Production (Mcf/D)
|
|
40,157
|
24
|
25,428
|
18
|
37,374
|
23
|
|||
|
Total
(BOE/D)
|
|
|
26,889
|
100
|
|
23,673
|
100
|
|
26,423
|
100
|
|
|
|
|
|
|
|
|
|
|||
|
Per
BOE:
|
|
|
|
|
|
|
|
|||
|
Average
sales price before hedging
|
|
$
|
41.53
|
$
|
51.71
|
$
|
50.33
|
|||
|
Average
sales price after hedging
|
|
|
42.00
|
|
44.90
|
|
47.28
|
|||
|
|
|
|
|
|
||||||
|
Oil,
per Bbl:
|
||||||||||
|
Average
WTI price
|
$
|
60.17
|
$
|
60.05
|
$
|
70.54
|
||||
|
Price
sensitive royalties
|
(4.28
|
)
|
(5.02
|
)
|
(5.21)
|
|||||
|
Quality
differential
|
(9.06
|
)
|
(5.39
|
)
|
(8.76)
|
|||||
|
Crude
oil hedges
|
(.01
|
)
|
(7.54
|
)
|
(3.99)
|
|||||
|
Average
oil sales price after hedging
|
$
|
46.82
|
$
|
42.10
|
$
|
52.58
|
||||
|
Gas,
per MMBtu:
|
||||||||||
|
Average
Henry Hub price
|
$
|
7.24
|
$
|
12.48
|
$
|
6.18
|
||||
|
Natural
gas hedges
|
.33
|
(.41
|
)
|
(.02)
|
||||||
|
Location
and quality differentials
|
(2.68
|
)
|
(3.46
|
)
|
(1.32)
|
|||||
|
Average
gas sales price after hedging
|
$
|
4.89
|
$
|
8.61
|
$
|
4.84
|
Electricity. We
consume natural gas as fuel to operate our three cogeneration facilities which
are intended to provide an efficient and secure long-term supply of steam
necessary for the cost-effective production of heavy oil. We sell our
electricity to utilities under standard offer contracts, which are based on
"avoided cost" or SRAC pricing approved by the CPUC and under which our revenues
are currently linked to the cost of natural gas. Natural gas index prices are
the primary determinant of our electricity sales price based on the current
pricing formula under these contracts. The correlation between electricity
sales
and natural gas prices allows us to manage our cost of producing steam more
effectively. Revenue and operating costs in the year ended 2006 were down from
the year ended 2005 due to 7% lower electricity prices and 18% lower natural
gas
prices, respectively. We purchased approximately 38 MMBtu/D as fuel for use
in
our cogeneration facilities in the year ended December 31, 2006. The
following table is for the years ended December 31:
|
2006
|
2005
|
2004
|
|||||||||||||||||||
|
Electricity
|
|||||||||||||||||||||
|
Revenues
(in millions)
|
$
|
52.9
|
$
|
55.2
|
$
|
47.6
|
|||||||||||||||
|
Operating
costs (in millions)
|
$
|
48.3
|
$
|
55.1
|
$
|
46.2
|
|||||||||||||||
|
Decrease
to total oil and gas operating expenses-per barrel
|
$
|
.50
|
$
|
.02
|
$
|
.19
|
|||||||||||||||
|
Electric
power produced - MWh/D
|
|
|
2,074
|
|
|
2,030
|
|
|
2,121
|
|
|||||||||||
|
Electric
power sold - MWh/D
|
|
|
1,867
|
|
|
1,834
|
|
|
1,915
|
|
|||||||||||
|
Average
sales price/MWh (no hedging was in place)
|
|
$
|
77.13
|
|
$
|
82.73
|
|
$
|
70.24
|
|
|||||||||||
|
Fuel
gas cost/MMBtu (after hedging and excluding
transportation)
|
|
$
|
5.99
|
|
$
|
7.30
|
|
$
|
5.46
|
|
34
The
following table is for the three months ended:
|
December
31, 2006
|
December
31, 2005
|
September
30, 2006
|
||||||||
|
Electricity
|
||||||||||
|
Revenues
(in millions)
|
$
|
13.5
|
$
|
18.3
|
$
|
12.6
|
||||
|
Operating
costs (in millions)
|
$
|
12.1
|
$
|
18.5
|
$
|
11.2
|
||||
|
Electric
power produced - MWh/D
|
|
|
2,093
|
|
|
2,082
|
|
|
2,100
|
|
|
Electric
power sold - MWh/D
|
|
|
1,861
|
|
|
1,886
|
|
|
1,895
|
|
|
Average
sales price/MWh
|
|
$
|
75.05
|
|
$
|
101.73
|
|
$
|
79.42
|
|
|
Fuel
gas cost/MMBtu (excluding transportation)
|
|
$
|
5.63
|
|
$
|
10.07
|
|
$
|
5.69
|
|
Royalties.
A
price-sensitive royalty burdens a portion of our Midway-Sunset California
property which produces approximately 3,044 BOE/D. This royalty is 75% of the
amount of the heavy oil posted price above a base price which was $15.48 in
2006. This base price escalates at 2% annually, thus the threshold price is
$15.79 per barrel in 2007. Amounts paid were $36 million, $29 million
and $19.3 million in the years ended December 31, 2006, 2005 and 2004,
respectively. Accounts payable associated with this royalty at year end 2006
was
$36 million. Because our interest in the revenue varies according to crude
prices, the continuing development on this property will depend on its future
profitability.
A
second
price sensitive royalty burdened approximately 500 BOE/D at our Placerita field
in California. This royalty is calculated when the sales price exceeds $26
per
barrel up to a maximum. The royalty was $.5 million, $2.8 million and
$1.4 million in the years ended December 31, 2006, 2005 and 2004,
respectively. The maximum amount of the royalty over its life is
$5 million, which was accrued from 2003 through the first quarter of 2006
and is now terminated.
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
We
believe that the most informative way to analyze changes in recurring operating
expenses from one period to another is on a per unit-of-production, or BOE,
basis. The following table presents information about our operating expenses
for
each of the years ended December 31:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||||||||||||||||||||||
|
|
|
2006
|
|
2005
|
|
Change
|
|
2006
|
|
2005
|
|
Change
|
|
||||||||||||||||||||||||||
| Operating costs - oil and gas production | $ |
12.69
|
$ |
11.79
|
8
|
% | $ |
117,624
|
$ |
99,066
|
19
|
% | |||||||||||||||||||||||||||
|
Production
taxes
|
1.58
|
1.37
|
15
|
%
|
14,674
|
11,506
|
28
|
%
|
|||||||||||||||||||||||||||||||
|
DD&A
- oil and gas production
|
|
|
7.30
|
|
|
4.54
|
|
|
61
|
%
|
|
67,668
|
|
|
38,150
|
|
|
77
|
%
|
||||||||||||||||||||
|
G&A
|
|
|
3.98
|
|
|
2.55
|
|
|
56
|
%
|
|
36,841
|
|
|
21,396
|
|
|
72
|
%
|
||||||||||||||||||||
|
Interest
expense
|
|
|
1.05
|
|
|
.72
|
|
|
46
|
%
|
|
10,247
|
|
|
6,048
|
|
|
69
|
%
|
||||||||||||||||||||
|
Total
|
|
$
|
26.60
|
|
$
|
20.97
|
|
|
27
|
%
|
$
|
247,054
|
|
$
|
176,166
|
|
|
40
|
%
|
||||||||||||||||||||
Our
total
operating costs, production taxes, G&A and interest expenses for 2006,
stated on a unit-of-production basis, increased 27% over 2005. The changes
were
primarily related to the following items:
| · |
Operating
costs: Operating costs in 2006 were 8% higher than 2005 due to an
increase
in well servicing activities and higher cost of goods and services
in
general. We installed additional steam generators in California related
to
various thermally enhanced oil projects and as a result of the increased
steam injection, our crude oil production on these properties has
continued to increase. The cost of our steaming operations on our
heavy
oil properties in California varies depending on the cost of natural
gas
used as fuel and the volume of steam injected. The following table
presents steam information:
|
|
|
||||
|
2006
|
2005
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
81,246
|
70,032
|
16%
|
|
|
Fuel
gas cost/MMBtu
|
$
5.99
|
$
7.30
|
(18%)
|
|
35
As
we
remain in a strong commodity price environment, we anticipate that cost
pressures within our industry may continue due to greater field activity and
rising service costs in general. Based on current plans, we are targeting
average steam injection in 2007 of approximately 90,000 to 95,000 BSPD. Natural
gas prices impact our cost structure in California by approximately $1.60 per
California BOE for each $1.00 change in natural gas price.
| · |
Production
taxes: Our production taxes have increased over the last year as
the value
of our oil and natural gas has increased. Severance taxes, which
are
prevalent in Utah and Colorado, are directly related to the cost
of the
field sales price of the commodity. In California, our production
is
burdened with ad valorem taxes on our total proved reserves. During
2006
our production taxes increased as a result of higher assessed values
on
our properties, increased production and higher investment in mineral
interests. We expect production taxes to track the commodity price
generally.
|
| · |
Depreciation,
depletion and amortization: DD&A increased per BOE in 2006 due to a
large increase in capital spending over the last two years and
particularly more extensive development in fields with higher drilling
costs. Higher leasehold acquisition costs in 2003 through 2006 are
expected to increase our DD&A expense over the life of these assets as
development increases. Our capital program is experiencing cost pressures
in our labor and for goods and services commensurate with other energy
developers. As these costs increase, our DD&A rates per BOE will also
increase.
|
| · |
General
and administrative: Approximately two-thirds of our G&A is
compensation or compensation related costs. Our employee headcount
increased 16% as we added an important new core asset into our portfolio
and as we are strengthening our talent base. We also re-examined
our
compensation structure and made necessary changes to attract and
retain
the talent needed to achieve our growth goals. We are experiencing
higher
employee turnover rates as the demand for experienced personnel in
the
energy industry is very high. Other items increasing our G&A in 2006
were contributions to fund the opposition of Proposition 87 in California,
increased travel and consulting costs and a generally higher level
of
activity.
|
| · |
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was $406 million
at December 31, 2006 compared to $87 million at December 31, 2005.
Average borrowings in 2006 increased as a result of our Piceance
basin
acquisitions during 2006 and capital expenditure program. A certain
portion of our interest cost related to our Piceance basin acquisition
and
joint venture has been capitalized into the basis of the assets,
and we
anticipate a portion will continue to be capitalized during 2006
and 2007
until our probable reserves have been recategorized to proved reserves.
For the year ended December 31, 2006, $9.3 million has been capitalized
and we expect to capitalize approximately $20 million of interest
cost
during the full year of 2007.
|
The
following table presents information about our operating expenses for the three
months ended:
|
Amount
per BOE
|
Amount
(in thousands)
|
||||||||||||||||||
|
|
|
December
31, 2006
|
December
31, 2005
|
September
30, 2006
|
|
December
31, 2006
|
December
31, 2005
|
September
30, 2006
|
|||||||||||
|
Operating
costs - oil and gas production
|
$
|
13.69
|
$
|
13.69
|
$
|
12.73
|
$
|
33,804
|
$
|
29,710
|
$
|
30,950
|
|||||||
|
Production
taxes
|
1.15
|
1.35
|
2.17
|
2,840
|
2,937
|
5,286
|
|||||||||||||
|
DD&A
- oil and gas production
|
|
8.24
|
|
5.23
|
7.39
|
20,335
|
|
11,560
|
|
17,974
|
|||||||||
|
G&A
|
|
4.55
|
|
2.49
|
|
3.87
|
11,231
|
|
5,407
|
|
9,419
|
||||||||
|
Interest
expense
|
|
1.27
|
.71
|
|
1.11
|
3,503
|
|
1,548
|
|
2,707
|
|||||||||
|
Total
|
|
$
|
28.90
|
$
|
23.47
|
|
$
|
27.27
|
$
|
71,713
|
|
$
|
51,162
|
|
$
|
66,336
|
|||
|
December
31, 2006
|
December
31, 2005
|
Change
|
September
30, 2006
|
Change
|
|
|
Average
volume of steam injected (Bbl/D)
|
85,349
|
73,312
|
16%
|
86,556
|
(1%)
|
|
Fuel
gas cost/MMBtu
|
$
5.63
|
$
10.07
|
(44%)
|
$5.69
|
(1%)
|
36
The
following table presents information about our operating expenses for each
of
the years ended December 31:
|
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
||||||||||||||||||||||||||||||||||
|
|
|
2005
|
|
2004
|
|
Change
|
|
2005
|
|
2004
|
|
Change
|
|
||||||||||||||||||||||||||
| Operating costs - oil and gas production | $ |
11.79
|
$
|
10.09
|
17
|
% | $ |
99,066
|
$
|
73,838
|
34
|
% | |||||||||||||||||||||||||||
|
Production
taxes
|
1.37
|
.86
|
59
|
%
|
11,506
|
6,431
|
79
|
%
|
|||||||||||||||||||||||||||||||
|
DD&A
- oil and gas production
|
|
|
4.54
|
|
|
3.96
|
|
|
15
|
%
|
|
38,150
|
|
|
29,752
|
|
|
28
|
%
|
||||||||||||||||||||
|
G&A
|
|
|
2.55
|
|
|
2.99
|
|
|
(15)
|
%
|
|
21,396
|
|
|
22,504
|
|
|
(5)
|
%
|
||||||||||||||||||||
|
Interest
expense
|
|
|
.72
|
|
|
.27
|
|
|
167
|
%
|
|
6,048
|
|
|
2,067
|
|
|
193
|
%
|
||||||||||||||||||||
|
Total
|
|
$
|
20.97
|
|
$
|
18.17
|
|
|
15
|
%
|
$
|
176,166
|
|
$
|
134,592
|
|
|
31
|
%
|
||||||||||||||||||||
Our
total
operating costs, production taxes, G&A and interest expenses for 2005,
stated on a unit-of-production basis, increased 15% over 2004. The changes
were
primarily related to the following items:
| · |
Operating
costs: Higher crude oil and natural gas prices have created an incentive
for the U.S. domestic oil and gas industry to significantly increase
exploration and development activities, which is straining the capacity
for goods and services that support our industry. Thus, higher costs
are
prominent throughout the industry and resulted in higher operating
costs
per BOE for the year ended 2005 as compared to 2004. Costs in California
were also higher due to increased well servicing activities and increases
in steam costs. The cost of our steaming operations on our heavy
oil
properties represents a significant portion of our operating costs
and
will vary depending on the cost of natural gas used as fuel and the
volume
of steam injected. The following table presents steam information:
|
|
|
||||
|
2005
|
2004
|
Change
|
||
|
Average
volume of steam injected (Bbl/D)
|
70,032
|
69,200
|
1%
|
|
|
Fuel
gas cost/MMBtu
|
$7.30
|
$5.46
|
34%
|
|
| · |
Production
taxes: Higher prices, such as those exhibited in 2005, create increased
production taxes.
|
| · |
Depreciation,
depletion and amortization: DD&A increased per BOE in the year ended
2005 from the year ended 2004 due to higher acquisition costs of
our Rocky
Mountain/Mid-Continent region assets as compared to our legacy heavy
oil
assets in California and higher finding and development costs. As
these
costs increase, our DD&A rates per BOE will also increase.
|
| · |
General
and administrative: Approximately two-thirds of our G&A is
compensation or compensation related costs. We intend to remain
competitive in workforce compensation to achieve our growth plans.
Stock-based compensation expense was $.35 per BOE and $.56 per BOE
for the
years ended December 31, 2005 and 2004, respectively. Compensation
expenses increased due to increased staffing resulting from our growth,
and increases in compensation levels and bonuses. Additionally, we
incurred increased legal and accounting fees, primarily due to compliance
with Sarbanes-Oxley, and growth through acquisitions and other financial
reporting related matters. Legal and accounting expenses were $.28
per BOE
in 2005 as compared to $.23 per BOE in
2004.
|
| · |
Interest
expense: We increased our outstanding borrowings to $75 million at
December 31, 2005 as compared to $28 million at December 31, 2004.
Average
borrowings increased as a result of acquisitions of $112 million
during
2005. Additionally, interest rates increased by approximately 1.75%
since
December 31, 2004.
|
37
Estimated
2007 Oil and Gas Operating, G&A and Interest
Expenses.
|
|
Amount
per BOE
|
|
||||||||
|
|
|
Anticipated
|
|
|
|
|||||
|
|
|
range
in 2007
|
|
2006
|
|
2005
|
||||
|
Operating
costs-oil and gas production (1)
|
$
|
14.50
to 15.50
|
|
$
|
12.69
|
|
$
|
11.79
|
||
|
Production
taxes
|
1.50
to 2.00
|
1.58
|
1.37
|
|||||||
|
DD&A
|
|
|
7.75
to 8.75
|
|
|
7.30
|
|
|
4.54
|
|
|
G&A
|
|
|
3.50
to 4.00
|
|
|
3.98
|
|
|
2.55
|
|
|
Interest
expense
|
|
|
1.00
to 2.00
|
|
|
1.05
|
|
|
.72
|
|
|
Total
|
|
$
|
28.25
to 32.25
|
|
$
|
26.60
|
|
$
|
20.97
|
|
(1)
Assuming natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan
to
inject approximately 15% greater steam levels in 2007 compared to 2006
levels.
Dry
hole, abandonment and impairment.
Reflected on our year ended 2006 income statement under the dry hole,
abandonment and impairment line, there is $8.3 million that consists primarily
of two Coyote Flats, Utah wells for $5.2 million, our 25% share in an
exploration well located in the Lake Canyon project area of the Uinta basin
drilled for approximately $1.6 million net to our interest and four wells in
Bakken and four wells in Tri-State for $1.5 million.
For
the
year ended 2005, costs of $5.7 million which were incurred on one exploratory
well on the Coyote Flats prospect, the Midway-Sunset property, two exploratory
wells at northern Brundage Canyon, and $2.5 million of impairment on the
remaining carrying value of our Illinois and eastern Kansas prospective CBM
acreage were charged to expense. During 2004, we recorded costs of $.7 million
on exploratory wells on the Midway-Sunset property and the Coyote Flats
prospect.
Exploration
costs.
We
incurred exploration costs of $3.8 million in 2006 compared to $3.6 million
and
zero costs in 2005 and 2004, respectively. These costs consist primarily of
geological and geophysical costs. We participated in 3-D seismic surveys at
Lake
Canyon, Utah and in the Tri-State area. We are projecting exploration costs
in
2007 of between $1 million and $2 million.
Income
Taxes.
The
Revenue Reconciliation Act of 1990 included a tax credit for certain costs
associated with extracting high-cost, capital-intensive marginal oil or gas
which utilizes certain methods, including cyclic steam and steam flood recovery
methods for heavy oil. Historically, we have had significant investment in
qualifying costs and have been able to reduce our effective tax rate
considerably. However, the federal and state EOR tax credits were fully phased
out in 2006 due to the 2005 average U.S. wellhead crude oil price exceeding
the
allowable EOR tax credit ceiling price of $44.48 per barrel. If the average
U.S.
wellhead price of crude oil declines below the triggering point in future years,
we expect to earn and claim the EOR credit on qualifying expenditures and
therefore our effective tax rate should decline. As of December 31, 2006 we
have
approximately $24 million of federal and $18 million of state (California)
EOR
tax credit carryforwards available to reduce future cash income taxes. The
EOR
credits will begin to expire, if unused, in 2024 and 2015 for federal and
California, respectively.
We
experienced an effective tax rate of 39%, 31% and 23% in 2006, 2005 and 2004,
respectively. The significant increase in effective tax rate during 2006 is
primarily due to the phase out of EOR tax credits in 2006. In anticipation
of
the continued full EOR credit phase out in 2007, we expect our effective tax
rate to be between 37% to 39%, based on WTI prices averaging between $40 and
$60. See Note 9 to the financial statements for further
information.
Commodity
derivatives. In
the
quarter ended March 31, 2006, we took a charge for the change in fair
market value of our natural gas derivatives put in place to protect our Piceance
basin acquisition future cash flows. These gas derivatives did not qualify
for
hedge accounting under SFAS 133 because the price index in the derivative
instrument did not correlate closely with the item being hedged. The pre-tax
charge in the first quarter was $4.8 million which represented the change
in fair market value over the life of the contract, which resulted from an
increase in natural gas prices from the date of the derivative to March 31,
2006. On May 31, 2006, we entered into basis swaps with natural gas volumes
to match the volumes on our NYMEX Henry Hub collars that were placed on
March 1, 2006. The combination of the derivative instruments entered into
on March 1, 2006 (described above) and the basis swaps were designated as
cash flow hedges in accordance with SFAS 133. Thus the unrealized net gain
of $5.6 million on the income statement in the second quarter of 2006 under
the caption "Commodity derivatives" is primarily the change in fair value of
the
derivative instrument caused by changes in forward price curves prior to
designating these instruments as cash flow hedges. Post May 31, 2006
changes in the marked-to-market fair values are reflected in Other Comprehensive
Income.
38
Asset
dispositions. We
have
significantly increased and strengthened our portfolio of assets since 2002
and
expect to continue to make acquisitions. We anticipate that we will dispose
of
certain properties or assets over time. The assets most likely for disposition
will be those that do not fit or complement our strategic growth plan, that
are
not contributing satisfactory economic returns given the profile of the assets,
or we believe the development potential will not be meaningful to our company
as
a whole. We have identified several assets that fit our criteria and expect
to
divest of these assets in 2007. Proceeds from these sales will contribute to
the
funding of our capital program. Net
oil
and gas properties and equipment classified as held for sale is $8.9 million
for
the year ended December 31, 2006 in accordance with SFAS No. 144. See Note
2 to the financial statements.
Reserve
Replacement Rate.
The
reserve replacement rate is calculated by dividing total new proved reserves
added for the year by total production for the year. Total new proved reserves
include; revision of previous estimate, improved recovery, extensions and
discoveries, and purchase of reserves in place. This measure is important
because it is an indication of growth in proved reserves and, thus may impact
our value. We believe our calculation of this measure is substantially similar
to how other companies compute reserve replacement rate. See Item 8 Supplemental
Information About Oil & Gas Producing Activities (unaudited).
Financial
Condition, Liquidity and Capital Resources. Substantial
capital is required to replace and grow reserves. We achieve reserve replacement
and growth primarily through successful development and exploration drilling
and
the acquisition of properties. Fluctuations in commodity prices have been the
primary reason for short-term changes in our cash flow from operating
activities. The net long-term growth in our cash flow from operating activities
is the result of growth in production as affected by period to period
fluctuations in commodity prices. In the second quarter of 2006, we revised
our
senior unsecured revolving credit facility to increase our maximum credit amount
under the facility to $750 million and increased our current borrowing base
to $500 million. On October 24, 2006, we completed the sale of $200 million
of ten year 8.25% senior subordinated notes and paid down our borrowings under
our facility by $141 million. As of December 31, 2006, we had total borrowings
under the senior unsecured revolving credit facility and senior unsecured money
market line of credit of $206 million and $200 million under our senior
subordinated notes.
Capital
Expenditures. We
establish a capital budget for each calendar year based on our development
opportunities and the expected cash flow from operations for that year.
Acquisitions are typically debt financed. We may revise our capital budget
during the year as a result of acquisitions and/or drilling outcomes. Excess
cash generated from operations is expected to be applied toward acquisitions,
debt reduction or other corporate purposes.
In
2007,
we have a developmental capital program of approximately $267 million, excluding
acquisitions, plus we intend to make a final payment of $54 million associated
with our Piceance joint venture. We are proceeding with this program, but may
revise our plans due to lower commodity price expectations, timing of crude
deliveries out of the Uinta basin, equipment availability, permitting or other
factors. Our 2007 expenditures will be directed toward developing reserves,
increasing oil and gas production and exploration opportunities. For 2007,
we
plan to invest approximately $176 million, or 66%, in our Rocky
Mountain/Mid-Continent region assets, and $91 million, or 34%, in our California
assets. Approximately half of the capital budget is focused on converting
probable and possible reserves into proved reserves and on our appraisal and
exploratory projects, while the other half is for the development of our proved
reserves and facility costs.
Dividends.
We paid
a special dividend of $.02 per share on September 29, 2006 and increased our
regular quarterly dividend by 15%, from $.065 to $.075 per share beginning
with
the September 2006 dividend. Our regular annual dividend is currently $.30
per
share, payable quarterly in March, June, September and December.
Working
Capital and Cash Flows. Cash
flow
from operations is dependent upon the price of crude oil and natural gas and
our
ability to increase production and manage costs. Combined crude oil and natural
gas prices increased in 2006 (see graphs on page 33) and we increased production
by 10%.
Our
working capital balance fluctuates as a result of the amount of borrowings
and
the timing of repayments under our credit arrangements. We used our long-term
borrowings under our senior unsecured revolving credit facility primarily to
fund property acquisitions. Generally, we use excess cash to pay down borrowings
under our credit arrangement. As a result, we often have a working capital
deficit or a relatively small amount of positive working capital. In 2006,
the
working capital deficit was substantially greater than 2005. The increase in
the
deficit is primarily made up of the $54.4 million property acquisition payable
related to the final payment of the June 2006 Piceance transaction as compared
to 2005.
39
The
table
below compares financial condition, liquidity and capital resources changes
as
of and for the years ended December 31 (in millions, except for production
and
average prices):
|
2006
|
2005
|
Change
|
|
|
Average
production (BOE/D)
|
25,398
|
23,015
|
+10%
|
|
Average
oil and gas sales prices, per BOE after hedging
|
$
46.67
|
$
41.62
|
+12%
|
|
Net
cash provided by operating activities
|
$
243
|
$
188
|
+29%
|
|
Working
capital
|
$
(101)
|
$
(55)
|
(84%)
|
|
Sales
of oil and gas
|
$
430
|
$
350
|
+23%
|
|
Long-term
debt
|
$
390
|
$
75
|
+420%
|
|
Capital
expenditures, including acquisitions and deposits on acquisitions
(1)
|
$
523
|
$
231
|
+126%
|
|
Dividends
paid
|
$
13.2
|
$
13.2
|
-%
|
(1)
Does not include our commitment to drill wells on our Lake Canyon prospect
pursuant to our joint venture or the remaining payment under our Piceance basin
joint venture.
The
table
below compares financial condition, liquidity and capital resources changes
as
of and for the three months ended (in millions, except for production and
average prices):
|
December
31, 2006
|
December
31, 2005
|
Change
|
September
30, 2006
|
Change
|
|
|
Average
production (BOE/D)
|
26,889
|
23,539
|
14%
|
26,423
|
2%
|
|
Average
oil and gas sales prices, per BOE after hedging
|
$
42.00
|
$
44.90
|
(6%)
|
$
47.28
|
(11%)
|
|
Net
cash provided by operating activities
|
$
58
|
$
65
|
(11%)
|
$
101
|
(43%)
|
|
Working
capital, excluding line of credit
|
$
(101)
|
$
(55)
|
(84%)
|
$
(154)
|
34%
|
|
Sales
of oil and gas
|
$
102
|
$
98
|
4%
|
$
116
|
(12%)
|
|
Long-term
debt, including line of credit
|
$
390
|
$
75
|
420%
|
$
330
|
18%
|
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
127
|
$
41
|
210%
|
$
148
|
(14%)
|
|
Dividends
paid
|
$
3.3
|
$
2.9
|
14%
|
$
4.2
|
(21%)
|
In
June
2005, we announced that our Board of Directors authorized a share repurchase
program for up to an aggregate of $50 million of our outstanding Class A Common
Stock. From June 2005 through December 31, 2006, we have purchased 818,000
shares in the open market for approximately $25 million. See Note 7 to the
financial statements.
Hedging.
See
Item
7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to
the
financial statements.
Credit
Facility. See
Note
6 to the financial statements for more information.
Contractual
Obligations.
Our
contractual obligations as of December 31, 2006 are as follows (in
thousands):
| Contractual Obligations | Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | ||||||||||||||||||||||||
|
Long-term
debt and interest
|
|
$
|
609,464
|
$
|
28,603
|
$
|
28,603
|
$
|
28,603
|
$
|
28,603
|
$
|
212,552
|
$
|
282,500
|
||||||||||||||||
|
Abandonment
obligations
|
|
|
26,135
|
|
740
|
|
941
|
|
991
|
|
991
|
|
991
|
|
21,481
|
||||||||||||||||
|
Operating
lease obligations
|
|
|
14,208
|
|
1,822
|
|
1,670
|
|
1,375
|
|
1,357
|
|
1,357
|
|
6,627
|
||||||||||||||||
|
Property
acquisition payable
|
54,000
|
54,000
|
-
|
-
|
-
|
-
|
-
|
||||||||||||||||||||||||
|
Drilling
and rig obligations
|
|
|
107,333
|
|
34,260
|
|
28,960
|
|
41,989
|
|
2,124
|
|
-
|
|
-
|
||||||||||||||||
|
Firm
natural gas transportation
contracts |
|
|
73,795
|
|
4,801
|
|
7,584
|
|
8,496
|
|
8,659
|
|
8,659
|
|
35,596
|
||||||||||||||||
|
Total
|
|
$
|
884,935
|
$
|
124,226
|
$
|
67,758
|
$
|
81,454
|
$
|
41,734
|
$
|
223,559
|
$
|
346,204
|
40
Long-term
debt and interest
- Our
credit facility borrowings and related interest of approximately 6.4% can be
paid before its maturity date without significant penalty on borrowings under
our credit facility. Our bond notes and related interest of 8.25% mature in
November 2016, but are not redeemable until November 1, 2011 and are not
redeemable without any premium until November 1, 2014.
Operating
leases -
We
lease
corporate and field offices in California, Colorado and Texas. Rent expense
with
respect to our lease commitments for the years ended December 31, 2006, 2005
and
2004 was $1 million, $.6 million, and $.6 million, respectively. In 2006, we
purchased an airplane for business travel which was subsequently sold and
contracted under a ten year operating lease beginning December
2006.
Drilling
obligation
-
We
intend
to participate in the drilling of over 16 gross wells on our Lake Canyon
prospect over the four year contract, beginning in 2006. Our minimum obligation
under our exploration and development agreement is $9.6 million. Also included
above, under our June 2006 joint venture agreement in the Piceance basin we
must
have 120 wells drilled by 2010 to avoid penalties of $.2 million per well or
a
maximum of $24 million.
Drilling
rig obligation
- We are
obligated in operating lease agreements for the use of multiple drilling rigs.
Firm
natural gas transportation
-
We
have
one firm transportation contract which provides us additional flexibility in
securing our natural gas supply for California operations. This allows us to
potentially benefit from lower natural gas prices in the Rocky Mountains
compared to natural gas prices in California. We also have several long-term
transportation contracts which provide us with physical access to interstate
pipelines to move gas from our producing areas to markets.
Application
of Critical Accounting Policies. The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
for
the reporting period and as of the financial statement date. These estimates
and
assumptions affect the reported amounts of assets and liabilities, the
disclosure of contingent liabilities and the reported amounts of revenues and
expenses. Actual results could differ from those amounts.
A
critical accounting policy is one that is important to the portrayal of our
financial condition and results, and requires management to make difficult
subjective and/or complex judgments. Critical accounting policies cover
accounting matters that are inherently uncertain because the future resolution
of such matters is unknown. We believe the following accounting policies are
critical policies.
Successful
Efforts Method of Accounting. We
account for our oil and gas exploration and development costs using the
successful efforts method. Geological and geophysical costs, and the costs
of
carrying and retaining undeveloped properties, are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes. All
exploratory wells are evaluated for economic viability within one year of well
completion. Exploratory wells that discover potentially economic reserves that
are in areas where a major capital expenditure would be required before
production could begin, and where the economic viability of that major capital
expenditure depends upon the successful completion of further exploratory work
in the area, remain capitalized as long as the additional exploratory work
is
under way or firmly planned.
Oil
and Gas Reserves. Oil
and
gas reserves include proved reserves that represent estimated quantities of
crude oil, natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Our
oil
and gas reserves are based on estimates prepared by independent engineering
consultants. Reserve engineering is a subjective process that requires judgment
in the evaluation of all available geological, geophysical, engineering and
economic data. Projected future production rates, the timing of future capital
expenditures as well as changes in commodity prices may significantly impact
estimated reserve quantities. Depreciation, depletion and amortization
(DD&A) expense and impairment of proved properties are impacted by our
estimation of proved reserves. These estimates are subject to change as
additional information and technologies become available. Accordingly, oil
and
natural gas quantities ultimately recovered and the timing of production may
be
substantially different than projected. Reduction in reserve estimates may
result in increased DD&A expense, increased impairment of proved properties
and a lower standardized measure of discounted future net cash
flows.
Carrying
Value of Long-lived Assets.
Downward revisions in our estimated reserve quantities, increases in future
cost
estimates or depressed crude oil or natural gas prices could cause us to reduce
the carrying amounts of our properties. We perform an impairment analysis of
our
proved properties annually by comparing the future undiscounted net revenue
per
the annual reserve valuation prepared by our 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
41
estimated
future undiscounted cash flow, they are written down to fair value. Cash flows
used in the impairment analysis are determined based on our estimates of crude
oil and natural gas reserves, future crude oil and natural gas prices and costs
to extract these reserves. For our unproved properties, we perform an impairment
analysis annually or whenever events or changes in circumstances indicate an
asset's net book carrying value may not be recoverable.
Derivatives
and Hedging. We
follow
the provisions of Statement of Financial Accounting Standards (SFAS)
No. 133, Accounting
for Derivative Instruments and Hedging Activities.
SFAS 133 requires the accounting recognition of all derivative instruments
as either assets or liabilities at fair value. Derivative instruments that
are
not hedges must be adjusted to fair value through net income. Under the
provisions of SFAS 133, we may designate a derivative instrument as hedging
the exposure to 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. Our policy is
to
assess hedge effectiveness at the end of each calendar quarter.
Income
Taxes. We
compute income taxes in accordance with SFAS No. 109, Accounting
for Income Taxes.
SFAS
No. 109 requires an asset and liability approach which results in the
recognition of deferred income taxes on the difference between the tax basis
of
an asset or liability and its carrying amount in our financial statements.
This
difference will result in taxable income or deductions in future years when
the
reported amount of the asset or liability is recovered or settled, respectively.
Considerable judgment is required in determining when these events may occur
and
whether recovery of an asset is more likely than not. Additionally, our federal
and state income tax returns are generally not filed before the financial
statements are prepared. Therefore we estimate the tax basis of our assets
and
liabilities at the end of each calendar year as well as the effects of tax
rate
changes, tax credits, and tax credit carryforwards. A valuation allowance is
recognized if it is determined that deferred tax assets may not be fully
utilized in future periods. 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. We may generate
EOR tax credits from the production of our heavy crude oil in California which
results in a deferred tax asset and believe that these credits will be fully
utilized in future years and consequently have not recorded any valuation
allowance related to these credits. Due to uncertainties involved with tax
matters, the future effective tax rate may vary significantly from the estimated
current year effective tax rate.
Asset
Retirement Obligations.
We
have
significant obligations to plug and abandon oil and natural gas wells and
related equipment at the end of oil and gas production operations. The
computation of our asset retirement obligations (ARO) was prepared in accordance
with SFAS No. 143, Accounting
for Asset Retirement Obligations,
which
requires us to record the fair value of liabilities for retirement obligations
of long-lived assets. Estimating the future ARO requires management to make
estimates and judgments regarding timing, current estimates of plugging and
abandonment costs, as well as what constitutes adequate remediation. We obtained
estimates from third parties and used the present value of estimated cash flows
related to our ARO to determine the fair value. Inherent in the present value
calculation are numerous assumptions and judgments including the ultimate costs,
inflation factors, credit adjusted discount rates, timing of settlement and
changes in the legal, regulatory, environmental and political environments.
Changes in any of these assumptions can result in significant revisions to
the
estimated ARO. To the extent future revisions to these assumptions impact the
present value of the existing ARO liability, a corresponding adjustment will
be
made to the related asset. Due to the subjectivity of assumptions and the
relatively long life of our assets, the ultimate costs to retire our wells
may
vary significantly from previous estimates.
Environmental
Remediation Liability. We
review, on a quarterly basis, our estimates of costs of the cleanup of various
sites including sites in which governmental agencies have designated us as
a
potentially responsible party. In accordance with SFAS No. 5, Accounting
for Contingencies,
when it
is probable that obligations have been incurred and where a minimum cost or
a
reasonable estimate of the cost of remediation can be determined, the applicable
amount is accrued. Determining when expenses should be recorded for these
contingencies and the appropriate amounts for accrual is an estimation process
that includes the subjective judgment of management. In many cases, management's
judgment is based on the advice and opinions of legal counsel and other
advisers, the interpretation of laws and regulations, which can be interpreted
differently by regulators or courts of law, our experience and the experience
of
other companies in dealing with similar matters and the decision of management
on how it intends to respond to a particular matter. A change in estimate could
impact our oil and gas operating costs and the liability, if applicable,
recorded on our balance sheet.
Accounting
for Business Combinations. We
have grown substantially through acquisitions and our business strategy is
to
continue to pursue acquisitions as opportunities arise. We have accounted for
all of our business combinations using the purchase method, which is the only
method permitted under SFAS 141. The accounting for business combinations
is complicated and involves the use of significant judgment. Under the purchase
method of accounting, a business combination is accounted for at a purchase
price based
42
upon
the
fair value of the consideration given, whether in the form of cash, assets,
stock or the assumption of liabilities. The assets and liabilities acquired
are
measured at their fair values, and the purchase price is allocated to the assets
and liabilities based upon these fair values. The excess of the fair value
of
assets acquired and liabilities assumed over the cost of an acquired entity,
if
any, is allocated as a pro rata reduction of the amounts that otherwise would
have been assigned to certain acquired assets.
Determining
the fair values of the assets and liabilities acquired involves the use of
judgment, since some of the assets and liabilities acquired do not have fair
values that are readily determinable. Different techniques may be used to
determine fair values, including market prices, where available, appraisals,
comparisons to transactions for similar assets and liabilities and present
value
of estimated future cash flows, among others. Since these estimates involve
the
use of significant judgment, they can change as new information becomes
available.
Each
of
the business combinations completed were of interests in oil and gas assets.
We
believe the consideration we paid to acquire these assets represents the fair
value of the assets and liabilities acquired at the time of acquisition.
Consequently, we have not recognized any goodwill from any of our business
combinations.
Stock-Based
Compensation. We
adopted SFAS No. 123(R) to account for our stock option plan beginning
January 1, 2006. This standard requires us to measure the cost of employee
services received in exchange for an award of equity instruments based on the
grant-date fair value of the award. We previously adopted the fair value
recognition provisions of SFAS No. 123, Accounting
for Stock-Based Compensation
effective January 1, 2004. The modified prospective method was selected as
described in SFAS 148, Accounting
for Stock-Based Compensation—Transition and Disclosure.
Under
this method, we recognize stock option compensation expense as if we had applied
the fair value method to account for unvested stock options from the original
effective date. Stock option compensation expense is recognized from the date
of
grant to the vesting date. The fair value of each option award is estimated
on
the date of grant using the Black-Scholes option pricing model that uses the
following assumptions. Expected volatilities are based on the historical
volatility of our stock. We use historical data to estimate option exercises
and
employee terminations within the valuation model; separate groups of employees
that have similar historical exercise behavior are considered separately for
valuation purposes. The expected term of options granted is based on historical
exercise behavior and represents the period of time that options granted are
expected to be outstanding; the range results from certain groups of employees
exhibiting different exercise behavior. The risk free rate for periods within
the contractual life of the option is based on U.S. Treasury rates in effect
at
the time of grant.
Electricity
Cost Allocation. Our
investment in our cogeneration facilities has been for the express purpose
of
lowering steam costs in our California heavy oil operations and securing
operating control of the respective steam generation. Such cogeneration
operations produce electricity and steam and use natural gas as fuel. We
allocate steam costs to our oil and gas operating costs based on the conversion
efficiency (of fuel to electricity and steam) of the cogeneration facilities
plus certain direct costs in producing steam. Electricity revenue represents
sales to the utilities. Electricity used in oil and gas operations is allocated
at cost. A portion of the capital costs of the cogeneration facilities is
allocated to DD&A-oil and gas production.
Capitalized
Interest.
Interest
incurred on funds borrowed to finance exploration and certain acquisition and
development activities is capitalized. To qualify for interest capitalization,
the costs incurred must relate to the acquisition of unproved reserves, drilling
of wells to prove up the reserves and the installation of the necessary
pipelines and facilities to make the property ready for production. Such
capitalized interest is included in oil and gas properties, buildings and
equipment. Capitalized interest is amortized over the estimated life of the
respective project.
Recent
Accounting Pronouncements. In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. In
April 2005, the SEC issued a rule that SFAS No. 123(R) will be
effective for annual reporting periods beginning on or after June 15, 2005.
As a result, we adopted this statement beginning January 1, 2006. We
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly, the adoption of SFAS No. 123(R) using the modified prospective
method did not have a material impact on our condensed financial statements
for
the year ended December 31, 2006.
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections,
a
replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued.
SFAS No. 154 requires retrospective application to prior period financial
statements for changes in accounting principle, unless it is impracticable
to
determine either the period-specific effects or the cumulative effect of the
change. SFAS No. 154 also requires that retrospective application of a
change in accounting principle be limited to the direct effects of the change.
Indirect effects of a change in accounting principle should be recognized in
the
period of the accounting change. SFAS No. 154 became effective for our
fiscal year beginning January 1, 2006. The adoption of SFAS No. 154
had no effect to our financial position and result of operations.
43
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for our fiscal year beginning after September
15,
2006. While there was no impact on our financial statements as of December
31,
2006, based on our existing derivatives, we may experience a financial impact
depending on the nature and extent of any new derivative instruments entered
into after the effective date of SFAS No. 155.
In
June
2006, the FASB issued Interpretation (FIN) No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109.
This
interpretation requires that realization of an uncertain income tax position
must be “more likely than not” (i.e. greater than 50% likelihood of receiving a
benefit) before it can be recognized in the financial statements. Further,
this
interpretation prescribes the benefit to be recorded in the financial statements
as the amount most likely to be realized assuming a review by tax authorities
having all relevant information and applying current conventions. This
interpretation also clarifies the financial statement classification of
tax-related penalties and interest and sets forth new disclosures regarding
unrecognized tax benefits. This interpretation is effective for fiscal years
beginning after December 15, 2006, and we will be required to adopt this
interpretation in the first quarter of 2007. Based on our evaluation as of
December 31, 2006, we do not believe that the implementation of FIN 48 will
have
a material impact on our financial statements.
In
September 2006, SFAS No. 157, Fair
Value Measurements was
issued by the FASB. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
SFAS No. 157 will become effective for our fiscal year beginning January 1,
2008, and we are currently assessing the potential impact of this Statement
on
our financial statements.
In
September 2006, Staff Accounting Bulletin (“SAB”) No. 108,
Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements.
Registrants must quantify the impact on current period financial statements
of
correcting all misstatements, including both those occurring in the current
period and the effect of reversing those that have accumulated from prior
periods. This SAB was adopted at December 31, 2006. The adoption of
SAB No. 108 had no effect on our financial position or on the results
of our operations.
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities,
which
permits an entity to measure certain financial assets and financial liabilities
at fair value. The objective of SFAS No. 159 is to improve financial reporting
by allowing entities to mitigate volatility in reported earnings caused by
the
measurement of related assets and liabilities using different attributes,
without having to apply complex hedge accounting provisions. Under SFAS No.
159,
entities that elect the fair value option (by instrument) will report unrealized
gains and losses in earnings at each subsequent reporting date. The fair value
option election is irrevocable, unless a new election date occurs. SFAS No.
159
establishes presentation and disclosure requirements to help financial statement
users understand the effect of the entity’s election on its earnings, but does
not eliminate disclosure requirements of other accounting standards. Assets
and
liabilities that are measured at fair value must be displayed on the face of
the
balance sheet. This statement is effective beginning January 1, 2008 and we
are
evaluating this pronouncement.
Item
7A. Quantitative
and Qualitative Disclosures About Market Risk
As
discussed in Note 15 to the financial statements, to minimize the effect of
a
downturn in oil and gas prices and protect our profitability and the economics
of our development plans, from time to time we enter into crude oil and natural
gas hedge contracts. The terms of contracts depend on various factors, including
management's view of future crude oil and natural gas prices, acquisition
economics on purchased assets and our future financial commitments. This price
hedging program is designed to moderate the effects of a severe crude oil and
natural gas price downturn while allowing us to participate in any commodity
price increases. In California, we benefit from lower natural gas pricing as
we
are a consumer of natural gas in our operations and elsewhere, we benefit from
higher natural gas pricing. We have hedged, and may hedge in the future both
natural gas purchases and sales as determined appropriate by management.
Management regularly monitors the crude oil and natural gas markets and our
financial commitments to determine if, when, and at what level some form of
crude oil and/or natural gas hedging and/or basis adjustments or other price
protection is appropriate in accordance with policy established by our board
of
directors.
Currently,
our hedges are in the form of swaps and collars. However, we may use a variety
of hedge instruments in the future to hedge WTI or the index gas price. We
have
crude oil sales contracts in place which are priced based on a correlation
to
WTI. Natural gas (for cogeneration and conventional steaming operations) is
purchased at the SoCal border price and we sell our produced gas in Colorado
and
Utah at the Colorado Interstate Gas (CIG) and Questar index prices,
respectively.
44
The
following table summarizes our hedge position as of December 31,
2006:
|
|
|
Average
|
|
|
|
|
Average
|
|
||||||||||||
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Average
|
||||||||||
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Price
|
||||||||||
|
Crude
Oil Sales (NYMEX WTI) Collars
|
|
Natural
Gas Sales (NYMEX HH TO CIG) Basis Swaps
|
|
|
|
|
||||||||||||||
|
Full
year 2007
|
10,000
|
$47.50
/ $70
|
|
2007
Average
|
13,500
|
$1.65
|
||||||||||||||
|
Full
year 2008
|
10,000
|
$47.50
/ $70
|
2008
Average
|
18,250
|
$1.50
|
|||||||||||||||
|
Full
year 2009
|
10,000
|
$47.50
/ $70
|
||||||||||||||||||
|
Full
year 2010
|
5,000
|
$56.00
/ $78.95
|
Natural
Gas Sales (NYMEX HH) Collars
|
Average
MMBtu Per Day
|
Floor/Ceiling
Prices
|
|||||||||||||||
|
|
1st
Quarter
2007
|
12,000
|
$8.00
/ $16.70
|
|||||||||||||||||
|
2nd
Quarter
2007
|
13,000
|
$8.00
/ $8.82
|
||||||||||||||||||
|
|
3rd
Quarter 2007
|
14,000
|
$8.00
/ $9.10
|
|||||||||||||||||
|
4th
Quarter 2007
|
15,000
|
$8.00
/ $11.39
|
||||||||||||||||||
|
|
1st
Quarter 2008
|
16,000
|
$8.00
/ $15.65
|
|||||||||||||||||
|
|
2nd
Quarter
2008
|
17,000
|
$7.50
/ $8.40
|
|||||||||||||||||
|
|
3rd
Quarter 2008
|
19,000
|
$7.50
/ $8.50
|
|||||||||||||||||
|
|
4th
Quarter 2008
|
21,000
|
$8.00
/ $9.50
|
|||||||||||||||||
Payments
to our counterparties are triggered when the monthly average prices are above
the swap or ceiling price in the case of our crude oil and natural gas sales
hedges and below the swap price for our natural gas sales hedge positions.
Conversely, payments from our counterparties are received when the monthly
average prices are below the swap or floor price for our crude oil and natural
gas sales hedges and above the swap price for our natural gas sales hedge
positions.
As
of
February 28, 2007, we have converted 2,000 Bbl/D of our 2007 oil collars
beginning on March 1, 2007 to a swap with a strike price of $60 WTI. This swap
is considered to be an effective cash flow hedge and the transaction cost to
convert to this swap is estimated at $.6 million on an after tax basis. We
intend to proceed with additional conversions of our existing collars to swaps
for a portion of our remaining 2007 collars if we can attain at least a $60
WTI
strike price. Additionally, we entered into oil swaps for 1,000 Bbl/D at $64.55
from March 2007 through December 2007.
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below $47.50 per barrel while
still participating in any oil price increase up to $78.95 per barrel on these
volumes and if 2) gas prices decline below approximately $8 per MMBtu.
These hedges improve our financial flexibility by locking in significant
revenues and cash flow upon a substantial decline in crude oil or natural gas
prices. It also allows us to develop our long-lived assets and pursue
exploitation opportunities with greater confidence in the projected economic
outcomes and allows us to borrow a higher amount under our senior unsecured
revolving credit facility.
While
we
have designated our hedges as cash flow hedges in accordance with SFAS
No. 133, Accounting
for Derivative Instruments and Hedging Activities,
it is
possible that a portion of the hedge related to the movement in the WTI to
California heavy crude oil price differential may be determined to be
ineffective. Likewise, we may have some ineffectiveness in our natural gas
hedges due to the movement of HH pricing as compared to actual sales points.
If
this occurs, the ineffective portion will directly impact net income rather
than
being reported as Other Comprehensive Income. While we believe that the
differential will narrow and move closer toward its historical level over time,
there are no assurances as to the movement in the differential. If the
differential were to change significantly, it is possible that our hedges,
when
marked-to-market, could have a material impact on earnings in any given quarter
and, thus, add increased volatility to our net income. The marked-to-market
values reflect the liquidation values of such hedges and not necessarily the
values of the hedges if they are held to maturity.
We
entered into derivative contracts (natural gas swaps and collar contracts)
on
March 1, 2006 that did not qualify for hedge accounting under SFAS 133 because
the price index for the location in the derivative instrument did not correlate
closely with the item being hedged. These contracts were recorded in the first
quarter of 2006 at their fair value on the balance sheet and we recognized
an
unrealized net loss of approximately $4.8 million on the income statement under
the caption “Commodity derivatives.” We entered into natural gas basis swaps on
the same volumes and maturity dates as the previous hedges in May 2006 which
allowed for these derivatives to be designated as cash flow hedges going
forward, causing an unrealized net gain of $5.6 million to be recognized in
the
45
second
quarter of 2006. The difference of $.8 million was recorded in other
comprehensive income at the date the hedges were designated.
Additionally,
on June 8, 2006 and July 10, 2006 we entered into five year interest rate swaps
for a fixed rate of approximately 5.5% on $100 million of our outstanding
borrowings under our credit facility. These interest rate swaps have been
designated as cash flow hedges.
The
related cash flow impact of all of our derivative activities are reflected
as
cash flows from operating activities.
Irrespective
of the unrealized gains reflected in Other Comprehensive Income, the ultimate
impact to net income over the life of the hedges will reflect the actual
settlement values. All of these hedges have historically been deemed to be
cash
flow hedges with the marked-to-market valuations provided by external sources,
based on prices that are actually quoted.
At
December 31, 2006, Accumulated Other Comprehensive Loss, net of income taxes,
consisted of $20 million of unrealized losses from our crude oil and natural
gas
hedges. Deferred net losses recorded in Accumulated Other Comprehensive Loss
at
December 31, 2006 are expected to be reclassified to earnings over the life
of
the contracts. The use of hedging transactions also involves the risk that
the
counterparties will be unable to meet the financial terms of such transactions.
With respect to our hedging activities, we utilize multiple counterparties
on
our hedges and monitor each counterparty's credit rating.
| 2006 | 2005 | 2004 | |||||||||||||||||||
|
Net
reduction of sales of oil and gas revenue due to hedging activities
(in
millions)
|
|
$
|
15.7
|
|
$
|
45.3
|
|
$
|
24.9
|
||||||||||||
|
Net
reduction of cost of gas due to hedging activities (in
millions)
|
$
|
1.6
|
$
|
5.0
|
$
|
1.3
|
|||||||||||||||
|
Net
reduction in revenue per BOE due to hedging activities
|
$
|
1.71
|
$
|
5.39
|
$
|
3.32
|
Based
on
NYMEX futures prices as of December 31, 2006, (WTI $66.39; HH $7.51) we would
expect to make pre-tax future cash payments or to receive payments over the
remaining term of our crude oil and natural gas hedges in place as
follows:
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|||||||||||||||||||||||||||
|
|
|
12/31/06
|
|
on
earnings
|
|
|||||||||||||||||||||||||||
|
|
NYMEX Futures | -20% | -10% | +10% | +20% | |||||||||||||||||||||||||||
| Average WTI Futures Price (2007 - 2010) |
$
|
66.39 |
$
|
53.11 |
$
|
59.75 |
$
|
73.02 |
$
|
79.66 | ||||||||||||||||||||||
|
Crude
Oil gain/(loss) (in millions)
|
|
-
|
2.5
|
|
|
.1
|
|
(34.8
|
)
|
(108.2
|
)
|
|||||||||||||||||||||
|
Average
HH Futures Price (2007 - 2008)
|
|
7.51
|
6.00
|
|
|
6.76
|
|
8.26
|
9.01
|
|||||||||||||||||||||||
|
Natural
Gas gain (in millions)
|
10.7
|
26.0
|
17.1
|
7.8
|
3.1
|
|||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
||||||||||||||||||||||||||||||||
|
2007
(WTI $64.35; HH $6.97)
|
$
|
4.8
|
$
|
11.5
|
$
|
8.0
|
$
|
(3.1
|
)
|
$
|
(26.1
|
)
|
||||||||||||||||||||
|
2008
(WTI $67.45; HH $8.06)
|
5.9
|
14.5
|
9.1
|
(9.6
|
)
|
(37.2
|
)
|
|||||||||||||||||||||||||
|
2009
(WTI $67.21)
|
-
|
-
|
-
|
(14.3
|
)
|
(38.9
|
)
|
|||||||||||||||||||||||||
|
2010
(WTI $66.53)
|
|
|
-
|
|
2.5
|
.1
|
-
|
(2.9
|
)
|
|||||||||||||||||||||||
| Total |
$
|
10.7 |
$
|
28.5 |
$
|
17.2 |
$
|
(27.0 | ) |
$
|
(105.1 | ) | ||||||||||||||||||||
Interest
Rates.
Our
exposure to changes in interest rates results primarily from long-term debt.
On
October 24, 2006, we issued $200 million of 8.25% senior subordinated notes
due
2016 in a public offering. Total
long-term debt outstanding at December 31, 2006 and 2005 was $390 million and
$75 million, respectively. Interest on amounts borrowed under our revolving
credit facility is charged at LIBOR plus 1.0% to 1.75%, with the exception
of
the $100 million of principal for which we have a hedge in place to fix the
interest rate at approximately 5.5% plus the senior unsecured revolving credit
facility’s margin through June 30, 2011. Based on year-end 2006 credit facility
borrowings, a 1% change in interest rates would have a $.6 million after tax
impact on our financial statements.
46
Item
8. Financial
Statements and Supplementary Data
|
Page
|
|||
|
Report
of PricewaterhouseCoopers LLP, an Independent Registered Public Accounting
Firm
|
48
|
||
|
Balance
Sheets at December 31, 2006 and 2005
|
49
|
||
|
Statements
of Income for the Years Ended December 31, 2006, 2005 and 2004
|
50
|
||
|
Statements
of Comprehensive Income for the Years Ended December 31, 2006, 2005
and
2004
|
50
|
||
|
Statements
of Shareholders' Equity for the Years Ended December 31, 2006, 2005
and
2004
|
51
|
||
|
Statements
of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
|
52
|
||
|
Notes
to the Financial Statements
|
53
|
||
|
Supplemental
Information About Oil & Gas Producing Activities
(unaudited)
|
72
|
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.
47
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Board of Directors and Shareholders of Berry Petroleum Company:
We
have
completed integrated audits of Berry Petroleum Company’s financial statements
and of its internal control over financial reporting as of December 31, 2006
in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are presented
below.
Financial
statements
In
our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Berry Petroleum
Company at December 31, 2006 and 2005, and the results of its operations and
its
cash flows for each of the three years in the period ended December 31, 2006
in
conformity with accounting principles generally accepted in the United States
of
America. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements
in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit
to
obtain reasonable assurance about whether the financial statements are free
of
material misstatement. An audit of financial statements includes examining,
on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
Internal
control over financial reporting
Also,
in
our opinion, management’s assessment, included in Management’s Report on
Internal Control Over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as of
December 31, 2006 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, 2006,
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
February
28, 2007
48
BERRY
PETROLEUM COMPANY
Balance
Sheets
December
31, 2006 and 2005
(In
Thousands, Except Share Information)
| ASSETS | 2006 | 2005 | |||||||||||
|
Current
assets:
|
|||||||||||||
|
Cash
and cash equivalents
|
|
$
|
416
|
|
$
|
1,990
|
|
||||||
|
Short-term
investments
|
|
|
665
|
|
|
661
|
|
||||||
|
Accounts
receivable
|
|
|
67,905
|
|
|
59,672
|
|
||||||
|
Deferred
income taxes
|
|
|
-
|
|
|
4,547
|
|
||||||
|
Fair
value of derivatives
|
|
|
7,349
|
|
|
3,618
|
|
||||||
|
Assets
held for sale
|
8,870
|
-
|
|||||||||||
|
Prepaid
expenses and other
|
|
|
13,604
|
|
|
4,398
|
|
||||||
|
Total
current assets
|
|
|
98,809
|
|
|
74,886
|
|
||||||
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,080,631
|
|
|
552,984
|
|
||||||
|
Fair
value of derivatives
|
|
|
2,356
|
|
|
-
|
|
||||||
|
Long-term
deferred income taxes
|
-
|
1,600
|
|||||||||||
|
Other
assets
|
|
|
17,201
|
|
|
5,581
|
|
||||||
|
|
|
$
|
1,198,997
|
|
$
|
635,051
|
|
||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
||||||||
|
Current
liabilities:
|
|
|
|
|
|
||||||||
|
Accounts
payable
|
|
$
|
69,914
|
|
$
|
57,783
|
|
||||||
|
Property
acquisition payable
|
54,400
|
-
|
|||||||||||
|
Revenue
and royalties payable
|
|
|
45,845
|
|
|
34,920
|
|
||||||
|
Accrued
liabilities
|
|
|
20,415
|
|
|
8,805
|
|
||||||
|
Line
of credit
|
16,000
|
11,500
|
|||||||||||
|
Income
taxes payable
|
|
|
-
|
|
|
1,237
|
|
||||||
|
Deferred
income taxes
|
745
|
-
|
|||||||||||
|
Fair
value of derivatives
|
|
|
8,084
|
|
|
15,398
|
|
||||||
|
Total
current liabilities
|
|
|
215,403
|
|
|
129,643
|
|
||||||
|
Long-term
liabilities:
|
|
|
|
|
|
||||||||
|
Deferred
income taxes
|
|
|
103,515
|
|
|
55,804
|
|
||||||
|
Long-term
debt
|
|
|
390,000
|
|
|
75,000
|
|
||||||
|
Abandonment
obligation
|
|
|
26,135
|
|
|
10,675
|
|
||||||
|
Unearned
revenue
|
1,437
|
866
|
|||||||||||
|
Fair
value of derivatives
|
|
|
34,807
|
|
|
28,853
|
|
||||||
|
|
|
|
555,894
|
|
|
171,198
|
|
||||||
|
Commitments
and contingencies (Note 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, 100,000,000 shares authorized; 42,098,551 shares
issued
and outstanding (21,157,155 on a pre-split basis in 2005)
|
|
|
421
|
|
|
211
|
|
||||||
|
Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and
outstanding (liquidation preference of $899) (898,892 on a pre-split
basis
in 2005)
|
|
|
18
|
|
|
9
|
|
||||||
|
Capital
in excess of par value
|
|
|
50,166
|
|
|
56,064
|
|
||||||
|
Accumulated
other comprehensive loss
|
|
|
(19,977
|
)
|
|
(24,380
|
)
|
||||||
|
Retained
earnings
|
|
|
397,072
|
|
|
302,306
|
|
||||||
|
Total
shareholders' equity
|
|
|
427,700
|
|
|
334,210
|
|
||||||
|
|
|
$
|
1,198,997
|
|
$
|
635,051
|
|
||||||
The
accompanying notes are an integral part of these financial
statements.
49
BERRY
PETROLEUM COMPANY
Statements
of Income
Years
ended December 31, 2006, 2005 and 2004
(In
Thousands, Except Per Share Data)
|
2006
|
2005
(1)
|
2004
(1)
|
|||||||||||||||||||
|
REVENUES
|
|
|
|
|
|
|
|
||||||||||||||
| Sales of oil and gas | $ |
430,497
|
$
|
349,691
|
$ |
226,876
|
|||||||||||||||
|
Sales
of electricity
|
|
|
52,932
|
|
|
55,230
|
|
|
47,644
|
|
|||||||||||
|
Interest
and other income, net
|
|
|
2,909
|
|
|
1,804
|
|
|
426
|
|
|||||||||||
|
|
|
|
486,338
|
|
|
406,725
|
|
|
274,946
|
|
|||||||||||
|
EXPENSES
|
|
|
|
|
|
|
|
||||||||||||||
|
Operating
costs - oil and gas production
|
|
|
117,624
|
|
|
99,066
|
|
|
73,838
|
|
|||||||||||
|
Operating
costs - electricity generation
|
|
|
48,281
|
|
|
55,086
|
|
|
46,191
|
|
|||||||||||
|
Production
taxes
|
14,674
|
11,506
|
6,431
|
||||||||||||||||||
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
67,668
|
|
|
38,150
|
|
|
29,752
|
|
|||||||||||
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
3,343
|
|
|
3,260
|
|
|
3,490
|
|
|||||||||||
|
General
and administrative
|
|
|
36,841
|
|
|
21,396
|
|
|
22,504
|
|
|||||||||||
|
Interest
|
|
|
10,247
|
|
|
6,048
|
|
|
2,067
|
|
|||||||||||
|
Commodity
derivatives
|
(736)
|
-
|
-
|
||||||||||||||||||
|
Dry
hole, abandonment, impairment and exploration
|
|
|
12,009
|
|
|
9,354
|
|
|
1,155
|
|
|||||||||||
|
|
|
|
309,951
|
|
|
243,866
|
|
|
185,428
|
|
|||||||||||
|
Income
before income taxes
|
|
|
176,387
|
|
|
162,859
|
|
|
89,518
|
|
|||||||||||
|
Provision
for income taxes
|
|
|
68,444
|
|
|
50,503
|
|
|
20,331
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Net
income
|
|
$
|
107,943
|
|
$
|
112,
356
|
|
$
|
69,187
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Basic
net income per share
|
|
$
|
2.46
|
|
$
|
2.55
|
|
$
|
1.58
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Diluted
net income per share
|
|
$
|
2.41
|
|
$
|
2.50
|
|
$
|
1.54
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share)
|
|
|
43,948
|
|
|
44,082
|
|
|
43,788
|
|
|||||||||||
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
||||||||||||||
|
Stock
options
|
|
|
723
|
|
|
780
|
|
|
1,046
|
|
|||||||||||
|
Other
|
|
|
103
|
|
|
118
|
|
|
106
|
|
|||||||||||
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
44,774
|
|
|
44,980
|
|
|
44,940
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Statements
of Comprehensive Income
|
|
||||||||||||||||||||
|
Years
Ended December 31, 2006, 2005 and 2004
|
|||||||||||||||||||||
|
(In
Thousands)
|
|||||||||||||||||||||
|
Net
income
|
$ |
107,943
|
$ |
112,356
|
$ |
69,187
|
|||||||||||||||
|
Unrealized
gains (losses) on derivatives, net of income taxes of $7,647, ($16,677),
and ($521), respectively
|
|
|
11,471
|
|
(25,015
|
)
|
|
(781
|
)
|
||||||||||||
|
Reclassification
of realized gains (losses) included in net income net of income taxes
of
($4,712), $1,081 and $2,284, respectively
|
|
|
(7,068
|
)
|
|
1,622
|
|
|
3,426
|
|
|||||||||||
|
Comprehensive
income
|
|
$
|
112,346
|
|
$
|
88,963
|
|
$
|
71,832
|
|
|||||||||||
(1)
The
2004 and 2005 per share and share amounts have been restated to give retroactive
effect to the two-for-one stock split that became effective on May 17, 2006.
See
Note 7 to the financial statements.
The
accompanying notes are an integral part of these financial
statements.
50
BERRY
PETROLEUM COMPANY
Statements
of Shareholders’ Equity
Years
Ended December 31, 2006, 2005 and 2004
(In
Thousands, Except Per Share Data)
|
Class
A
|
Class
B
|
Capital
in Excess of Par Value
|
Deferred
Stock-Based Compensation
|
Retained
Earnings
|
Accumulated
Other Comprehensive
Income
(Loss)
|
Shareholders'
Equity
|
||||||||||||||||||||||||||||||||||
| Balances at January 1, 2004 | $ | 209 | $ | 9 | $ | 56,475 | $ | (1,108 |
)
|
$ | 145,385 | $ | (3,632 |
)
|
$ | 197,338 | ||||||||||||||||||||||||
|
Adoption
of SFAS 123
|
|
-
|
|
-
|
(243
|
)
|
1,108
|
|
-
|
|
-
|
|
865
|
|
||||||||||||||||||||||||||
|
Stock-based
compensation (310,538 shares)
|
|
1
|
|
-
|
3,451
|
|
-
|
|
-
|
|
-
|
|
3,452
|
|
||||||||||||||||||||||||||
|
Deferred
director fees - stock compensation
|
|
-
|
|
-
|
993
|
|
-
|
|
-
|
|
-
|
|
993
|
|
||||||||||||||||||||||||||
|
Cash
dividends declared - $.26 per share
|
|
-
|
|
-
|
-
|
|
-
|
|
(11,394
|
)
|
-
|
|
(11,394
|
)
|
||||||||||||||||||||||||||
|
Unrealized
gain on derivatives
|
|
-
|
|
-
|
-
|
|
-
|
|
-
|
|
2,645
|
|
2,645
|
|
||||||||||||||||||||||||||
|
Net
income
|
|
-
|
|
-
|
-
|
|
-
|
|
69,187
|
|
-
|
|
69,187
|
|
||||||||||||||||||||||||||
|
Balances
at December 31, 2004
|
|
210
|
|
9
|
60,676
|
|
-
|
|
203,178
|
|
(987
|
)
|
263,086
|
|
||||||||||||||||||||||||||
|
Shares
repurchased and retired (217,800 shares)
|
|
|
(2
|
)
|
-
|
(6,314
|
)
|
-
|
-
|
-
|
(6,316
|
)
|
||||||||||||||||||||||||||||
|
Stock-based
compensation (294,358 shares)
|
|
|
3
|
-
|
1,360
|
-
|
-
|
-
|
1,363
|
|||||||||||||||||||||||||||||||
|
Deferred
director fees - stock compensation
|
|
|
-
|
-
|
342
|
-
|
-
|
-
|
342
|
|||||||||||||||||||||||||||||||
|
Cash
dividends declared - $.30 per share
|
|
|
-
|
-
|
-
|
-
|
(13,228
|
)
|
-
|
(13,228
|
)
|
|||||||||||||||||||||||||||||
|
Unrealized
loss on derivatives
|
|
|
-
|
-
|
-
|
-
|
-
|
(23,393
|
)
|
(23,393
|
)
|
|||||||||||||||||||||||||||||
|
Net
income
|
|
|
-
|
-
|
-
|
-
|
112,356
|
-
|
112,356
|
|||||||||||||||||||||||||||||||
|
Balances
at December 31, 2005
|
|
211
|
9
|
56,064
|
-
|
302,306
|
(24,380
|
)
|
334,210
|
|||||||||||||||||||||||||||||||
|
Two-for
one stock split
|
211
|
9
|
(220
|
)
|
-
|
-
|
-
|
-
|
||||||||||||||||||||||||||||||||
|
Shares
repurchased and retired (600,200 shares)
|
|
|
(6
|
)
|
-
|
(18,713
|
)
|
-
|
-
|
-
|
(18,719
|
)
|
||||||||||||||||||||||||||||
|
Stock-based
compensation (498,939 shares)
|
|
|
5
|
-
|
12.700
|
-
|
-
|
-
|
12,705
|
|||||||||||||||||||||||||||||||
|
Deferred
director fees - stock compensation
|
|
|
-
|
-
|
335
|
-
|
-
|
-
|
335
|
|||||||||||||||||||||||||||||||
|
Cash
dividends declared - $.30 per share
|
|
|
-
|
-
|
-
|
-
|
(13,177
|
)
|
-
|
(13,177
|
)
|
|||||||||||||||||||||||||||||
|
Unrealized
gain on derivatives
|
|
|
-
|
-
|
-
|
-
|
-
|
4,403
|
4,403
|
|||||||||||||||||||||||||||||||
|
Net
income
|
|
|
-
|
-
|
-
|
-
|
107,943
|
-
|
107,943
|
|||||||||||||||||||||||||||||||
|
Balances
at December 31, 2006
|
|
$
|
421
|
$
|
18
|
$
|
50,166
|
$
|
-
|
$
|
397,072
|
$
|
(19,977
|
)
|
$
|
427,700
|
||||||||||||||||||||||||
The
accompanying notes are an integral part of these financial
statements.
51
BERRY
PETROLEUM COMPANY
Statements
of Cash Flows
Years
Ended December 31, 2006, 2005 and 2004
(In
Thousands)
| Cash flows from operating activities: | 2006 | 2005 | 2004 | ||||||||||||||||||
| Net income | $ | 107,943 | $ | 112,356 | $ | 69,187 | |||||||||||||||
|
Depreciation,
depletion and amortization
|
|
|
71,011
|
|
|
41,410
|
|
|
33,242
|
|
|||||||||||
|
Dry
hole
|
|
|
8,253
|
|
5,705
|
|
745
|
||||||||||||||
|
Abandonment
and impairment
|
606
|
(1,381
|
)
|
(1,314
|
)
|
||||||||||||||||
|
Commodity
derivatives
|
(109
|
)
|
-
|
-
|
|||||||||||||||||
|
Stock-based
compensation expense, net of taxes
|
|
|
6,436
|
|
1,703
|
|
|
5,309
|
|
||||||||||||
|
Deferred
income taxes, net
|
|
|
51,666
|
|
20,847
|
|
|
10,815
|
|
||||||||||||
|
Other,
net
|
|
|
447
|
|
278
|
|
|
794
|
|
||||||||||||
|
Increase
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
(16,338
|
)
|
|
(26,717
|
)
|
|
(11,310
|
)
|
|||||||||||
|
Increase
in current liabilities other than line of credit
|
|
|
13,314
|
|
33,579
|
|
|
17,145
|
|
||||||||||||
|
Net
cash provided by operating activities
|
|
|
243,229
|
|
187,780
|
|
|
124,613
|
|
||||||||||||
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
||||||||||||||
|
Exploration
and development of oil and gas properties
|
|
|
(265,110
|
)
|
|
(118,718
|
)
|
|
(71,556
|
)
|
|||||||||||
|
Property
acquisitions
|
|
|
(257,840
|
)
|
|
(112,249
|
)
|
|
(2,845
|
)
|
|||||||||||
|
Additions
to vehicles, drilling rigs and other fixed assets
|
(21,306
|
)
|
(11,762
|
)
|
(669
|
)
|
|||||||||||||||
|
Capitalized
interest
|
(9,339
|
)
|
-
|
-
|
|||||||||||||||||
|
Deposits
on potential acquisitions
|
|
|
-
|
|
-
|
|
(10,221
|
)
|
|||||||||||||
|
Proceeds
from sale of assets
|
|
|
4,812
|
|
130
|
|
|
101
|
|
||||||||||||
|
Other,
net
|
|
|
-
|
|
-
|
|
|
3
|
|
||||||||||||
|
Net
cash used in investing activities
|
|
|
(548,783
|
)
|
|
(242,599
|
)
|
|
(85,187
|
)
|
|||||||||||
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
||||||||||||||
|
Proceeds
from issuance of line of credit
|
327,250
|
18,000
|
-
|
||||||||||||||||||
|
Payment
of line of credit
|
(322,750
|
)
|
(6,500
|
)
|
-
|
||||||||||||||||
|
Proceeds
from issuance of long-term debt
|
|
|
569,700
|
|
144,000
|
|
|
-
|
|
||||||||||||
|
Payment
of long-term debt
|
|
|
(254,700
|
)
|
|
(97,000
|
)
|
|
(22,000
|
)
|
|||||||||||
|
Dividends
paid
|
|
|
(13,177
|
)
|
|
(13,228
|
)
|
|
(11,394
|
)
|
|||||||||||
|
Book
overdraft
|
15,246
|
1,921
|
-
|
||||||||||||||||||
|
Repurchase
of shares
|
(18,713
|
)
|
(6,315
|
)
|
-
|
||||||||||||||||
|
Proceeds
from stock option exercises
|
3,156
|
-
|
-
|
||||||||||||||||||
|
Excess
tax benefit
|
3,444
|
-
|
-
|
||||||||||||||||||
|
Debt
issuance cost
|
|
|
(5,476
|
)
|
(759
|
)
|
-
|
||||||||||||||
|
Net
cash provided by (used in) financing activities
|
|
|
303,980
|
|
40,119
|
|
(33,394
|
)
|
|||||||||||||
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
(1,574
|
)
|
|
(14,700
|
)
|
|
6,032
|
|
|||||||||||
|
Cash
and cash equivalents at beginning of year
|
|
|
1,990
|
|
|
16,690
|
|
|
10,658
|
|
|||||||||||
|
Cash
and cash equivalents at end of year
|
|
$
|
416
|
|
$
|
1,990
|
|
$
|
16,690
|
|
|||||||||||
|
Supplemental
disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Interest
paid
|
|
$
|
15,019
|
|
$
|
5,275
|
|
$
|
1,243
|
|
|||||||||||
|
Income
taxes paid
|
|
$
|
18,148
|
|
$
|
26,544
|
|
$
|
11,652
|
|
|||||||||||
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Current
(net of income taxes of $4,188, ($3,631), and $1,202,
respectively)
|
|
$
|
6,282
|
|
$
|
(5,446
|
)
|
$
|
1,804
|
||||||||||||
|
Non-current
(net of income taxes of ($1,252), ($11,965), and $561,
respectively)
|
|
|
(1,879
|
)
|
|
(17,947
|
)
|
|
841
|
||||||||||||
| Net increase (decrease) to accumulated other comprehensive income | $ |
4,403
|
$ | (23,393 | ) | $ | 2,645 | ||||||||||||||
| Non-cash financing activity: Property acquired for debt | $ | 54,000 | $ | - | $ | - |
The
accompanying notes are an integral part of these financial
statements.
52
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
1. General
We
are an
independent energy company engaged in the production, development, acquisition,
exploitation and exploration of crude oil and natural gas. We have 66% of our
oil and gas reserves in California and 34% in the Rocky Mountain/Mid-Continent
region. Approximately 63% of our production is in California, most of which
is
heavy crude oil and is sold to a Bakersfield, California refinery. We have
invested in cogeneration facilities which provide steam required for the
extraction of heavy oil and which generates electricity for sale. Production
of
light crude oil and natural gas in the Rocky Mountain/Mid-Continent region
accounts for approximately 37% of our production.
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
2. Summary
of Significant Accounting Policies
Cash
and cash equivalents
- We
consider all highly liquid investments purchased with a remaining maturity
of
three months or less to be cash equivalents. Our cash management process
provides for the daily funding of checks as they are presented to the bank.
Included in accounts payable at December 31, 2006 is $17.2 million representing
outstanding checks in excess of the bank balance (book overdraft).
Short-term
investments
-
Short-term investments consist principally of United States treasury notes
and
corporate notes with remaining maturities of more than three months at date
of
acquisition and are carried at fair value. We utilize specific identification
in
computing realized gains and losses on investments sold.
Accounts
receivable
-
Trade
accounts receivable are recorded at the invoiced amount. We do not have any
off-balance-sheet credit exposure related to our customers. We assess credit
risk and allowance for doubtful accounts on a customer specific basis. As of
December 31, 2006 and 2005, we do not have an allowance for doubtful
accounts.
Income
taxes
-
Income
taxes are provided based on the liability method of accounting. The provision
for income taxes is based on reported pre-tax financial statement income.
Deferred tax assets and liabilities are recognized for the future expected
tax
consequences of temporary differences between income tax and financial
reporting, and principally relate to differences in the tax bases of assets
and
liabilities and their reported amounts using enacted tax rates in effect for
the
year in which differences are expected to reverse. If it is more likely than
not
that some portion or all of a deferred tax asset will not be realized, a
valuation allowance is recognized.
Derivatives
-
To
minimize the effect of a downturn in oil and gas prices and protect our
profitability and the economics of our development plans, from time to time
we
enter into crude oil and natural gas hedge contracts. SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities,
as
amended, requires that all derivative instruments subject to the requirements
of
the statement be measured at fair value and recognized as assets or liabilities
in the balance sheet. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation is generally established at the inception of a derivative. For
derivative contracts that do not qualify for hedge accounting under SFAS No.
133
the contracts are recorded at fair value on the balance sheet with the
corresponding unrealized gain or loss on the income statement under the caption
“Commodity derivatives.” For derivatives designated as cash flow hedges and
meeting the effectiveness guidelines of SFAS No. 133, changes in fair value,
to
the extent effective, are recognized in other comprehensive income until the
hedged item is recognized in earnings. The hedging relationship between the
hedging instruments and hedged items, such as oil and gas, must be highly
effective in achieving the offset of changes in cash flows attributable to
the
hedged risk, both at the inception of the hedge and on an ongoing basis. We
measure hedge effectiveness at least quarterly based on the relative changes
in
fair value between the derivative contract and the hedged item over time, or
in
the case of options based on the change in intrinsic value. A regression
analysis is used to determine whether the relationship is considered to be
highly effective retrospectively and prospectively. Actual effectiveness of
the
hedge will be calculated against the underlying cumulatively using the
dollar offset method at the end of each quarter. Any change in fair value of
a
derivative resulting from ineffectiveness or an excluded component of the
gain/loss, such as time value for option contracts, is recognized immediately
in
the statements of income. Gains and losses on hedging instruments and
adjustments of the carrying amounts of hedged items are included in revenues
for
hedges related to our crude oil and natural gas sales and in operating expenses
for hedges related to our natural gas consumption. The resulting cash flows
are
reported as cash flows from operating
53
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
activities.
See Note 15 - Hedging.
Assets
held for sale -
We
consider an asset to be held for sale when management approves and commits
to a
formal plan to actively market a business for sale. Upon designation as held
for
sale, the carrying value of the asset is recorded at the lower of the carrying
value or its estimated fair value, less costs to sell. Once
an
asset is determined to be “held for sale”, we no longer record DD&A on the
property. We anticipate that we will dispose of certain properties or assets
over time. The assets most likely for disposition will be those that do not
fit
or complement our strategic growth plan, that are not contributing satisfactory
economic returns given the profile of the assets, or that we believe the
development potential will not be meaningful to our company as a whole. We
have
identified several assets that fit our criteria and expect to divest of these
assets in 2007. Proceeds from these sales will contribute to the funding of
our
capital program. Net
oil
and gas properties and equipment classified as held for sale is $8.9 million
for
the year ended December 31, 2006 in accordance with SFAS No.
144.
Leases
receivable
-
We
entered into two separate three year lease agreements on two company owned
drilling rigs. Each agreement has a three year purchase option in favor of
the
lessee. The agreements were signed in the third and second quarters of 2005
and
2006, respectively. Both agreements are accounted for as direct financing leases
as defined by SFAS No. 13,
Accounting for Leases, and
included in other long term assets on the balance sheet.
Oil
and gas properties, buildings and equipment
-
We
account for our oil and gas exploration and development costs using the
successful efforts method. Geological and geophysical costs and the costs of
carrying and retaining undeveloped properties are expensed as incurred.
Exploratory well costs are capitalized pending further evaluation of whether
economically recoverable reserves have been found. If economically recoverable
reserves are not found, exploratory well costs are expensed as dry holes. All
exploratory wells are evaluated for economic viability within one year of well
completion and the related capitalized costs are reviewed quarterly. Exploratory
wells that discover potentially economic reserves that are in areas where a
major capital expenditure would be required before production could begin,
and
where the economic viability of that major capital expenditure depends upon
the
successful completion of further exploratory work in the area, remain
capitalized if the well found a sufficient quantity of reserves to justify
its
completion as a producing well and we are making sufficient progress assessing
the reserves and the economic and operating viability of the project. The costs
of development wells are capitalized whether productive or
nonproductive.
Depletion
of oil and gas producing properties is computed using the units-of-production
method. Depreciation of lease and well equipment, including cogeneration
facilities and other steam generation equipment and facilities, is computed
using the units-of-production method or on a straight-line basis over estimated
useful lives ranging from 10 to 20 years. Buildings and equipment are recorded
at cost. Depreciation is provided on a straight-line basis over estimated useful
lives ranging from 5 to 30 years for buildings and improvements and 3 to 10
years for machinery and equipment. Estimated residual salvage value is
considered when determining depreciation, depletion and amortization (DD&A)
rates.
In
accordance with SFAS
No.
144,
Accounting
for the Impairment or Disposal of Long-Lived Assets,
we
group assets at the field level and periodically review the carrying value
of
our property and equipment to test whether current events or circumstances
indicate that such carrying value may not be recoverable. If the tests indicate
that the carrying value of the asset is greater than the estimated future
undiscounted cash flows to be generated by such asset, then an impairment
adjustment needs to be recognized. Such adjustment consists of the amount by
which the carrying value of such asset exceeds its fair value. We generally
measure fair value by considering sale prices for similar assets or by
discounting estimated future cash flows from such asset using an appropriate
discount rate. Considerable management judgment is necessary to estimate the
fair value of assets, and accordingly, actual results could vary significantly
from such estimates. When assets are sold, the applicable costs and accumulated
depreciation and depletion are removed from the accounts and any gain or loss
is
included in income. Expenditures for maintenance and repairs are expensed as
incurred.
Asset
retirement obligations
-
We
have
significant obligations to plug and abandon oil and natural gas wells and
related equipment at the end of oil and gas production operations. The
computation of our ARO is prepared in accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations.
Under
this standard, we record the fair value of the future abandonment as capitalized
abandonment costs in Oil and Gas Properties with an offsetting abandonment
liability. We obtain estimates from third parties and use the present value
of
estimated cash flows related to its ARO to determine the fair value. The
capitalized abandonment costs are amortized with other property costs using
the
units-of-production method. We increase the liability monthly by recording
accretion expense using our credit adjusted interest rate. Accretion expense
is
included in DD&A in our financial statements.
54
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Revenue
recognition
-
Revenues
associated with sales of crude oil, natural gas, and electricity are recognized
when title passes to the customer, net of royalties, discounts and allowances,
as applicable. Electricity and natural gas produced by us and used in our
operations are not included in revenues. Revenues from crude oil and natural
gas
production from properties in which we have an interest with other producers
are
recognized on the basis of our net working interest (entitlement
method).
Conventional
steam costs
-
The
costs
of producing conventional steam are included in “Operating costs - oil and gas
production.”
Cogeneration
operations
-
Our
investment in cogeneration facilities has been for the express purpose of
lowering steam costs in our heavy oil operations and securing operating control
of the respective steam generation. Such cogeneration operations produce
electricity and steam. We allocate steam costs to our oil and gas operating
costs based on the conversion efficiency of the cogeneration facilities plus
certain direct costs in producing steam. Electricity revenue represents sales
to
the utilities. Electricity used in oil and gas operations is allocated at cost.
Electricity consumption included in oil and gas operating costs for the years
ended December 31, 2006, 2005 and 2004 was $5.3 million, $5.7 million and $5
million, respectively.
Shipping
and handling costs
-
Shipping
and handling costs, which consist primarily of natural gas transportation costs,
are included in either "Operating costs - oil and gas production" or "Operating
costs - electricity generation,” as applicable. Natural gas transportation costs
included in these categories were $6.8 million, $5.8 million and $5.4 million,
for 2006, 2005 and 2004, respectively. Additionally, the transportation costs
in
the Uinta basin were first incurred in 2006 and were $1.1 million.
Production
taxes
-
Consist
primarily of severance, production and ad valorem taxes.
Stock-based
compensation
-
We
adopted SFAS No. 123(R) beginning January 1, 2006. We previously adopted
the fair value recognition provisions of SFAS No. 123, Accounting
for Stock-Based Compensation
effective January 1, 2004. The primary difference between the standards was
the
accounting for the excess tax benefit, as the difference between the stock
option grant price and the exercise price. The implementation of FAS123(R)
did
not have a material impact on us. We voluntarily adopted the fair value method
of accounting for our stock option plan as prescribed by SFAS 123. The modified
prospective method was selected as described in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, we recognize stock option compensation expense as if it had applied
the fair value method to account for unvested stock options from its original
effective date. Stock option compensation expense is recognized from the date
of
grant to the vesting date.
From
January 1, 2004 to July 29, 2004 a minor portion of our stock option
compensation was calculated under variable accounting. In accordance with
variable plan accounting, we recognized a corresponding liability determined
by
a marked-to-market valuation of our stock at each financial reporting date.
On
July 29, 2004, we revised certain stock option exercise provisions of the plan
and therefore variable plan accounting was no longer required.
Comprehensive
income (loss)
-
Comprehensive
income (loss) includes net income (loss) as well as unrealized gains and losses
on derivative instruments, recorded net of tax.
Net
income per share
-
Basic
net
income per share is computed by dividing income available to shareholders (the
numerator) by the weighted average number of shares of capital stock outstanding
(the denominator). Our Class B Stock is included in the denominator of basic
and
diluted net income. The computation of diluted net income per share is similar
to the computation of basic net income per share except that the denominator
is
increased to include the dilutive effect of the additional common shares that
would have been outstanding if all convertible securities had been converted
to
common shares during the period.
Environmental
expenditures
-
We
review, on a quarterly basis, our estimates of costs of the cleanup of various
sites, including sites in which governmental agencies have designated us as
a
potentially responsible party. When it is probable that obligations have been
incurred and where a minimum cost or a reasonable estimate of the cost of
compliance or remediation can be determined, the applicable amount is accrued.
For other potential liabilities, the timing of accruals coincides with the
related ongoing site assessments. Any liabilities arising hereunder are not
discounted.
55
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
Accounting
for business combinations
- We
have accounted for all of our business combinations using the purchase method,
which is the only method permitted under SFAS 141, Accounting
for Business Combinations.
Under
the purchase method of accounting, a business combination is accounted for
at a
purchase price based upon the fair value of the consideration given, whether
in
the form of cash, assets, stock or the assumption of liabilities. The assets
and
liabilities acquired are measured at their fair values, and the purchase price
is allocated to the assets and liabilities based upon these fair values. The
excess of the fair value of assets acquired and liabilities assumed over the
cost of an acquired entity, if any, is allocated as a pro rata reduction of
the
amounts that otherwise would have been assigned to certain acquired assets.
We
have not recognized any goodwill from any business combinations.
Capitalized
interest
-
Interest incurred on funds borrowed to finance exploration and certain
acquisition and development activities is capitalized. To qualify for interest
capitalization, the costs incurred must relate to the acquisition of unproved
reserves, drilling of wells to prove up the reserves and the installation of
the
necessary pipelines and facilities to make the property ready for production.
Such capitalized interest is included in oil and gas properties, buildings
and
equipment. Capitalized interest is amortized over the estimated life of the
respective project.
Recent
accounting developments
-
In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. In
April 2005, the SEC issued a rule that SFAS No. 123(R) would be
effective for annual reporting periods beginning on or after June 15, 2005.
As a result, we adopted this statement beginning January 1, 2006. We
previously adopted the fair value recognition provisions of SFAS No. 123,
Accounting
for Stock-Based Compensation.
Accordingly, the adoption of SFAS No. 123(R) using the modified prospective
method did not have a material impact on our condensed financial statements
for
the year ended December 31, 2006.
In
May 2005, SFAS No. 154, Accounting
Changes and Error Corrections,
a
replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued.
SFAS No. 154 requires retrospective application to prior period financial
statements for changes in accounting principle, unless it is impractical to
determine either the period-specific effects or the cumulative effect of the
change. SFAS No. 154 also requires that retrospective application of a
change in accounting principle be limited to the direct effects of the change.
Indirect effects of a change in accounting principle should be recognized in
the
period of the accounting change. SFAS No. 154 became effective for our
fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will
depend on the nature and extent of any voluntary accounting changes and
correction of errors after the effective date.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for our fiscal year beginning after September
15,
2006. While we determined there was no impact on our financial statements as
of
December 31, 2006, based on our existing derivatives, we may experience a
financial impact depending on the nature and extent of any new derivative
instruments entered into after the effective date of SFAS No. 155.
In
June
2006, the FASB issued Interpretation (FIN) No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109.
This
interpretation requires that realization of an uncertain income tax position
must be “more likely than not” (i.e. greater than 50% likelihood of receiving a
benefit) before it can be recognized in the financial statements. Further,
this
interpretation prescribes the benefit to be recorded in the financial statements
as the amount most likely to be realized assuming a review by tax authorities
having all relevant information and applying current conventions. This
interpretation also clarifies the financial statement classification of
tax-related penalties and interest and sets forth new disclosures regarding
unrecognized tax benefits. This interpretation is effective for fiscal years
beginning after December 15, 2006, and we will be required to adopt this
interpretation in the first quarter of 2007. Based on our evaluation as of
December 31, 2006, we do not believe that the implementation of FIN 48 will
have
a material impact on our financial statements.
56
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
2. Summary
of Significant Accounting Policies (Cont'd)
In
September 2006, Statement of Financial Accounting Standards (SFAS) No. 157,
Fair
Value Measurements was
issued by the Financial Accounting Standards Board (FASB). This statement
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. SFAS No. 157 will become
effective for our fiscal year beginning January 1, 2008, and we are currently
assessing the potential impact of this Statement on our financial
statements.
In
September 2006, Staff Accounting Bulletin (“SAB”) No. 108,
Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements.
Registrants must quantify the impact on current period financial statements
of
correcting all misstatements, including both those occurring in the current
period and the effect of reversing those that have accumulated from prior
periods. This SAB was adopted at December 31, 2006. The adoption of
SAB No. 108 had no effect on our financial position or on the results
of our operations.
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities,
which
permits an entity to measure certain financial assets and financial liabilities
at fair value. The objective of SFAS No. 159 is to improve financial reporting
by allowing entities to mitigate volatility in reported earnings caused by
the
measurement of related assets and liabilities using different attributes,
without having to apply complex hedge accounting provisions. Under SFAS No.
159,
entities that elect the fair value option (by instrument) will report unrealized
gains and losses in earnings at each subsequent reporting date. The fair value
option election is irrevocable, unless a new election date occurs. SFAS No.
159
establishes presentation and disclosure requirements to help financial statement
users understand the effect of the entity’s election on its earnings, but does
not eliminate disclosure requirements of other accounting standards. Assets
and
liabilities that are measured at fair value must be displayed on the face of
the
balance sheet. This statement is effective beginning January 1, 2008 and we
are
evaluating this pronouncement.
3. Fair
Value of Financial Instruments
Cash
equivalents consist principally of commercial paper investments. Cash and
equivalents of $.4 million and $2 million at December 31, 2006 and 2005,
respectively, are stated at cost, which approximates market.
Our
short-term investments available for sale at December 31, 2006 and 2005 consist
of United States treasury notes that mature in less than one year and are
carried at fair value. For the three years ended December 31, 2006, realized
and
unrealized gains and losses of our short-term investments were insignificant
to
the financial statements. A United States treasury note with a market value
of
$.7 million is pledged as collateral to the California State Lands Commission
as
a performance bond on our Montalvo properties. The carrying value of our
long-term debt approximates its fair value.
4. Concentration
of Credit Risks
We
sell
oil, gas and natural gas liquids to pipelines, refineries and oil companies
and
electricity to utility companies. Credit is extended based on an evaluation
of
the customer’s financial condition and historical payment
record.
Because
of our ability to deliver significant volumes of crude oil over a multi-year
period, we are able to secure oil sales contracts at market or better
terms.
On
November 21, 2005, we entered into a new crude oil sales contract for our
California production (approximately 16,000 Bbl/D) for deliveries beginning
February 1, 2006 with an independent refiner. Due to the substantial estimated
revenue of this contract we were able to obtain financial assurance of payment
through a sizable parent guarantee.
On
February 27, 2007, we entered into a multi-staged crude oil sales contract
with
a subsidiary of Holly Corporation (Holly) for our Uinta basin crude oil. Under
the agreement, Holly will begin purchasing 3,200 gross Bbl/D beginning July
1,
2007. Upon completion of their Woods Cross refinery expansion in Salt Lake
City,
which is expected in mid 2008, Holly will increase their total purchased volumes
to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes
transportation, is a fixed percentage of WTI and approximates our expected
field
posted price of $13 to $16 below WTI.
57
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
4. Concentration
of Credit Risks (Cont’d)
For
the
three years ended December 31, 2006, we have experienced no credit losses on
the
sale of oil, gas or natural gas liquids. We place our temporary cash investments
with high quality financial institutions and limit the amount of credit exposure
to any one financial institution. For the three years ended December 31, 2006,
we have not incurred losses related to these investments. With respect to our
hedging activities, we utilize more than one counterparty on our hedges and
monitor each counterparty’s credit rating.
The
following summarizes the accounts receivable balances at December 31, 2006
and
2005 and sales activity with significant customers for each of the years ended
December 31, 2006, 2005 and 2004 (in thousands). We do not believe that the
loss
of any one customer would impact the marketability, but may impact the
profitability of our California crude oil, gas, natural gas liquids or
electricity sold.
Due to
the possibility of refinery constraints in the Utah region, it is possible
that
the loss of the crude oil sales customer under our February 27, 2007 contract
or
our current contracts could impact the marketability of a portion of our Utah
crude oil volumes.
|
|
|
Accounts
Receivable
|
|
Sales
|
|
||||||||||||||||||||||||||||
|
|
|
As
of December 31,
|
|
For
the Year Ended December 31,
|
|
||||||||||||||||||||||||||||
|
Customer
|
2006
|
2005
|
2006
|
2005
|
2004
|
||||||||||||||||||||||||||||
|
Oil
& Gas Sales:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||
|
A
|
$ | - | $ | 24,389 | $ | - | $ | 291,093 | $ | 202,966 | |||||||||||||||||||||||
|
B
|
|
|
2,732
|
|
|
6,929
|
|
|
75,597
|
|
|
81,342
|
|
|
58,807
|
|
|||||||||||||||||
|
C
|
1,136
|
-
|
14,391
|
-
|
-
|
||||||||||||||||||||||||||||
|
D
|
28,768
|
-
|
305,587
|
-
|
-
|
||||||||||||||||||||||||||||
|
E
|
|
|
2,246
|
|
|
1,086
|
|
|
19,462
|
|
|
11,863
|
|
|
9,138
|
|
|||||||||||||||||
|
|
|
$
|
34,882
|
|
$
|
32,404
|
|
$
|
415,037
|
|
$
|
384,298
|
|
$
|
270,911
|
|
|||||||||||||||||
|
Electricity
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||
|
F
|
|
$
|
4,279
|
|
$
|
4,375
|
|
$
|
24,335
|
|
$
|
24,391
|
|
$
|
21,755
|
|
|||||||||||||||||
|
G
|
|
|
5,658
|
|
|
7,806
|
|
|
28,597
|
|
|
30,893
|
|
|
26,524
|
|
|||||||||||||||||
|
|
|
$
|
9,937
|
|
$
|
12,181
|
|
$
|
52,932
|
|
$
|
55,284
|
|
$
|
48,279
|
|
|||||||||||||||||
Sales
amounts will not agree to the Statements of Income due primarily to the effects
of hedging and price sensitive royalties paid on a portion of our crude oil
sales, which are netted in “Sales of oil and gas” on the Statements of
Income.
58
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment
Oil
and
gas properties, buildings and equipment consist of the following at December
31
(in thousands):
|
2006
|
2005
|
||||||||||||||
|
Oil
and gas:
|
|
|
|
|
|
||||||||||
|
Proved
properties:
|
|
|
|
|
|
||||||||||
| Producing properties, including intangible drilling costs | $ | 649,928 | $ | 437,032 | |||||||||||
|
Lease
and well equipment (1)
|
|
|
358,392
|
|
|
275,346
|
|
||||||||
|
|
|
|
1,008,320
|
|
|
712,378
|
|
||||||||
|
Unproved
properties
|
|
|
|
|
|
||||||||||
|
Properties,
including intangible drilling costs
|
|
|
309,959
|
|
|
36,440
|
|
||||||||
|
Lease
and well equipment
|
|
|
25
|
|
|
267
|
|
||||||||
|
|
|
|
309,984
|
|
|
36,707
|
|
||||||||
|
|
|
|
1,318,304
|
|
|
749,085
|
|
||||||||
|
Less
accumulated depreciation, depletion and amortization
|
|
|
258,466
|
|
|
208,597
|
|
||||||||
|
|
|
|
1,059,838
|
|
|
540,488
|
|
||||||||
|
Commercial
and other:
|
|
|
|
|
|
||||||||||
|
Land
|
|
|
774
|
|
|
496
|
|
||||||||
|
Drilling
rigs and equipment
|
10,478
|
-
|
|||||||||||||
|
Buildings
and improvements
|
|
|
5,596
|
|
|
4,351
|
|
||||||||
|
Machinery
and equipment
|
|
|
16,025
|
|
|
17,016
|
|
||||||||
|
|
|
|
32,873
|
|
|
21,863
|
|
||||||||
|
Less
accumulated depreciation
|
|
|
12,080
|
|
|
9,367
|
|
||||||||
|
|
|
|
20,793
|
|
|
12,496
|
|
||||||||
|
|
|
$
|
1,080,631
|
|
$
|
552,984
|
|
||||||||
|
(1)
Includes
cogeneration facility costs.
|
|
|
|
|
|
|
|
||||||||
In
February 2006, we closed on an agreement with a private seller to acquire a
50%
working interest in natural gas assets in the Piceance basin of western Colorado
for approximately $159 million. The acquisition was funded under our existing
credit facility. We purchased 100% of Piceance Operating Company LLC (which
owned a 50% working interest in the acquired assets). The total purchase price
was allocated as follows: $30 million to proved reserves and $129 million to
unproved properties. Allocation was made based on fair value. The historical
operating activities of these oil and gas assets are insignificant compared
to
our historical operations and therefore we have not included proforma
disclosures. Piceance
Operating Company LLC was dissolved subsequent to the acquisition.
In
June
2006, we entered into an agreement with a party to jointly develop the North
Parachute Ranch property in the Grand Valley field of the Piceance basin of
western Colorado. We estimate we will pay up to $153 million to fund the
drilling of 90 natural gas wells on the joint venture partner’s acreage. The
maximum amount of cost charged to us will not exceed $1.7 million per well.
If
any wells are drilled for less than $1.7 million, the excess will be returned
to
us. In exchange for our payments of up to $153 million, we will earn a 5%
working interest (4% net revenue interest) on each of the 90 wellbores and
a net
working interest of 95% (79% net revenue interest) in 4,300 gross acres located
elsewhere on the property. The costs of drilling and development on the 4,300
gross acres will be shared by the partners in relation to the working interests.
The $153 million payment was allocated to unproved properties based on the
fair
value of the 5% and 95% working interests.
59
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
In
July
2006, we paid $51 million, which was the first installment of the total $153
million and thereby earned the assignment of the 4,300 gross acres. On November
1, 2006, we paid the second installment of approximately $50 million. We plan
to
pay the third installment of approximately $54 million on May 1, 2007. Prior
to
2010 we are required to drill 120 wells, bearing 95% of the cost, on our 4,300
gross acres and if not met, then we are required to pay $.2 million for each
well less than 120 drilled. Additionally, if we have not drilled at least one
well by mid-2011 in each 160 acre tract within the 4,300 gross acres, then
that
specific undrilled 160 acre tract shall be reassigned to the joint venture
partner. At the date of the agreement there were no operating activities from
these gas assets.
In
2005,
we made three acquisitions for approximately $111 million establishing a core
area in the Tri-State region (Eastern Colorado, western Kansas and southwestern
Nebraska) totaling approximately 100,000 net producing acres and 315,000 net
total acres. Our primary acquisition was the Niobrara gas producing assets
in
Yuma County in northeastern Colorado in which we have a working interest of
approximately 52%. Our other two acquisitions in the region consisted of
undeveloped prospective acreage where our working interests range from 40%
to
50%.
In
2005,
we completed several transactions whereby we now have working interests in
186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota.
These lease acquisitions, totaling approximately $11 million, cover several
contiguous blocks located primarily on the eastern flank of the Nesson
Anticline.
In
July
2004, we purchased approximately 169,000 gross acres with an industry partner
in
the Lake Canyon prospect in Utah, of which 124,500 gross (62,250 net) acres
are
leased from the Ute Tribe and 44,500 gross (22,250 net) acres are fee lands.
Total cost to us was approximately $2 million. We will drill and operate shallow
wells which target light oil in the Green River formation and retain a 75%
working interest. Our partner will drill and operate deeper wells and we will
retain a 25% working interest. The Ute Tribe has the option to participate
in
all wells and retain up to a 25% working interest. As of December 31, 2006,
our
minimum obligation under our agreement is $9.6 million through 2009.
On
January 27, 2005, we acquired certain interests in the Niobrara field in
northeastern Colorado for approximately $105 million (J-W Acquisition) to
increase natural gas reserves and production. Assets purchased include $93
million of gas properties, $6 million of pipeline, and $5 million of compression
equipment. Liabilities assumed included $1 million of asset retirement
obligations.
The
pro
forma results presented below for the year ended December 31, 2005 and 2004
have
been prepared to report the effect of the J-W Acquisition on our results of
operations under the purchase method of accounting as if it had been consummated
on January 1, 2004. The pro forma results do not purport to represent the
results of operations that actually would have occurred on such date or to
project our results of operations for any future date or period. The following
show the results (in thousands, except per share data):
|
2005
|
2004
|
||||
|
Proforma
Revenue
|
$
408,088
|
$
295,243
|
|||
|
Proforma
Income from operations
|
190,970
|
121,688
|
|||
|
Proforma
Net income
|
112,660
|
72,393
|
|||
|
Proforma
Basic earnings per share
|
5.11
|
3.31
|
|||
|
Proforma
Diluted earnings per share
|
5.01
|
3.22
|
|||
60
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
5. Oil
and Gas Properties, Buildings and Equipment (Cont'd)
Suspended
Well Costs
The
following table provides an aging of capitalized exploratory well costs based
on
the date the drilling was completed and the number of wells for which
exploratory well costs have been capitalized for a period of greater than one
year since the completion of drilling (in thousands, except number of
projects):
| 2006 | 2005 | 2004 | |||||||||||||||||||
| Capitalized exploratory well costs that have been capitalized for a period of one year or les | $ | 89 | $ | 6,037 | $ | 2,941 | |||||||||||||||
|
Capitalized
exploratory well costs that have been capitalized for a period greater
than one year
|
|
-
|
|
|
-
|
|
|
511
|
|
||||||||||||
|
Balance
at December 31
|
|
$
|
89
|
|
$
|
6,037
|
|
$
|
3,452
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Number
of projects that have exploratory well costs that have been capitalized
for a period of greater than one year
|
|
|
-
|
|
|
-
|
|
|
1
|
|
The
following table reflects the net changes in capitalized exploratory well costs
(in thousands):
| 2006 | 2005 | 2004 | |||||||||||||||||||
| Beginning balance at January 1 | $ | 6,037 | $ | 3,452 | $ | 511 | |||||||||||||||
|
Additions
to capitalized exploratory well costs pending the determination of
proved
reserves
|
|
6,682
|
|
|
8,840
|
|
|
3,420
|
|
||||||||||||
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved
reserves
|
|
(4,377
|
)
|
|
(3,369
|
)
|
|
-
|
|
||||||||||||
|
Capitalized
exploratory well costs charged to expense
|
|
(8,253
|
)
|
|
(2,886
|
)
|
|
(479
|
)
|
||||||||||||
|
Ending
balance at December 31
|
|
$
|
89
|
$
|
6,037
|
|
$
|
3,452
|
|
In
2004,
included in the amount of exploratory well costs that have been capitalized
for
a period of greater than one year since completion of drilling are costs of
$.5
million that have been capitalized since 2003. These costs are related to our
diatomite project in the Midway-Sunset field and have been reclassified from
exploratory well costs to productive property in 2005.
Dry
hole, abandonment and impairment
Reflected
on our year ended 2006 income statement under the dry hole, abandonment and
impairment line, there is $8.3 million that consists primarily of two Coyote
Flats, Utah wells for $5.2 million, our 25% share in an exploration well located
in the Lake Canyon project area of the Uinta basin drilled for approximately
$1.6 million net to our interest and four wells in Bakken and four wells in
Tri-State for $1.5 million.
For
the
year ended 2005, costs of $5.7 million which were incurred on one exploratory
well on the Coyote Flats prospect, the Midway-Sunset property, two exploratory
wells at northern Brundage Canyon, and impairment of $2.5 million on the
remaining carrying value of our Illinois and eastern Kansas prospective CBM
acreage were charged to expense. During 2004, we recorded costs of $.7 million
on exploratory wells on the Midway-Sunset property and the Coyote Flats
prospect.
6. Long-term
and Short-term Debt Obligations
Long-term
debt
In
October 2006, we issued in a public offering $200 million of 8.25% senior
subordinated notes due 2016. The deferred costs of approximately $5 million
associated with the issuance of this debt are being amortized over the ten
year
life of the bonds. The net proceeds from the offering were used to 1) repay
approximately $145 million of borrowings under the bank credit facility, which
were $170 million as of the issuance date after the application of this
payment and 2) approximately $50 million was used to finance the November 1,
2006 installment under the joint venture agreement to develop properties in
the
Piceance basin.
61
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
6. Long-term
and Short-term Debt Obligations (Cont'd)
In
April
2006, we completed a new unsecured five-year bank credit agreement (the
Agreement) with a banking syndicate and extended the term by one year to July
2011. The Agreement is a revolving credit facility for up to $750 million and
replaces the previous $500 million facility. The current borrowing base was
established at $500 million, as compared to the previous $350 million. This
transaction was accounted for in accordance with Emerging Issues Task Force,
(EITF) 98-14, Debtor’s
Accounting for Changes in Line-of-Credit or Revolving-Debt
Arrangements.
The
total
outstanding debt under the credit facility’s borrowing base and line of credit
was $206 million at December 31, 2006, leaving $294 million in borrowing
capacity available. Interest on amounts borrowed under this debt is charged
at
LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with margins on the
various rate options based on the ratio of credit outstanding to the borrowing
base. We are required under the Agreement to pay a commitment fee of .25% to
.375% on the unused portion of the credit facility annually.
The
maximum amount available is subject to an annual redetermination of the
borrowing base in accordance with the lender's customary procedures and
practices. Both we and the banks have bilateral rights to one additional
redetermination each year.
The
Agreement contains restrictive covenants which, among other things, require
us
to maintain a certain debt to EBITDA ratio and a minimum current ratio, as
defined. The bond indebtedness of $200 million is subordinated to our credit
facility indebtedness. Our bond indebtedness covenant limits debt to the greater
of $750 million or 40% of Adjusted Consolidated Net Tangible Assets (as
defined). Additionally, as long as certain interest coverage ratio (as defined)
is met, we may incur additional debt. We were in compliance with all such
covenants as of December 31, 2006. The weighted average interest rate on total
long-term outstanding borrowings at December 31, 2006 and 2005 was 6.2% and
4.9%, respectively.
Short-term
debt
In
November 2005, we completed a new unsecured uncommitted money market line of
credit (Line of Credit). Borrowings under the Line of Credit may be up to $30
million for a maximum of 30 days. The Line of Credit may be terminated at any
time upon written notice by either us or the lender. At December 31, 2006 the
outstanding balance under this Line of Credit was $16 million. Interest on
amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The
weighted average interest rate on outstanding borrowings on the Line of Credit
at December 31, 2006 and 2005 was 7.3% and 5.4%, respectively. Additionally,
on
June 8, 2006 and July 10, 2006 we entered into five year interest rate swaps
for
a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings
under our credit facility for five years. These interest rate swaps have been
designated as cash flow hedges.
7. Shareholders’
Equity
On
March
1, 2006, our Board of Directors approved a two-for-one stock split to
shareholders of record on May 17, 2006, subject to obtaining shareholder
approval of an increase in our authorized shares. On May 17, 2006 our
shareholders approved the authorized share increase and on June 2, 2006 each
shareholder received one additional share for each share in the shareholder's
possession on May 17, 2006. This did not change the proportionate interest
a
shareholder maintained in Berry Petroleum Company on May 17, 2006. All
historical shares, equity awards and per share amounts have been restated for
the two-for-one stock split.
Shares
of
Class A Common Stock (Common Stock) and Class B Stock, referred to collectively
as the "Capital Stock," are each entitled to one vote and 95% of one vote,
respectively. Each share of Class B Stock is entitled to a $.50 per share
preference in the event of liquidation or dissolution. Further, each share
of
Class B Stock is convertible into one share of Common Stock at the option of
the
holder.
In
June
2005, we announced that our Board of Directors authorized a share repurchase
program for up to an aggregate of $50 million of our outstanding Class A Common
Stock. From June 2005 through December 31, 2006, we repurchased 818,000 shares
in the open market for approximately $25 million.
62
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
7. Shareholders’
Equity (Cont'd)
In
December 2005, we adopted a plan under Rule 10b5-1 of the Securities Exchange
Act of 1934 to facilitate the repurchase of our shares of common stock. Rule
10b5-1 allows a company to purchase its shares at times when it would not
normally be in the market due to possession of nonpublic information, such
as
the time immediately preceding its quarterly earnings releases. This plan
expired on December 1, 2006. This 10b5-1 plan was authorized under, and
administered consistent with, our $50 million share repurchase program. We
may
repurchase shares in the open market from time to time during our normal trading
windows or under a new plan under 10b5-1. All repurchases of common stock are
made in compliance with regulations set forth by the SEC and are subject to
market conditions, applicable legal requirements and other factors.
This
share repurchase program does not obligate us to acquire any particular amount
of common stock and the plan may be suspended at any time at our
discretion.
Dividends
We
paid a
special dividend of $.02 per share on September 29, 2006 and increased our
regular quarterly dividend by 15%, from $.065 to $.075 per share beginning
with
the September 2006 dividend. Our regular annual dividend is currently $.30
per
share, payable quarterly in March, June, September and December. We paid a
special dividend of $.05 per share on September 29, 2005 and increased our
regular quarterly dividend by 8%, from $.06 to $.065 per share beginning with
the September 2005 dividend.
As
of
December 31, 2006, dividends declared on 7,793,080 shares of certain Common
Stock are restricted, whereby 37.5% of the dividends declared on these shares
are paid by us to the surviving member of a group of individuals, the B Group,
as long as this remaining member shall live.
Dividend
payments are limited by covenants in our 1) credit facility to the greater
of
$20 million or 75% of net income, and 2) bond indenture of up to $20 million
annually irrespective of our coverage ratio or net income and up to $10 million
in the event we are in a non-payment default.
Shareholder
Rights Plan
In
November 1999, we adopted a Shareholder Rights Agreement and declared a dividend
distribution of one Right for each outstanding share of Capital Stock on
December 8, 1999. Each Right, when exercisable, entitles the holder to purchase
one one-hundredth of a share of a Series B Junior Participating Preferred Stock,
or in certain cases other securities, for $19.00. The exercise price and number
of shares issuable are subject to adjustment to prevent dilution. The Rights
would become exercisable, unless earlier redeemed by us 10 days following a
public announcement that a person or group has acquired, or obtained the right
to acquire, 20% or more of the outstanding shares of Common Stock, or 10
business days following the commencement of a tender or exchange offer for
such
outstanding shares which would result in such person or group acquiring 20%
or
more of the outstanding shares of Common Stock, either event occurring without
the prior consent of us.
The
Rights will expire on December 8, 2009 or may be redeemed by us at $.005 per
Right prior to that date unless they have theretofore become exercisable. The
Rights do not have voting or dividend rights, and until they become exercisable,
have no diluting effect on our earnings. A total of 500,000 shares of our
Preferred Stock has been designated Series B Junior Participating Preferred
Stock and reserved for issuance upon exercise of the Rights.
8. Asset
Retirement Obligations
Inherent
in the fair value calculation of ARO are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement, and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to
these assumptions impact the fair value of the existing ARO liability, a
corresponding adjustment is made to the oil and gas property balance. In 2006,
we reassessed our estimate as costs have increased due to demand for these
services, resulting in an increase in the ARO balance at year end.
63
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
8. Asset
Retirement Obligations (Cont’d)
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the years ended December 31 (in thousands):
|
|
|
2006
|
|
2005
|
|
||
|
Beginning
balance at January 1
|
|
$
|
10,675
|
$
|
8,214
|
|
|
|
Liabilities
incurred
|
|
|
5,711
|
|
2,952
|
|
|
|
Liabilities
settled
|
|
|
(862
|
)
|
|
(1,382
|
)
|
|
Revisions
in estimated liabilities
|
9,176
|
-
|
|||||
|
Accretion
expense
|
|
|
1,435
|
|
891
|
|
|
|
|
|
|
|
|
|||
|
Ending
balance at December 31
|
|
$
|
26,135
|
$
|
10,675
|
|
|
9. Income
Taxes
The
provision for income taxes consists of the following (in
thousands):
|
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Current:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
$
|
12,231
|
$
|
22,666
|
|
$
|
7,073
|
|
|
|
State
|
|
|
4,547
|
|
6,990
|
|
|
2,443
|
|
|
|
|
|
|
16,778
|
|
29,656
|
|
|
9,516
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
|
44,205
|
|
20,640
|
|
|
11,959
|
|
|
|
State
|
|
|
7,461
|
|
207
|
|
(1,144
|
)
|
||
|
|
|
|
51,666
|
|
20,847
|
|
|
10,815
|
|
|
|
Total
|
|
$
|
68,444
|
$
|
50,503
|
|
$
|
20,331
|
|
|
The
following table summarizes the components of the total deferred tax assets
and
liabilities before such financial statement offsets. The components of the
net
deferred tax liability consist of the following at December 31
(in thousands):
| 2006 | 2005 | ||||||||||||||
| Deferred tax asset: | |||||||||||||||
| Federal benefit of state taxes |
$
|
4,248 | $ | 2,712 | |||||||||||
|
Credit
carryforwards
|
|
|
33,338
|
|
31,929
|
|
|||||||||
|
Stock
option costs
|
|
|
3,989
|
|
2,352
|
|
|||||||||
|
Derivatives
|
|
|
13,275
|
|
16,253
|
|
|||||||||
|
Other,
net
|
|
|
3,450
|
|
139
|
|
|||||||||
|
|
|
|
58,300
|
|
53,385
|
|
|||||||||
|
Deferred
tax liability:
|
|
|
|
|
|||||||||||
|
Depreciation
and depletion
|
|
|
(162,560
|
)
|
|
(102,754
|
)
|
||||||||
|
Other,
net
|
|
|
-
|
|
(289
|
)
|
|||||||||
|
|
|
|
|
|
|||||||||||
|
|
|
|
(162,560
|
)
|
|
(103,043
|
)
|
||||||||
|
|
|
|
|
|
|||||||||||
|
Net
deferred tax liability
|
|
$
|
(104,260
|
)
|
$
|
(49,658
|
)
|
64
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
9. Income
Taxes (Cont'd)
At
December 31, 2006, our net deferred tax assets and liabilities were recorded
as
a current liability of $.7 million and a long-term liability of $103.5 million.
At December 31, 2005, our net deferred tax assets and liabilities were recorded
as a current asset of $4.5 million, a long-term asset of $1.6 million and a
long-term liability of $55.8 million.
Reconciliation
of the statutory federal income tax rate to the effective income tax rate
follows:
| 2006 | 2005 | 2004 | ||||||||||||||||||
|
Tax
computed at statutory federal rate
|
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
||||||||||
|
State
income taxes, net of federal benefit
|
|
|
5
|
|
3
|
|
1
|
|||||||||||||
|
Tax
credits
|
|
|
-
|
|
(7
|
)
|
|
(9
|
)
|
|||||||||||
|
Recognition
of tax basis of properties
|
|
|
-
|
|
-
|
|
(5
|
)
|
||||||||||||
|
Other
|
|
|
(1
|
)
|
|
-
|
|
1
|
||||||||||||
|
Effective
tax rate
|
|
|
39
|
%
|
|
31
|
%
|
|
23
|
%
|
||||||||||
We
have
approximately $24 million of federal and $18 million of state (California)
EOR
tax credit carryforwards available to reduce future income taxes. The EOR
credits will begin to expire, if unused, in 2024 and 2015 for federal and
California, respectively.
10. Leases
Receivable
We
entered into two separate three year lease agreements on two company owned
drilling rigs. Each agreement has a three year purchase option in favor of
the
lessee. The agreements were signed in the third and second quarters of 2005
and
2006, respectively. The total net investment in these rigs is approximately
$8.9
million at December 31, 2006. Both agreements are accounted for as direct
financing leases as defined by SFAS No. 13,
Accounting for Leases.
Net
investment in both leases are included in the balance sheet as other assets
and
as of December 31, 2006 are as follows (in thousands):
| Net minimum lease payments receivable | $ 11,511 | |||
|
Unearned
income
|
(2,657
|
)
|
||
|
Net
investment in direct financing lease
|
$
8,854
|
|||
As
of
December 31, 2006, estimated future minimum lease payments, including the
purchase option, to be received are as follows (in thousands):
|
2007
|
$
1,276
|
||
|
2008
|
4,545
|
||
|
2009
|
5,752
|
||
|
Total
|
$
11,573
|
Drilling
Rigs
During
2005, we purchased two drilling rigs, which are leased to a drilling company
under three-year contracts (see above). During 2006, we purchased a third rig
that was refurbished in preparation for leasing under a similar drilling
contract to be used for our Piceance drilling program. All three rigs carry
purchase options available to the drilling company.
65
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
11. Commitments
and Contingencies
We
have
accrued environmental liabilities for all sites, including sites in which
governmental agencies have designated us as a potentially responsible party,
where it is probable that a loss will be incurred and the minimum cost or amount
of loss can be reasonably estimated. However, because of the uncertainties
associated with environmental assessment and remediation activities, future
expense to remediate the currently identified sites, and sites identified in
the
future, if any, could be higher than the liability currently accrued. Amounts
currently accrued are not significant to our financial position and management
believes, based upon current site assessments, that the ultimate resolution
of
these matters will not require substantial additional accruals. We are involved
in various other lawsuits, claims and inquiries, most of which are routine
to
the nature of our business. In the opinion of management, the resolution of
these matters will not have a material effect on our financial position, or
on
the results of operations or liquidity.
Our
contractual obligations not included in our balance sheet as of December 31,
2006 are as follows (in thousands):
| Contractual Obligations | Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | ||||||||||||||||||||||||
|
Operating
lease obligations
|
|
|
14,208
|
|
1,822
|
|
1,670
|
|
1,375
|
|
1,357
|
|
1,357
|
|
6,627
|
||||||||||||||||
|
Drilling
and rig obligations
|
|
|
107,333
|
|
34,260
|
|
28,960
|
|
41,989
|
|
2,124
|
|
-
|
|
-
|
||||||||||||||||
|
Firm
natural gas transportation
contracts |
|
|
73,795
|
|
4,801
|
|
7,584
|
|
8,496
|
|
8,659
|
|
8,659
|
|
35,596
|
||||||||||||||||
|
Total
|
|
$
|
195,336
|
$
|
40,883
|
$
|
38,214
|
$
|
51,860
|
$
|
12,140
|
$
|
10,016
|
$
|
42,223
|
Operating leases - We lease corporate and field offices in California, Colorado and Texas. Rent expense with respect to our lease commitments for the years ended December 31, 2006, 2005 and 2004 was $1 million, $.6 million, and $.6 million, respectively. In 2006, we purchased an airplane for business travel which was subsequently sold and contracted under a ten year operating lease beginning December 2006.
Drilling
obligation
-
We
intend
to participate in the drilling of over 16 gross wells on our Lake Canyon
prospect over the four year contract, beginning in 2006. Our minimum obligation
under our exploration and development agreement is $9.6 million. Also included
above, under our June 2006 joint venture agreement in the Piceance basin we
must
have 120 wells drilled by 2010 to avoid penalties of $.2 million per well or
a
maximum of $24 million.
Drilling
rig obligation
- We are
obligated in operating lease agreements for the use of multiple drilling rigs.
Firm
natural gas transportation
-
We
have
one firm transportation contract which provides us additional flexibility in
securing our natural gas supply for California operations. This allows us to
potentially benefit from lower natural gas prices in the Rocky Mountains
compared to natural gas prices in California. We also have several long-term
transportation contracts which provide us with physical access to interstate
pipelines to move gas from our producing areas to markets.
12. Equity
Compensation Plans
On
December 2, 1994, our Board of Directors adopted the Berry Petroleum Company
1994 Stock Option Plan which was restated and amended in December 1997 and
December 2001 (the 1994 Plan or Plan) and approved by the shareholders in May
1998 and May 2002, respectively. The 1994 Plan provided for the granting of
stock options to purchase up to an aggregate of 3,000,000 shares of Common
Stock. All options, with the exception of the formula grants to non-employee
Directors, were granted at the discretion of the Compensation Committee and
the
Board of Directors. The term of each option did not exceed ten years from the
date the options were granted. The 1994 Plan expired on December 2, 2004, and
the shareholders approved a new equity incentive plan in May 2005.
The
2005
Equity Incentive Plan (the 2005 Plan), approved by the shareholders in May
2005,
provides for granting of equity compensation up to an aggregate of 2,900,000
shares of Common Stock. All equity grants are at market value on the date of
grant and at the discretion of the Compensation Committee or the Board of
Directors. The term of each employee grant did not exceed ten years from the
grant date and vesting has generally been at 25% per year for 4 years or 100%
after 3 years. The 2005 Plan also allows for grants to non-employee Directors.
During 2006, each of the non-employee Directors received 10,000 options at
the
market value on the date of grant. The options granted to the non-employee
Directors vest immediately. We generally use a broker for issuing new shares
upon option exercise.
66
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont’d)
We
adopted SFAS No. 123(R) to account for our stock option plan beginning
January 1, 2006. This standard requires us to measure the cost of employee
services received in exchange for an award of equity instruments based on the
grant-date fair value of the award. We previously adopted the fair value
recognition provisions of SFAS No. 123, Accounting
for Stock-Based Compensation
effective January 1, 2004. The modified prospective method was selected as
described in SFAS No. 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, we recognized stock option compensation expense as if it had
applied the fair value method to account for unvested stock options from its
original effective date. Total compensation cost recognized into income was
$6.1
million, $2.9 million and $4.2 million in 2006, 2005 and 2004,
respectively.
Stock
Options
The
fair
value of each stock option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the assumptions noted in the
following table. Expected volatilities are based on the historical volatility
of
our stock. We use historical data to estimate option exercises and employee
terminations within the valuation model; separate groups of employees that
have
similar historical exercise behavior are considered separately for valuation
purposes. The expected term of options granted is based on historical exercise
behavior and represents the period of time that options granted are expected
to
be outstanding; the range given below results from certain groups of employees
exhibiting different exercise behavior. The risk free rate for periods within
the contractual life of the option is based on U.S. Treasury rates in effect
at
the time of grant.
|
|
2006
|
|
2005
|
2004
|
|
|
Expected
volatility
|
32%
- 33%
|
|
28%
- 32%
|
25%
|
|
|
Weighted-average
volatility
|
32%
|
|
32%
|
25%
|
|
|
Expected
dividends
|
.8%
- 1.0%
|
|
.92%
- 1.3%
|
1.27%
- 2.45%
|
|
|
Expected
term (in years)
|
5.3
- 5.5
|
|
4
-
5
|
4
-
7
|
|
|
Risk-free
rate
|
4.5%
- 4.8%
|
|
3.8%
- 4.4%
|
3.4%
- 4.4%
|
The
following table summarizes information related to stock options outstanding
and
exercisable as of December 31, 2006:
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Weighted
|
||
|
|
|
|
|
Weighted
|
|
Average
|
|
|
|
Weighted
|
|
Average
|
|
|
Range
of
|
|
|
|
Average
|
|
Remaining
|
|
|
|
Average
|
|
Remaining
|
|
|
Exercise
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
Options
|
|
Exercise
|
|
Contractual
|
|
|
Prices
|
|
Outstanding
|
|
Price
|
|
Life
|
|
Exercisable
|
|
Price
|
|
Life
|
|
|
$6.25
- $14.00
|
|
872,610
|
$
8.75
|
5.7
|
771,860
|
$
8.61
|
6.3
|
||||||
|
$14.01
- $22.00
|
|
925,550
|
20.03
|
7.8
|
445,300
|
19.99
|
7.8
|
||||||
|
$22.01
- $30.00
|
25,000
|
29.36
|
9.1
|
3,750
|
29.25
|
8.6
|
|||||||
|
$30.01
- $38.00
|
|
1,036,676
|
31.90
|
9.5
|
272,157
|
31.56
|
9.3
|
||||||
|
Total
|
|
2,859,836
|
$
20.97
|
7.8
|
1,493,067
|
$
16.24
|
6.9
|
||||||
Weighted
average option exercise price information for the years ended December 31 is
as
follows:
|
|
|
2006
|
|
2005
(1)
|
|
2004
(1)
|
|
|||
|
Outstanding
at January 1
|
|
$
|
16.76
|
|
$
|
12.70
|
|
$
|
8.25
|
|
|
Granted
during the year
|
|
|
32.82
|
|
|
29.56
|
|
20.30
|
|
|
|
Exercised
during the year
|
|
|
10.83
|
|
|
8.40
|
|
|
7.87
|
|
|
Cancelled/expired
during the year
|
|
|
19.11
|
|
|
18.68
|
|
|
9.01
|
|
|
Outstanding
at December 31
|
|
|
20.97
|
|
|
16.76
|
|
|
12.70
|
|
|
Exercisable
at December 31
|
|
|
16.24
|
|
|
12.31
|
|
|
8.80
|
|
67
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont’d)
The
following is a summary of stock option activity for the years ended December
31
is as follows:
| 2006 | 2005 (1) | 2004 (1) | |||||||||||||||||||
| Balance outstanding, January 1 | 3,110,826 | 3,131,250 | 3,403,850 | ||||||||||||||||||
|
Granted
|
|
604,050
|
|
598,926
|
|
1,135,500
|
|
||||||||||||||
|
Exercised
|
|
(526,990
|
)
|
(605,200
|
)
|
(1,163,100
|
)
|
||||||||||||||
|
Canceled/expired
|
|
(328,050
|
)
|
(14,150
|
)
|
(245,000
|
)
|
||||||||||||||
|
Balance
outstanding, December 31
|
|
2,859,836
|
|
3,110,826
|
|
3,131,250
|
|
||||||||||||||
|
|
|
|
|
|
|||||||||||||||||
|
Balance
exercisable at December 31
|
|
1,493,067
|
|
1,423,076
|
|
1,376,550
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||
|
Available
for future grant
|
|
1,252,344
|
|
2,159,174
|
|
|
-
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Weighted
average remaining contractual life (years)
|
|
8
|
|
|
8
|
|
|
8
|
|
||||||||||||
|
Weighted
average fair value per option granted during the year based on the
Black-Scholes pricing model
|
|
$
|
11.27
|
|
$
|
9.58
|
|
$
|
5.05
|
|
(1)
The 2004 and 2005 per share and share amounts have been restated to give
retroactive effect to the two-for-one stock split that became effective on
May
17, 2006.
As
of
December 31, 2006, there was $10.5 million of total unrecognized compensation
cost related to stock options granted under the Plan. This cost is expected
to
be recognized over a weighted-average period over 1.6 years. The tax benefit
realized from stock options exercised during the year ended December 31, 2006
is
$4.3 million.
|
Stock
Options
|
|||||
|
Year
ended
|
|||||
|
December
31, 2006
|
December
31, 2005 (1)
|
December
31, 2004 (1)
|
|||
|
Weighted-average
grant date fair value of options issued
|
$
11.27
|
$
9.58
|
$
5.05
|
||
|
Total
intrinsic value of options exercised (in millions)
|
11.8
|
12.6
|
7.2
|
||
|
Total
intrinsic value of options outstanding (in millions)
|
29.8
|
36.8
|
34.9
|
||
|
Total
intrinsic value of options exercisable (in millions)
|
22.3
|
26.2
|
20.7
|
||
(1)
The 2004 and 2005 share amounts have been restated to give retroactive effect
to
the two-for-one stock split that became effective on May 17,
2006.
68
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
12. Equity
Compensation Plans (Cont’d)
Restricted
Stock Units
Under
the
2005 Equity Plan, we began a long-term incentive program whereby restricted
stock units (RSUs) are available for grant to certain employees. Granted RSUs
generally
vest at either 25% per year over 4 years or 100% after 3 years. Unearned
compensation under the restricted stock award plan is amortized over the vesting
period. We pay cash compensation on the RSUs in an equivalent amount of actual
dividends paid on a per share basis of our outstanding common
stock.
The
following is a summary of RSU activity for the year ended December 31, 2006
as
follows:
|
RSUs
|
Weighted
Average Intrinsic Value at Grant Date
|
Weighted
Average Contractual Life Remaining
|
||||||||
|
Balance
outstanding, January 1
|
141,900
|
$
|
30.65
|
3.0
years
|
||||||
|
Granted
|
372,480
|
31.86
|
||||||||
|
Converted
|
(29,825
|
)
|
30.65
|
|||||||
|
Canceled/expired
|
(25,400
|
)
|
31.32
|
|||||||
|
Balance
outstanding, December 31
|
459,155
|
$
|
31.59
|
3.3
years
|
| RSUs Year ended | ||||||
|
|
|
|
December
31, 2006
|
|
December
31, 2005 (1)
|
December
31, 2004
|
|
Weighted-average
grant date fair value of RSUs issued
|
$
31.86
|
$
30.65
|
$
-
|
|||
|
Total
intrinsic value of RSUs vested (in millions)
|
|
|
1.0
|
|
-
|
-
|
|
Total
intrinsic value of RSUs outstanding (in millions)
|
|
|
14.2
|
|
4.1
|
-
|
(1)
The 2005 share amounts have been restated to give retroactive effect to the
two-for-one stock split that became effective on May 17, 2006.
The
total
compensation cost related to nonvested awards not yet recognized on December
31,
2006 is $13 million and the weighted average period over which this cost is
expected to be recognized is 1.8 years.
13. 401(k)
Plan
We
sponsor a defined contribution thrift plan under section 401(k) of the Internal
Revenue Code to assist all employees in providing for retirement or other future
financial needs. In December 2005, the 401(k) Plan was amended whereby effective
January 1, 2006, our matching contribution is $1.00 for each $1.00 contributed
by the employee up to 8% of an employee's eligible compensation. Prior to
January 1, 2006, the employer match ranged from $1.00 to $1.50 for each $1.00
contributed by the employee up to 6% of an employee’s eligible compensation. The
employer match amount was based on the achievement of certain monthly profit
levels. Our contributions to the 401(k) Plan were $1.2 million, $1.1 million
and
$.8 million for 2006, 2005 and 2004, respectively. Employees are eligible to
participate in the 401(k) Plan on their date of hire and approximately 92%
of
our employees participated in the 401(k) Plan in 2006.
14. Director
Deferred Compensation Plan
We
established a non-employee director deferred stock and compensation plan to
permit eligible directors, in recognition of their contributions to us, to
receive fees as compensation and to defer recognition of their compensation
in
whole or in part to a Stock Unit Account or an Interest Account. When the
eligible director ceases to be a director, the distribution from the Stock
Unit
Account shall be made in shares using an established market value date. The
distribution from the Interest Account shall be made in cash. The aggregate
number of shares which may be issued to eligible directors under the plan shall
not exceed 500,000, subject to adjustment for corporate transactions that change
the amount of outstanding stock. The plan may be amended at any time, but not
more than once every six months, by the Compensation Committee or the Board
of
Directors and shall terminate, unless extended, on May 31, 2008.
69
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
14. Director
Deferred Compensation Plan (Cont’d)
Amounts
allocated to the Stock Unit Account have the right to receive an amount equal
to
the dividends per share we declare as applicable. The dividend payment date
and
this “dividend equivalent” shall be treated as reinvested in an additional
number of units and credited to their account using an established market value
date. Amounts allocated to the Interest Account are credited with interest
at an
established interest rate.
Shares
earned and deferred in accordance with the plan as of December 31, 2006, 2005
and 2004 were 13,387, 13,770 and 14,962, respectively.
15. Hedging
From
time
to time we enter into crude oil and natural gas hedge contracts, the terms
of
which depend on various factors, including management’s view of future crude oil
and natural gas prices and our future financial commitments. This hedging
program is designed to moderate the effects of a severe crude oil price downturn
and protect certain operating margins in our California operations. Currently,
the hedges are in the form of swaps and collars, however we may use a variety
of
hedge instruments in the future. Management regularly monitors the crude oil
and
natural gas markets and our financial commitments to determine if, when, and
at
what level some form of crude oil and/or natural gas hedging or other price
protection is appropriate. All of these hedges have historically been deemed
to
be cash flow hedges with the marked-to-market valuations provided by external
sources, based on prices that are actually quoted.
In
June
2005, we entered into derivative instruments (zero-cost collars) for
approximately 10,000 Bbl/D for the period January 1, 2006 through December
31,
2009. Based on WTI pricing, the floor is $47.50 and the ceiling is $70 per
barrel. The use of hedging transactions also involves the risk that the
counterparties will be unable to meet the financial terms of such transactions.
With respect to our hedging activities, we utilize multiple counterparties
on
our hedges and monitor each counterparty’s credit rating. After the June hedge
transaction, a significant credit risk concentration existed in one broker.
In
July 2005, we reduced the concentration as the hedges were transferred to
multiple counterparties. We are not required to issue collateral on these
hedging transactions.
We
entered into derivative contracts (natural gas swaps and collar contracts)
on
March 1, 2006 that did not qualify for hedge accounting under SFAS 133 because
the price index for the location in the derivative instrument did not correlate
closely with the item being hedged. These contracts were recorded in the first
quarter of 2006 at their fair value on the balance sheet and we recognized
an
unrealized net loss of approximately $4.8 million on the income statement under
the caption “Commodity derivatives.” We entered into natural gas basis swaps on
the same volumes and maturity dates as the previous hedges in May 2006 which
allowed for these derivatives to be designated as cash flow hedges going
forward. We recognized an unrealized net gain of $5.6 million in the second
quarter of 2006. The net gain of $.8 million was recorded in other accumulated
comprehensive income at the date the hedges were designated and will be
amortized to revenue as the related sales occur.
Additionally,
on June 8, 2006 and July 10, 2006 we entered into five year interest rate swaps
for a fixed rate of approximately 5.5% on $100 million of our outstanding
borrowings under our credit facility for five years. These interest rate swaps
have been designated as cash flow hedges.
The
related cash flow impact of all of our derivative activities are reflected
as
cash flows from operating activities. At December 31, 2006, our net fair value
of derivatives liability was $33.2 million as compared to $40.6 million at
December 31, 2005. Based on NYMEX strip pricing as of December 31, 2006, we
expect to make hedge payments under the existing derivatives of
$4.8 million during the next twelve months. At December 31, 2006 and 2005,
Accumulated Other Comprehensive Loss consisted of $20 million and $ 24.4
million, respectively, net of tax, of unrealized losses from our crude oil
and
natural gas swaps and collars that qualified for hedge accounting treatment
at
December 31, 2006. Deferred net losses recorded in Accumulated Other
Comprehensive Loss at December 31, 2006 and subsequent marked-to-market changes
in the underlying hedging contracts are expected to be reclassified to earnings
over the life of these contracts.
70
BERRY
PETROLEUM COMPANY
Notes
to the Financial Statements
16. Quarterly
Financial Data (unaudited)
The
following is a tabulation of unaudited quarterly operating results for 2006
and
2005 (in thousands, except per share data).
|
Income
|
Basic
Net
|
Diluted
Net
|
|||||||||||||||||||||||||||||||
|
|
|
Operating
|
|
Before
|
|
Net
|
|
Income
|
|
Income
|
|
||||||||||||||||||||||
|
2006
|
|
Revenues
|
|
Taxes
|
|
Income
|
|
Per
Share (1)
|
|
Per
Share (1)
|
|
||||||||||||||||||||||
| First Quarter | $ | 117,101 | $ | 38,084 | $ | 23,251 | $ | .53 | $ | .52 | |||||||||||||||||||||||
|
Second
Quarter
|
|
|
122,356
|
|
|
57,197
|
|
|
34,203
|
|
|
.78
|
|
|
.76
|
|
|||||||||||||||||
|
Third
Quarter
|
|
|
128,760
|
|
|
50,477
|
|
|
31,374
|
|
|
.71
|
|
|
.70
|
|
|||||||||||||||||
|
Fourth
Quarter
|
|
|
115,212
|
|
|
30,629
|
|
|
19,115
|
|
|
.44
|
|
|
.43
|
|
|||||||||||||||||
|
|
|
$
|
483,429
|
|
$
|
176,387
|
|
$
|
107,943
|
|
$
|
2.46
|
|
$
|
2.41
|
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| First Quarter | $ | 87,847 | $ | 33,367 | $ | 22,505 | $ | .51 | $ | .50 | |||||||||||||||||||||||
|
Second
Quarter
|
|
|
92,339
|
|
|
37,322
|
|
|
25,260
|
|
|
.57
|
|
|
.56
|
|
|||||||||||||||||
|
Third
Quarter
|
|
|
109,372
|
|
|
48,765
|
|
|
34,219
|
|
|
.78
|
|
|
.76
|
|
|||||||||||||||||
|
Fourth
Quarter
|
|
|
115,363
|
|
|
43,405
|
|
|
30,372
|
|
|
.69
|
|
|
.68
|
|
|||||||||||||||||
|
|
|
$
|
404,921
|
|
$
|
162,859
|
|
$
|
112,356
|
|
$
|
2.55
|
|
$
|
2.50
|
|
|||||||||||||||||
(1)
The 2005 per share and share amounts have been restated to give retroactive
effect to the two-for-one stock split that became effective on May 17, 2006.
See
Note 7.
71
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities
(Unaudited)
The
following sets forth costs incurred for oil and gas property acquisition,
development and exploration activities, whether capitalized or expensed (in
thousands):
|
Property
acquisitions (1)
|
|
2006
|
|
2005
|
|
2004
|
|
||||||||||||||
| Proved properties | $ | 33,390 | $ | 97,348 | $ | 440 | |||||||||||||||
|
Unproved
properties
|
|
|
224,450
|
|
|
24,566
|
|
|
2,405
|
|
|||||||||||
|
Development (2)
|
|
|
277,613
|
|
|
112,255
|
|
|
66,664
|
|
|||||||||||
|
Exploration
(3)
|
|
|
22,435
|
|
|
11,310
|
|
|
5,506
|
|
|||||||||||
|
|
|
$
|
557,888
|
|
$
|
245,479
|
|
$
|
75,015
|
|
|||||||||||
(1)
Costs incurred for proved and unproved property acquisitions in 2005 include
the
reclassification of 2004 deposits of $5,505 and $4,716,
respectively.
(2)
Development
costs include $.5 million, $.6 million and $.7 million that were charged to
expense during 2006, 2005 and 2004, respectively.
(3)
Exploration
costs include $3.8 million and $3.6 million that were charged to expense during
2006 and 2005, respectively. Exploration costs include $9.3 million of
capitalized interest.
The
following sets forth results of operations from oil and gas producing and
exploration activities (in thousands):
|
|
|
2006
|
|
2005
|
|
2004
|
|
||||||||||||||
| Sales to unaffiliated parties | $ | 430,497 | $ | 349,691 | $ | 226,876 | |||||||||||||||
|
Production
costs
|
|
|
(132,298
|
)
|
|
(110,572
|
)
|
|
(80,269
|
)
|
|||||||||||
|
Depreciation,
depletion and amortization
|
|
|
(67,668
|
)
|
|
(38,150
|
)
|
|
(29,752
|
)
|
|||||||||||
|
Dry
hole, abandonment, impairment and exploration
|
|
|
(12,009
|
)
|
|
(9,354
|
)
|
|
(745
|
)
|
|||||||||||
|
|
|
|
218,522
|
|
191,615
|
|
|
116,110
|
|
||||||||||||
|
Income
tax expenses
|
|
|
(85,970
|
)
|
|
(57,872
|
)
|
|
(33,840
|
)
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Results
of operations from producing and exploration activities
|
|
$
|
132,552
|
$
|
133,743
|
|
$
|
82,270
|
|
||||||||||||
The
following estimates of proved oil and gas reserves, both developed and
undeveloped, represent our owned interests located solely within the United
States. Proved reserves represent estimated quantities of crude oil and natural
gas which geological and engineering data demonstrated with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed oil and gas reserves are the
quantities expected to be recovered through existing wells with existing
equipment and operating methods. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells for which relatively major expenditures are required
for
completion.
Disclosures
of oil and gas reserves which follow are based on estimates prepared by
independent engineering consultants as of December 31, 2006, 2005 and 2004.
Such
estimates are subject to numerous uncertainties inherent in the estimation
of
quantities of proved reserves and in the projection of future rates of
production and the timing of development expenditures. These estimates do not
include probable or possible reserves. The information provided does not
represent management's estimate of our expected future cash flows or value
of
proved oil and gas reserves.
72
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities (Unaudited)
(Cont'd)
Changes
in estimated reserve quantities
The
net
interest in estimated quantities of proved developed and undeveloped reserves
of
crude oil and natural gas at December 31, 2006, 2005 and 2004, and changes
in
such quantities during each of the years then ended were as follows (in
thousands):
|
|
|
2006
|
|
2005
|
|
2004
|
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||||||||
| Oil | Gas | Oil | Gas | Oil | Gas | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
Mbbls
|
|
Mmcf
|
|
BOE
|
|
||||||||||||||||||||||||||||||||||||||||||
|
Proved
developed and Undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||
| Beginning of year | 103,733 | 135,311 | 126,285 | 105,549 | 25,724 | 109,836 | 106,640 | 19,680 | 109,920 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Revision
of previous estimates
|
|
(512)
|
(222
|
)
|
(553
|
)
|
|
(681
|
)
|
4,084
|
-
|
|
|
2,975
|
|
|
8,246
|
|
|
4,349
|
|||||||||||||||||||||||||||||||||||||||||
|
Improved
recovery
|
|
11,900
|
-
|
11,900
|
|
753
|
-
|
753
|
|
|
2,021
|
|
|
-
|
|
|
2,021
|
|
|||||||||||||||||||||||||||||||||||||||||||
|
Extensions
and discoveries
|
|
4,100
|
78,000
|
17,100
|
|
6,228
|
24,605
|
10,329
|
|
|
2,736
|
|
|
714
|
|
|
2,855
|
|
|||||||||||||||||||||||||||||||||||||||||||
|
Property
sales
|
|
-
|
-
|
-
|
|
(1,035
|
)
|
-
|
(1,035
|
)
|
|
(127
|
)
|
|
(77
|
)
|
|
(140
|
)
|
||||||||||||||||||||||||||||||||||||||||||
|
Production
|
|
(7,183)
|
(12,526
|
)
|
(9,270
|
)
|
|
(7,081
|
)
|
(7,919)
|
(8,401
|
)
|
|
(7,044
|
)
|
|
(2,839
|
)
|
|
(7,517
|
)
|
||||||||||||||||||||||||||||||||||||||||
|
Purchase
of reserves in place (1)
|
|
500
|
25,800
|
4,800
|
|
-
|
88,817
|
14,803
|
|
|
132
|
|
|
-
|
|
|
132
|
|
|||||||||||||||||||||||||||||||||||||||||||
|
Royalties
converted to working interest
|
|
-
|
-
|
-
|
|
-
|
-
|
-
|
|
(1,784
|
)
|
|
-
|
|
|
(1,784
|
)
|
||||||||||||||||||||||||||||||||||||||||||||
|
End
of year
|
|
112,538
|
226,363
|
150,262
|
|
103,733
|
135,311
|
126,285
|
|
|
105,549
|
|
|
25,724
|
|
|
109,836
|
|
|||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||
|
Proved
developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||
|
Beginning
of year
|
|
78,308
|
70,519
|
90,061
|
|
78,207
|
20,048
|
81,549
|
|
|
78,145
|
|
|
12,207
|
|
|
80,180
|
|
|||||||||||||||||||||||||||||||||||||||||||
|
End
of year
|
|
84,782
|
104,934
|
102,270
|
|
78,308
|
70,519
|
90,061
|
|
|
78,207
|
|
|
20,048
|
|
|
81,549
|
|
|||||||||||||||||||||||||||||||||||||||||||
(1)
See above and Note 5 to the financial statements.
The
standardized measure has been prepared assuming year end sales prices adjusted
for fixed and determinable contractual price changes, current costs and
statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense. Cash outflows for future production and development costs
include cash flows associated with the ultimate settlement of the asset
retirement obligation.
Standardized
measure of discounted future net cash flows from estimated production of proved
oil and gas reserves (in thousands):
| 2006 | 2005 | 2004 | |||||||||||||||||||
| Future cash inflows | $ | 6,195,547 | $ | 6,088,170 | $ | 3,281,155 | |||||||||||||||
|
Future
production costs
|
|
|
(2,497,785
|
)
|
|
(2,297,638
|
)
|
|
(1,405,432
|
)
|
|||||||||||
|
Future
development costs
|
|
|
(511,886
|
)
|
|
(333,722
|
)
|
|
(216,859
|
)
|
|||||||||||
|
Future
income tax expenses
|
|
|
(892,669
|
)
|
|
(1,115,516
|
)
|
|
(355,764
|
)
|
|||||||||||
|
Future
net cash flows
|
|
|
2,293,207
|
|
2,341,294
|
|
|
1,303,100
|
|
||||||||||||
|
10%
annual discount for estimated timing of cash flows
|
|
|
(1,110,939
|
)
|
|
(1,089,914
|
)
|
|
(616,352
|
)
|
|||||||||||
|
Standardized
measure of discounted future net cash flows
|
|
$
|
1,182,268
|
$
|
1,251,380
|
|
$
|
686,748
|
|
||||||||||||
|
Average
sales prices at December 31:
|
|
|
|
|
|
|
|
||||||||||||||
|
Oil
($/Bbl)
|
|
$
|
46.15
|
$
|
48.38
|
|
$
|
29.49
|
|
||||||||||||
|
Gas
($/Mcf)
|
|
$
|
4.45
|
$
|
7.91
|
|
$
|
6.61
|
|
||||||||||||
|
BOE
Price
|
|
$
|
41.23
|
$
|
48.21
|
|
$
|
29.87
|
|
73
BERRY
PETROLEUM COMPANY
Supplemental
Information About Oil & Gas Producing Activities (Unaudited)
(Cont'd)
Changes
in standardized measure of discounted future net cash flows from proved oil
and
gas reserves (in thousands):
|
2006
|
2005
|
2004
|
|||||||||||||||||||
| Standardized measure - beginning of year | $ |
1,251,380
|
$ |
686,748
|
$ |
528,220
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Sales
of oil and gas produced, net of production costs
|
|
|
(300,619
|
)
|
|
(240,039
|
)
|
|
(144,457
|
)
|
|||||||||||
|
Revisions
to estimates of proved reserves:
|
|
|
|
|
|
|
|
||||||||||||||
|
Net
changes in sales prices and production costs
|
|
|
(350,877
|
)
|
|
702,867
|
|
|
190,861
|
|
|||||||||||
|
Revisions
of previous quantity estimates
|
|
|
(7,359
|
)
|
|
5
|
|
|
40,419
|
||||||||||||
|
Improved
recovery
|
|
|
158,213
|
|
12,267
|
|
|
18,787
|
|
||||||||||||
|
Extensions
and discoveries
|
|
|
227,348
|
|
168,291
|
|
|
26,541
|
|
||||||||||||
|
Change
in estimated future development costs
|
|
|
(333,663
|
)
|
|
(157,068
|
)
|
|
(56,314
|
)
|
|||||||||||
|
Purchases
of reserves in place
|
|
|
33,390
|
|
103,150
|
|
|
962
|
|
||||||||||||
|
Sales
of reserves in place
|
|
|
-
|
|
(9,613
|
)
|
|
(1,043
|
)
|
||||||||||||
|
Development
costs incurred during the period
|
|
|
277,075
|
|
111,613
|
|
|
65,971
|
|
||||||||||||
|
Accretion
of discount
|
|
|
125,138
|
|
87,650
|
|
|
68,312
|
|
||||||||||||
|
Income
taxes
|
|
|
109,918
|
|
(392,886
|
)
|
|
(16,890
|
)
|
||||||||||||
|
Other
|
|
|
(7,676
|
)
|
|
178,395
|
|
(21,430
|
)
|
||||||||||||
|
Royalties
converted to working interest
|
|
|
-
|
|
-
|
|
(13,191
|
)
|
|||||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Net
increase (decrease)
|
|
|
(69,112
|
)
|
|
564,632
|
|
|
158,528
|
|
|||||||||||
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Standardized
measure - end of year
|
|
$
|
1,182,268
|
$
|
1,251,380
|
|
$
|
686,748
|
|
Item
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item
9A. Controls and Procedures
Evaluation
of Disclosure Controls and Procedures
As
of
December 31, 2006, we have carried out an evaluation under the supervision
of,
and with the participation of, our management, including our Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15
under the Securities Exchange Act of 1034, as amended.
Based
on
their evaluation as of December 31, 2006, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls and procedures
(as
defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act
of 1934) are effective to ensure that the information required to be disclosed
by us in the reports that it files or submits under the Securities Exchange
Act
of 1934 is recorded, processed, summarized and reported within the time periods
specified in SEC rules and forms.
Management’s
Report on Internal Control Over Financial Reporting
Internal
control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f)
promulgated under the Securities Exchange Act of 1934, as amended, as a process
designed by, or under the supervision of, our principal executive and principal
financial officers, or persons performing similar functions, and effected by
our
Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external reporting purposes in accordance with
U.S.
generally accepted accounting principles and includes those policies and
procedures that:
74
· pertain
to the maintenance of records that in reasonable detail accurately and fairly
reflect the transactions and dispositions of our assets;
· provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of our management and
Directors; and
· provide
reasonable assurance regarding prevention or the timely detection of
unauthorized acquisition, or the use or disposition of our assets that could
have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. All internal control systems, no matter how
well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect
to
financial statement preparation and presentation. Additionally, projections
of
any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
Management
is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). Under the supervision and with the participation of
management, including the principal executive officer and principal financial
officer, we conducted an evaluation of the effectiveness of our internal control
over financial reporting based on the framework in Internal
Control - Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission. Based
on
our evaluation under the framework in Internal
Control - Integrated Framework,
management concluded that our internal control over financial reporting was
effective as of December 31, 2006.
Management’s
assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
is included herein.
Changes
in Internal Control Over Financial Reporting
There
were no changes in our internal control over financial reporting that occurred
during the three months ended December 31, 2006 that have materially affected,
or are reasonably likely to materially affect, our internal control over
financial reporting. We may make changes in our internal control procedures
from
time to time in the future.
Item
9B. Other Information
On
February 27, 2007, we entered into a multi-staged crude oil sales contract
with
a subsidiary of Holly Corporation (Holly) for our Uinta basin crude oil. Under
the agreement, Holly will begin purchasing 3,200 gross Bbl/D beginning July
1,
2007. Upon completion of their Woods Cross refinery expansion in Salt Lake
City,
which is expected in mid 2008, Holly will increase their total purchased volumes
to 5,000 Bbl/D through June 30, 2013. Pricing under the contract, which includes
transportation, is a fixed percentage of WTI and approximates our expected
field
posted price of $13 to $16 below WTI.
PART
III
Item
10. Directors and Executive Officers and Corporate
Governance
The
information called for by Item 10 is incorporated by reference from information
under the captions “Corporate Governance”, “Meetings and Committees of our
Board” and “Compliance with Section 16(a) of the Securities Exchange Act of
1934” in our definitive proxy statement to be filed pursuant to Regulation 14A
no later than 120 days after the close of our fiscal year. Information regarding
Executive Officers is contained in this report in Item 1 Business of this
Form 10-K.
Item
11. Executive
Compensation
The
information called for by Item 11 is incorporated by reference from information
under the caption "Executive Compensation" in our definitive proxy statement
to
be filed pursuant to Regulation 14A no later than 120 days after the close
of
our fiscal year.
75
Item
12. Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The
information called for by Item 12 is incorporated by reference from information
under the captions "Security Ownership" and "Principal Shareholders" in our
definitive proxy statement to be filed pursuant to Regulation 14A no later
than
120 days after the close of our fiscal year and Item 5 Market
for the Registrant's Common Equity and Related Shareholder Matters and Issuer
Purchases of Equity Securities of this Form 10-K.
Item
13. Certain
Relationships and Related Transactions, and Director
Independence
The
information called for by Item 13 is incorporated by reference from information
under the caption "Certain Relationships and Related Transactions" in our
definitive proxy statement to be filed pursuant to Regulation 14A no later
than
120 days after the close of our fiscal year.
Item
14. Principal
Accounting Fees and Services
The
information called for by Item 14 is incorporated by reference from the
information under the caption “Fees to Independent Registered Public Accounting
Firms for 2006 and 2005” in our definitive proxy statement to be filed pursuant
to Regulation 14A no later than 120 days after the close of our fiscal
year.
PART
IV
Item
15. Exhibits,
Financial Statement Schedules
A.
Financial Statements and Schedules
See
Item
8 Index to Financial Statements and Supplementary Data in this Form
10-K.
B.
Exhibits
|
Exhibit
No.
|
Description
of Exhibit
|
||
|
|
|
||
|
3.1*
|
Registrant's
Amended and Restated Certificate of Incorporation (filed as
Exhibit 3.1 to
the Registrant’s Quarterly Report on Form 10-Q for the period ended June
30, 2006, File No. 1-09735).
|
||
|
3.2*
|
Registrant's
Restated Bylaws dated July 1, 2005 (filed as Exhibit 3.1 to
the
Registrant's Quarterly Report on Form 10-Q for the quarterly
period ended
June 30, 2005, File No. 1-09735).
|
||
|
4.1*
|
First
Supplemental Indenture, dated as of October 24, 2006, between
the
Registrant and Wells Fargo Bank, National Association as Trustee
relating
to the Registrant's 8 1/4% Senior Subordinated Notes due 2016
(filed as
Exhibit 4.1 to the Registrant's Current Report on Form 8-K
File No.
1-9735).
|
||
|
4.2*
|
Registrant’s
8.25% Senior Subordinated Notes (filed as Form 425B5 on October
19,
2006).
|
||
|
4.3*
|
Registrant's
Certificate of Designation, Preferences and Rights of Series
B Junior
Participating Preferred Stock (filed as Exhibit A to the Registrant's
Registration Statement on Form 8-A12B on December 7, 1999,
File No.
778438-99-000016).
|
||
|
4.4*
|
Rights
Agreement between Registrant and ChaseMellon Shareholder Services,
L.L.C.
dated as of December 8, 1999 (filed by the Registrant on Form
8-A12B on
December 7, 1999, File No. 778438-99-000016).
|
||
|
10.1
|
Description
of Short-Term Cash Incentive Plan of Registrant.
|
||
|
10.2*
|
Form
of Change in Control Severance Protection Agreement dated August
24, 2006,
by and between Registrant and selected employees of the Company
(filed as
Exhibit 99.1 to the Registrant’s Current Report on Form 8-K on August 24,
2006, File No. 1-9735).
|
||
|
10.3*
|
Instrument
for Settlement of Claims and Mutual Release by and among Registrant,
Victory Oil Company, the Crail Fund and Victory Holding Company
effective
October 31, 1986 (filed as Exhibit 10.13 to Amendment No. 1
to the
Registrant's Registration Statement on Form S-4 filed on May
22, 1987,
File No. 33-13240).
|
||
|
10.4*
|
Credit
Agreement, dated as of June 27, 2005, by and between the Registrant
and
Wells Fargo Bank, N.A. and other financial institutions (filed
as Exhibit
10.1 to the Registrant's Quarterly Report on Form 10-Q for
the quarterly
period ended June 30, 2005, File No. 1-9735).
|
||
|
10.5*
|
First
Amendment to Credit Agreement, dated as of December 15, 2005
by and
between the Registrant and Wells Fargo Bank, N.A. and other
financial
institutions (filed as Exhibit 3.1 to the Registrant’s Annual Report on
Form 10-K for the period ended December 31, 2005, File No.
1-09735).
|
||
76
|
10.6*
|
Second
Amendment to Credit Agreement, dated as of April 28, 2006 by and
between
the Registrant and Wells Fargo Bank, N.A. and other financial institutions
(filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q
for the period ended March 31, 2006, File No. 1-09735).
|
|
|
10.7*
|
Amended
and Restated 1994 Stock Option Plan (filed as Exhibit 4.1 to the
Registrant’s Registration Statement on Form S-8 filed on August 20, 2002,
File No. 333-98379).
|
|
|
10.8*
|
First
Amendment to the Registrant’s Amended and Restated 1994 Stock Option Plan
dated as of June 23, 2006 by and between the Registrant and Robert
F.
Heinemann (filed as Exhibit 99.3 to the Registrant's Current Report
on
Form 8-K June 26, 2006, File No. 1-9735).
|
|
|
10.9*
|
Berry
Petroleum Company 2005 Equity Incentive Plan (filed as Exhibit 4.2
to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
|
|
10.10*
|
Form
of the Stock Option Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 4.3 to the
Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
|
|
10.11*
|
Form
of the Stock Appreciation Rights Agreement, by and between Registrant
and
selected employees, directors, and consultants (filed as Exhibit
4.4 to
the Registrant’s Form S-8 filed on July 29, 2005, File No.
333-127018).
|
|
|
10.12*
|
Form
of Stock Award Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 99.1 on Form
8-K
filed on December 22, 2005, File No. 1-9735).
|
|
|
10.13*
|
Form
of Stock Award Agreement, by and between Registrant and selected
employees, directors, and consultants (filed as Exhibit 99.4 to the
Registrant's Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
|
|
10.14*
|
Carry
and Earning Agreement, dated June 7, 2006, between Registrant and
EnCana
Oil & Gas (USA), Inc. (filed as Exhibit 99.2 on Form 8-K on June 19,
2006, File No. 1-9735).
|
|
|
10.15*
|
Crude
oil purchase contract, dated November 14, 2005 between Registrant
and Big
West of California, LLC (filed as Exhibit 99.2 on Form 8-k filed
on
November 22, 2005, File No. 1-9735).
|
|
|
10.16*
|
Non-Employee
Director Deferred Stock and Compensation Plan (as amended effective
January 1, 2006) (filed as Exhibit 10.13 to the Registrant’s Annual Report
on Form 10-K for the period ended December 31, 2005, File No.
1-09735).
|
|
|
10.17*
|
Amended
and Restated Employment Contract dated as of June 23, 2006 by and
between
the Registrant and Robert F. Heinemann (filed as Exhibit 99.1 to
the
Registrant's Current Report on Form 8-K June 26, 2006, File No.
1-9735).
|
|
|
10.18*
|
Stock
Award Agreement dated as of June 23, 2006 by and between the Registrant
and Robert F. Heinemann (filed as Exhibit 99.2 to the Registrant's
Current
Report on Form 8-K June 26, 2006, File No. 1-9735).
|
|
|
10.19*
|
Purchase
and sale agreement between the Registrant and J-W Operating Company
(filed
as Exhibit 99.2 to the Registrant's Current Report on Form 8-K/A
filed on
February 15, 2005, File No. 1-9735).
|
|
|
10.20*
|
Amended
and Restated Purchase and Sale Agreement between Registrant and Orion
Energy Partners, LP (filed as Exhibit 10.17 to the Registrant’s Annual
Report on Form 10-K for the period ended December 31, 2005, File
No.
1-09735).
|
|
|
10.21*
|
Underwriting
Agreement dated October 18, 2006 by and between Registrant and the
several
Underwriters listed in Schedule 1 thereto (filed as Exhibit 1.1 to
the
Registrant’s Current Report on Form 8-K on October 19, 2006, File No.
1-9735).
|
|
|
10.22**
|
Crude
Oil Supply Agreement between the Registrant and Holly Refining and
Marketing Company - Woods Cross.
|
|
|
23.1
|
Consent
of PricewaterhouseCoopers LLP, Independent Registered Public Accounting
Firm.
|
|
|
23.2
|
Consent
of DeGolyer and MacNaughton.
|
|
|
31.1
|
Certification
of Chief Executive Officer pursuant to SEC Rule
13(a)-14(a).
|
|
|
31.2
|
Certification
of Chief Financial Officer pursuant to SEC Rule
13(a)-14(a).
|
|
|
32.1
|
Certification
of Chief Executive Officer pursuant to Section 1350 of Chapter 63
of Title
18 of the U.S. Code.
|
|
|
32.2
|
Certification
of Chief Financial Officer pursuant to Section 1350 of Chapter 63
of Title
18 of the U.S. Code.
|
|
|
99.1*
|
Form
of Indemnity Agreement of Registrant (filed as Exhibit 99.1 in
Registrant's Annual Report on Form 10-K filed on March 31, 2005,
File No.
1-9735).
|
|
|
99.2*
|
Form
of "B" Group Trust (filed as Exhibit 28.3 to Amendment No. 1 to
Registrant's Registration Statement on Form S-4 filed on May 22,
1987,
File No. 33-13240).
|
|
|
*
Incorporated by reference
**
Portions of this exhibit have been omitted pursuant to a request
for
confidential treatment
|
||
77
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned, thereunto duly authorized on February 28, 2007.
BERRY
PETROLEUM COMPANY
|
/s/
Robert F. Heinemann
|
/s/
Ralph J. Goehring
|
/s/
Steven B. Wilson
|
|
ROBERT
F. HEINEMANN
|
RALPH
J. GOEHRING
|
STEVEN
B. WILSON
|
|
President,
Chief Executive Officer
|
Executive
Vice President and
|
Controller
|
|
and
Director
|
Chief
Financial Officer
|
(Principal
Accounting Officer)
|
|
|
(Principal
Financial Officer)
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in the
capacities on the dates indicated.
|
Name
|
Office
|
Date
|
|
|
|
|
|
/s/
Martin H. Young, Jr.
|
Chairman
of the Board,
|
February
28, 2007
|
|
Martin
H. Young, Jr.
|
Director
|
|
|
/s/
Robert F. Heinemann
|
President,
Chief Executive Officer
|
February
28, 2007
|
|
Robert
F. Heinemann
|
and
Director
|
|
|
|
|
|
|
/s/
Joseph H. Bryant
|
Director
|
February
28, 2007
|
|
Joseph
H. Bryant
|
|
|
|
|
|
|
|
/s/
Ralph B. Busch, III
|
Director
|
February
28, 2007
|
|
Ralph
B. Busch, III
|
|
|
|
|
|
|
|
/s/
William E. Bush, Jr.
|
Director
|
February
28, 2007
|
|
William
E. Bush, Jr.
|
|
|
|
|
|
|
|
/s/
Stephen L. Cropper
|
Director
|
February
28, 2007
|
|
Stephen
L. Cropper
|
|
|
|
|
|
|
|
/s/
J. Herbert Gaul, Jr.
|
Director
|
February
28, 2007
|
|
J.
Herbert Gaul, Jr.
|
|
|
|
|
|
|
|
/s/
Thomas J. Jamieson
|
Director
|
February
28, 2007
|
|
Thomas
J. Jamieson
|
|
|
|
/s/
J. Frank Keller
|
Director
|
February
28, 2007
|
|
J.
Frank Keller
|
|
|
|
/s/
Ronald J. Robinson
|
Director
|
February
28, 2007
|
|
Ronald
J. Robinson
|
|
|
78
Exhibit
10.1
DESCRIPTION
OF THE SHORT-TERM CASH INCENTIVE PLAN (BONUS)
Annual
cash incentive awards, which are designed to provide short-term performance
incentives, are made to employees to recognize and reward corporate and
individual performance. The plan in effect provides an annual incentive
fund of
up to 3.75% of the Company's annual net income, with certain adjustments,
to
potentially any and all employees upon achievement of the Company’s growth and
profitability goals.
Annually,
Management and the Board will set specific targets to be achieved which
will
determine the cash payment as a whole and then to each eligible employee
based
on a formula. Executive Officers have performance metrics established for
each
of the following: net income, production, operating expenditures, proved
reserves, and finding and development costs, all modified by environmental
health and safety (“EHS”) performance. All other employees have performance
metrics for production and EHS. The Board retains the flexibility to adjust
various items to assure compliance with the intent of the cash incentive
awards.
All annual cash bonuses for executive officers are approved by the Compensation
Committee and the Board of Directors.
1
Confidential
Portions Redacted and Filed with the Commission [***] Symbolizes Language
Omitted Pursuant to an Application For Confidential Treatment.
CRUDE
OIL SUPPLY AGREEMENT
by
and between
BERRY
PETROLEUM COMPANY
and
HOLLY
REFINING AND MARKETING COMPANY - WOODS CROSS
dated
February
27, 2007
|
TABLE
OF CONTENTS
|
|||
|
ARTICLE
1 REFERENCES AND DEFINITIONS; RELATIONSHIP OF THE
PARTIES
|
|||
|
1.1
|
Definitions
|
1
|
|
|
1.2
|
Attachments
|
1
|
|
|
1.3
|
Independent
Contractor; No Partnership
|
1
|
|
|
ARTICLE
2 SUPPLY, DELIVERY AND RECEIPT OF CRUDE OIL
|
2
|
||
|
2.1
|
Supply
and Receipt of Base Daily Volumes.
|
2
|
|
|
2.2
|
Supply
and Receipt of Incremental Daily Volumes.
|
2
|
|
|
2.3
|
Delivery
Point
|
2
|
|
|
2.4
|
Scheduling.
|
3
|
|
|
2.5
|
Dedication
of Production
|
3
|
|
|
ARTICLE
3 QUALITY AND MEASUREMENT
|
3
|
||
|
3.1
|
Quality
|
3
|
|
|
3.2
|
Evidence
of Quality
|
4
|
|
|
3.3
|
Measurement
|
4
|
|
|
3.4
|
Observation
|
4
|
|
|
ARTICLE
4 PRICING
|
4
|
||
|
4.1
|
Pricing
Formula
|
4
|
|
|
4.2
|
Non-Conforming
Batch
|
5
|
|
|
4.3
|
Change
of Conventional Light Sweet Benchmark
|
5
|
|
|
ARTICLE
5 TERM
|
5
|
||
|
5.1
|
Term
|
5
|
|
|
ARTICLE
6 TITLE; RISK OF LOSS
|
5
|
||
|
6.1
|
Title
Warranty
|
5
|
|
|
6.2
|
Disclaimer
|
6
|
|
|
6.3
|
Transfer
of Title and Associated Risks Warranty
|
6
|
|
|
ARTICLE
7 PAYMENTS, INVOICES AND CREDIT REQUIREMENTS
|
6
|
||
|
7.1
|
Payment
Per Warranty
|
6
|
|
|
7.2
|
Monthly
Invoices Warranty
|
6
|
|
|
7.3
|
Necessary
Documents Warranty
|
6
|
|
|
7.4
|
Payment
of Invoices Warranty
|
6
|
|
|
7.5
|
Late
Payments
|
7
|
|
|
7.6
|
Corrections;
Disputes
|
7
|
|
|
7.7
|
Financial
Responsibility
|
7
|
|
|
7.8
|
Continuing
Guaranty
|
8
|
|
|
ARTICLE
8 REPRESENTATIONS AND WARRANTIES
|
8
|
||
|
8.1
|
Supplier
Representations and Warranties
|
8
|
|
|
8.2
|
Refiner
Representations and Warranties
|
9
|
|
i
|
ARTICLE
9 EVENTS OF DEFAULT; REMEDIES; LIMITATION ON DAMAGES
|
9
|
||
|
9.1
|
Events
of Default
|
9
|
|
|
9.2
|
Remedies
|
10
|
|
|
9.3
|
Right
of Set-Off Warranty
|
10
|
|
|
9.4
|
Limitation
on Damages
|
11
|
|
|
ARTICLE
10 FORCE MAJEURE
|
11
|
||
|
10.1
|
General
|
11
|
|
|
10.2
|
Notice
Requirements Warranty
|
11
|
|
|
10.3
|
Efforts
to Remove Force Majeure
|
11
|
|
|
ARTICLE
11 TERMINATION
|
12
|
||
|
11.1
|
Termination
|
12
|
|
|
11.2
|
Effect
of Termination
|
12
|
|
|
11.3
|
Termination
for Extended Force Majeure
|
12
|
|
|
ARTICLE
12 INDEMNIFICATION AND DAMAGES
|
13
|
||
|
12.1
|
Refiner’s
Indemnification Obligations
|
13
|
|
|
12.2
|
Supplier’s
Indemnification Obligations
|
13
|
|
|
12.3
|
EXPRESS
NEGLIGENCE
|
13
|
|
|
ARTICLE
13 GENERAL PROVISIONS
|
13
|
||
|
13.1
|
Confidentiality
|
13
|
|
|
13.2
|
Consultation
as to Announcements
|
14
|
|
|
13.3
|
Notices
|
14
|
|
|
13.4
|
Taxes
|
17
|
|
|
13.5
|
Headings
and References
|
17
|
|
|
13.6
|
Rules
of Interpretation
|
17
|
|
|
13.7
|
Resolution
of Disputes – Negotiation and Arbitration
|
17
|
|
|
13.8
|
Governing
Law
|
20
|
|
|
13.9
|
Assignment;
Delegation
|
20
|
|
|
13.1
|
Time
and Performance of Essence
|
20
|
|
|
13.11
|
Nonwaiver;
No Third-Party Beneficiaries
|
20
|
|
|
13.12
|
Counterparts;
Severability; Survival
|
21
|
|
|
13.13
|
Expenses
|
21
|
|
|
13.14
|
Further
Assurances
|
21
|
|
|
13.15
|
Entire
Agreement; Amendment; Drafting
|
21
|
|
|
SCHEDULE
1.1
|
DEFINITIONS
|
1.1
|
|
|
SCHEDULE
2.4
|
QUALITY
RANGES OF CRUDE OIL
|
2.4
|
|
|
SCHEDULE
3.2
|
QUALITY
TESTING PROCEDURES
|
3.2
|
|
|
SCHEDULE
3.3
|
MEASUREMENT
PROCEDURES
|
3.3
|
|
|
SCHEDULE
7.8
|
CONTINUING
GUARANTY
|
7.8
|
|
|
SCHEDULE
11.1(A)CONTINUING GUARANTY (FOR EXTENSION PERIOD)
|
11.1(A)
|
||
ii
CRUDE
OIL SUPPLY AGREEMENT
THIS
CRUDE OIL SUPPLY AGREEMENT
entered
into on February 27, 2007 for performance commencing as of July 1, 2007 (the
“Effective
Date”),
is
made by and between Berry Petroleum Company, a Delaware corporation
(“Supplier”),
and
Holly Refining & Marketing Company - Woods Cross, a Delaware corporation
(“Refiner”).
Supplier and Refiner may each be referred to hereinafter individually as a
“Party”
or
collectively as the “Parties.”
RECITALS:
A. WHEREAS
Refiner
is investing significant capital in order to process increased volumes of black
wax crude oil at its Woods Cross refinery (the “Refinery”)
located at Salt Lake City, in the State of Utah and is therefore interested
in
securing a long term supply of black wax crude oil blend for the Refinery;
and
B. WHEREAS
Supplier
and Refiner have considered the mutual benefit of a long term black wax crude
oil supply agreement containing price terms and volume commitments, all as
set
forth in this Agreement;
NOW
THEREFORE,
in
consideration of the foregoing, the representations, warranties, covenants,
agreements and undertakings contained in this Agreement and other good and
valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the Parties agree as follows:
ARTICLE
1
REFERENCES
AND DEFINITIONS; RELATIONSHIP OF THE PARTIES
1.1 Definitions.
Capitalized terms used in this Agreement and the Schedules hereto, unless
otherwise defined herein, have the meanings given to those terms in Schedule
1.1.
1.2 Attachments.
The
following Schedules are attached to this Agreement and are incorporated into
this Agreement by this reference:
Schedule
1.1 Definitions
Schedule
2.1 Quality
Ranges of Crude Oil
Schedule
2.3 Delivery
Point
Schedule
3.2 Quality
Testing Procedures
Schedule
3.3 Measurement
Procedures
Schedule
7.8 Continuing
Guaranty
Schedule
11.1(a) Continuing
Guaranty (For Extension Period)
1.3 Independent
Contractor; No Partnership.
Each
Party’s duties and performance under this Agreement shall be those of an
independent contractor, as defined by Applicable Laws. The Parties expressly
agree and acknowledge that (a) nothing in this Agreement shall be deemed to
make
the Parties partners or joint venturers, and (b) neither Party shall have any
right, power or authority to enter into any agreement or undertaking for, or
act
on behalf of, or to act as or be an agent or representative of, or to otherwise
bind, the other Party except as expressly provided herein.
1
ARTICLE
2
SUPPLY,
DELIVERY AND RECEIPT OF CRUDE OIL
2.1 Supply
and Receipt of Base Daily Volumes.
(a) During
the Term and subject to Section
2.1(b),
Supplier shall sell and deliver to Refiner at the Delivery Point, and Refiner
shall buy and take delivery at the Delivery Point 3,200 Barrels of Crude Oil
per
Day (the “Base
Daily Volume”).
(b) If
Refiner has delivered to Supplier a certificate certifying that the Refinery
Modification Completion has occurred, as soon thereafter as reasonably possible
for Supplier to accomodate but in any event within ninety (90) Days from the
date of such delivery of the certificate (or such later date as may be specified
in the certificate) the Base Daily Volume shall be increased to 5,000 Barrels
of
Crude Oil per Day.
(c) A
50%
Daily variation in the quantity of Crude Oil delivered pursuant to this
Section
2.1
shall be
permitted; provided that for each Month or portion thereof during the Term,
the
average Daily quantity delivered pursuant to this Section
2.1
shall
equal the Base Daily Volume.
2.2 Supply
and Receipt of Incremental Daily Volumes.
(a) Not
later
than 120 Days prior to the start of any Contract Year, Supplier may provide
a
notice to Refiner indicating the Daily volume of Crude Oil production in
addition to the Base Daily Volumes that Supplier and its Affiliates reasonably
anticipate producing during such Contract Year. Within 30 Days following receipt
of such notice by Refiner, Refiner shall notify Supplier of the portion, if
any,
of such additional Daily volume of Crude Oil that Refiner desires to purchase.
Failure to deliver such notice shall be deemed an election by Refiner not to
purchase any of such additional Daily volume. Such portion, if any, that Refiner
elects to purchase in its notice to Supplier shall be referred to herein as
the
“Incremental
Daily Volume”.
For
the Contract Year immediately following such notice from Refiner, but not for
the remainder of the Term following such Contract Year, Supplier shall sell
and
deliver to Refiner at the Delivery Point, and Refiner shall buy and take
delivery at the Delivery Point each Day the Incremental Daily Volume, in
addition to the Base Daily Volume.
(b) A
50%
Daily variation in the quantity of Crude Oil delivered pursuant to this
Section
2.2
shall be
permitted; provided that for each Month or portion thereof during the Term,
the
average Daily quantity delivered pursuant to this Section
2.2
shall
equal the Incremental Daily Volume.
2.3 Delivery
Point.
Supplier will tender delivery of all Crude Oil to be delivered to Refiner
pursuant to this Agreement at the outlet flanges of Supplier’s lease tankage on
wells identified on Supplier’s Uinta Basin, Utah, properties from time to time
in writing by Supplier to Refiner as referenced on Schedule 2.3 (the
“Delivery
Point”).
Refiner shall accept delivery of such Crude Oil at the Delivery
Point.
2
2.4 Scheduling.
(a) The
Parties shall coordinate to schedule the delivery and receipt of Crude Oil
in
accordance with the procedures and limitations of the relevant transport and
delivery and receiving facilities; provided that this Section
2.4(a)
shall
not limit the obligations of the Parties pursuant to Sections
2.1
and
2.2.
(b) Notice
of Significant Events.
180
Days in advance of any planned material events which impact the Refinery’s
ability to process or Supplier’s ability to produce the Crude Oil to be
delivered hereunder, such as a refinery turnaround or a production facility
turnaround (a “Significant
Event”)
the
affected Party shall notify the other Party regarding schedule and volume
impacts of any Significant Event that may, in the case of Refiner, reduce its
processing capabilities, or in the case of Supplier, reduce its supplying
capabilities, by more than 10% of the Contract Daily Volume for more than seven
Days. The Parties shall use commercially reasonable efforts to reduce the
adverse impacts of all Significant Events on each Party. If the required notice
has been provided, the Parties obligations under Sections
2.1
and
2.2
shall be
excused during any such Significant Events. Each Party agrees to keep the other
Party promptly advised of all developments in the status of any Significant
Event. No Significant Event shall be scheduled during the Term which has the
effect of reducing the Base Annual Volume in any one 12 month period by more
than 10%.
2.5 Dedication
of Production.
Supplier will dedicate its (and its Affiliates’) first production of Crude Oil
to satisfy the requirements of this Agreement. Without limiting the foregoing,
Supplier agrees that any agreements by Supplier or its Affiliates to sell Crude
Oil to a purchaser other than Refiner shall be satisfied only out of production
in excess of the volumes to be sold to Refiner pursuant to this Agreement.
In
the event Supplier elects to market its production in excess of the Base Daily
Volumes and Refiner chooses to bid for such volumes, Supplier will contract
to
sell the incremental volumes to Refiner if Refiner exceeds or matches the
highest bid from other potential purchasers.
ARTICLE
3
QUALITY
AND MEASUREMENT
3.1 Quality
(a) The
crude
oil delivered to Refiner shall conform to the Minimum Quality Specifications
(“Crude
Oil”).
Without limiting any other provision of this Agreement, in no event shall
Supplier inject any unsaturated stock or vis-broken stock, LPG, Natural Gasoline
or Lube Oils as a part of Crude Oil delivered under this Agreement. If Refiner
deems the quality of Crude Oil delivered pursuant to this Agreement to be
inconsistent with Prudent Industry Practices, Supplier and Refiner shall work
together to develop additional delivered quality management processes and
specifications. If Supplier and Refiner are unable to develop such additional
processes and specifications, the matter shall be resolved by arbitration in
accordance with Section 13.7.
3
(b) Supplier
warrants that the Crude Oil delivered to the Refiner conforms to the minimum
specifications set forth in Schedule
2.1
(the
“Minimum
Quality Specifications”)
and is
not contaminated by any foreign chemicals.
3.2 Evidence
of Quality.
For
purposes of determining whether the crude oil delivered pursuant to this
Agreement meets the Minimum Quality Specifications, Refiner will have 30 Days
from the date that a delivery arrives at the Refinery to notify Supplier that
it
has tested the delivery and that the test results indicate that the delivery
did
not meet the Minimum Quality Specifications. Supplier will have 30 Days from
receipt of such notification to
provide the results of sample analysis performed by a reputable independent
third party testing service using the testing methods described in Schedule
3.2.
Any
rejection of volumes or price adjustment will be based on such injection sample
test results.
3.3 Measurement.
Measurement of Crude Oil shall be in accordance with the measurement procedures
set forth on Schedule
3.3.
3.4 Observation.
Each
Party shall have the right to have a representative witness all gauges, tests,
or measurements performed in connection with this Agreement providing that
reasonable advance notice is given. In the absence of the other party’s
representative, such gauges, tests, and measurements shall be deemed to be
correct absent manifest error.
ARTICLE
4
PRICING
4.1 Pricing
Formula.
The price (the “Price
Formula”)
for
Crude Oil delivered pursuant to this Agreement shall be set as follows:
(a) The
price
for Base Daily Volumes (US$/Barrel) shall equal *** multiplied by WTI, Cushing
(US$/Barrel).
(b) The
price
for Incremental Daily Volumes (US$/Barrel) shall equal *** multiplied by WTI,
Cushing (US$/Barrel).
4.2 Non-Conforming
Batch.
If Supplier supplies a delivery which does not meet the Minimum Quality
Specifications, Refiner shall be entitled either to reject such volumes (in
which case Supplier shall be responsible for the costs associated with the
redelivery to Supplier of such volumes) or to accept such volumes. In either
case, the Parties agree to execute a price adjustment for volumes delivered
in
the non-conforming delivery, including a full refund of the purchase price
and
associated costs (e.g., transportation costs) incurred by Refiner for volumes
that are rejected.
4.3 Change
of Conventional Light Sweet Benchmark.
The Parties agree that WTI, Cushing is intended to measure the fair market
value of conventional light sweet crude oil on a North American based futures
exchange. If at any time in the future WTI, Cushing ceases to be representative
of the North American conventional light sweet crude oil markets, the Parties
agree to determine a new light sweet crude oil benchmark for use in the Price
Formula. In the event of such a cessation, either Party may declare an
initiation date for the process of adjusting the Price Formula by giving notice
to the other Party. The new benchmark shall be based on a
4
North
American futures contract, if such contract exists. The Price Formula will
be
adjusted for quality, transportation and location for the new benchmark using
the process outlined below:
(a) Compare
Historical Period Average Prices for the current benchmark versus the proposed
new benchmark to determine a linear correlation (y=mx) between the fair market
values of the current benchmark versus the proposed new benchmark and apply
this
correlation to the Price Formula.
(b) After
transition to the new light crude benchmark and establishing the revised Price
Formula, either Party may request a review of the Price Formula after the elapse
of 6 Months. Any changes to the Price Formula resulting from the review shall
be
effective immediately after the review is complete and agreed by both Parties.
The review results shall not have any retroactive effect and only one review
period shall be permitted during the Term.
ARTICLE
5
TERM
5.1 Term.
This term of this Agreement (“Term”)
commences at midnight, Applicable Time, on the Effective Date, and expires
at
midnight, Applicable Time, on the date of termination provided in Section
11.1.
ARTICLE
6
TITLE;
RISK OF LOSS
6.1 Title
Warranty.
Supplier warrants that (a) all crude oil delivered pursuant to this Agreement
will be free from encumbrances and other adverse interests and (b) Supplier
has
the right to sell and pass title to Refiner of all such crude oil.
6.2 Disclaimer.
EXCEPT
AS SPECIFICALLY PROVIDED IN SECTIONS
3.1(b),
6.l
AND
ARTICLE
8,
SUPPLIER MAKES NO, AND HEREBY DISCLAIMS ANY, REPRESENTATION OR WARRANTY, EXPRESS
OR IMPLIED, STATUTORY OR OTHERWISE, ABOUT OR RELATING TO THE CRUDE OIL DELIVERED
BY IT HEREUNDER INCLUDING, WITHOUT LIMITATION, WARRANTIES AS TO CONDITION,
QUALITY, MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, OR
OTHERWISE.
6.3 Transfer
of Title and Associated Risks Warranty.Title,
custody and risk of loss to Crude Oil delivered hereunder shall pass from
Supplier to Refiner when Supplier delivers Crude Oil to Refiner at the Delivery
Point, it being understood and agreed that any casualty, loss, escape or
contamination occurring before and to the Delivery Point shall be the
responsibility of Supplier and after the Delivery Point shall be the
responsibility of Refiner. Except as otherwise provided in this Agreement,
Refiner shall be responsible for arranging and paying for all transportation
from the Delivery Point to the Refinery.
5
ARTICLE
7
PAYMENTS,
INVOICES AND CREDIT REQUIREMENTS
7.1 Payment
Per Warranty.
Refiner
agrees
to pay Supplier the Purchase Price for each Barrel of Crude Oil Supplier
delivers to the Delivery Point pursuant to
this
Agreement.
7.2 Monthly
Invoices Warranty.
Supplier
shall invoice Refiner for Crude Oil delivered pursuant to this Agreement, on
a
Monthly
basis.
Such invoice shall include the following information: the Month of delivery
under the transaction; the volume(s) of delivery; the Purchase Price; and the
due date of payment pursuant to Section
7.4.
7.3 Necessary
Documents Warranty.
Upon
request, each Party agrees to furnish the other Party all source documents
for
each volume of crude oil delivered pursuant to this Agreement that are
reasonably available to the furnishing Party; provided that furnishing source
documents shall not be a precondition for payment unless expressly so agreed
by
the Parties. Source documents include delivery tickets, transfer settlements,
or
other shipping/loading documents provided by a pipeline or other carrier
indicating the type, quality, volume, and other characteristics of the crude
oil
delivered.
7.4 Payment
of Invoices
Warranty.
Refiner
shall pay all amounts owed by it hereunder by electronic funds transfer to
Supplier’s account designated in Section
13.3(c)
with
immediately available funds by the later of the 5th Business Day after the
applicable invoice was received or the 20th Day of the Month following the
Month
of crude oil delivery. If payment falls due on a Saturday or a bank holiday
of
the bank where the designated account is located other than Monday, payment
shall be due on the preceding banking day of such bank. If payment falls due
on
a Sunday or a Monday bank holiday of such bank, payment shall be due on the
next
banking day of such bank. Payment shall be deemed made on the date good funds
are credited to Supplier's account at such bank.
7.5 Late
Payments.
Any payments that are not made when due under this Agreement pursuant to Section
7.4 shall bear interest at a per annum rate which shall be two percentage points
above the U.S. prime rate as published in the Wall Street Journal (or such
other
publication as the parties may agree from time to time) in effect on the date
payment was due from the date such payment is due until such payment is made
paid in full.
7.6 Corrections;
Disputes.
Invoices and payments shall be subject to correction for billing errors for
a
period of 24 Months after the end of the Month prior to which the invoice was
issued. No adjustment or correction shall be made and all records and payments
shall be conclusively presumed to be final and shall not be subject to
examination, unless notice specifying the error or inaccuracy is given within
such 24-Month period. If Refiner disputes the correctness of any invoice,
Refiner shall nevertheless pay the full amount of the invoice (including the
disputed portion) and shall notify Supplier of the specific basis for disputing
the correctness of the invoice as soon as practical after becoming aware of
the
basis for the dispute, and Refiner shall be entitled to a refund for
overpayments plus interest at the rate described in Section 7.5 calculated
from
the date of payment until refunded.
6
7.7 Financial
Responsibility.
Notwithstanding anything in this Agreement, if at any time, Parent has a net
worth of less than $200,000,000 or should Supplier reasonably believe that
such
Parent’s net worth is less than $200,000,000, Supplier may at anytime require,
by written notice to Refiner, at Refiner’s choice, either 1) advance cash
payment, or 2) satisfactory security in the form of a letter or letters of
credit at Refiner’s expense in a form and from a bank reasonably acceptable to
Supplier, to cover any and all deliveries of Crude Oil. If, on or before
the date specified in Supplier’s notice under this Section 7.7, Refiner does not
prepay or provide the letter or letters of credit, or if Supplier does not
accept another form of credit assurance agreeable to Supplier in Supplier’s sole
discretion, Supplier may terminate this Agreement immediately and Refiner shall
be considered to experience an Event of Default. At any time Parent has a
net worth of less than $200,000,000 or if Supplier reasonably believes that
such
net worth is less than $200,000,000, Seller shall not be obligated to schedule
or complete delivery of the Crude Oil until advance cash payment is made or
said
letter or letters of credit, or if applicable, other credit assurance agreeable
to Supplier, is delivered by Refiner to Supplier. In any event if Parent
or Refiner makes an advance cash payment to Supplier, so long as Refiner is
not
in default, Supplier will deposit said cash payment into an interest bearing
investment earning interest at a rate equivalent to the equivalent yield of
a
thirty (30) day U.S. Treasury note and such earned interest shall be held for
the benefit of Parent or Refiner.
7.8 Continuing
Guaranty.
As a material condition to this Agreement, Refiner shall concurrently deliver
to
Supplier a Continuing Guaranty, in the form attached to this Agreement as
Schedule 7.8.
ARTICLE
8
REPRESENTATIONS
AND WARRANTIES
8.1 Supplier
Representations and Warranties.
Supplier represents and warrants to Refiner that:
(a) It
is
duly organized, validly existing and in good standing under the laws of
Delaware, and has all requisite power and authority to own and lease the
properties and assets it currently owns and leases, and to conduct its
activities as such activities are currently conducted and as contemplated by
this Agreement;
(b) Supplier
has all requisite corporate power, authority and capacity to execute, deliver
and perform this Agreement and to consummate the transactions contemplated
hereby. The execution, delivery and performance of this Agreement and the
consummation of the transactions contemplated hereby by Supplier have been
duly
and validly authorized by all necessary corporate action on its part, and this
Agreement has been duly and validly executed and delivered by Supplier, and
is
the valid and binding obligation of Supplier, enforceable against it in
accordance with its terms, subject to Applicable Laws of bankruptcy, insolvency
and similar laws affecting creditors’ rights and remedies
generally;
(c) The
execution, delivery and performance by Supplier of this Agreement does not
and
will not (i) conflict with or violate any provision of Supplier’s organizational
documents; (ii)
7
violate
any provision of any Applicable Laws; (iii) conflict with, violate, result
in a
breach of, constitute a default under (without regard to requirements of notice,
lapse of time or elections of other Persons, or any combination thereof) or
accelerate or permit the acceleration of the performance required by, any
contracts or other instruments to which either Supplier is a party or by which
Supplier is bound or affected; or (iv) require any consent, approval or
authorization of, or filing of any certificate, notice, application, report,
or
other document with, any Governmental Authority or other Person;
(d) Supplier
is not subject to any Applicable Law that would preclude or prohibit its
fulfillment of any of its obligations hereunder, all in accordance with the
terms and conditions of this Agreement; and
(e) Supplier
has the requisite authority, ability, skills, technical support and capacity
to
perform all of its obligations hereunder with respect to the supply of Crude
Oil
and the operation of its production facilities, all in accordance with this
Agreement in all material respects.
8.2 Refiner
Representations and Warranties.
Refiner represents and warrants to Supplier that:
(a) Refiner
is duly organized, validly existing and in good standing under the laws of
Delaware and has all requisite power and authority to own and lease the
properties and assets it currently owns and leases and to conduct its activities
as such activities are currently conducted and as contemplated by this
Agreement;
(b) Refiner
has all requisite corporate power, authority and capacity to execute, deliver
and perform this Agreement and to consummate the transactions contemplated
hereby. The execution, delivery and performance of this Agreement and the
consummation of the transactions contemplated hereby by Refiner have been duly
and validly authorized by all necessary action on the part of Refiner, and
this
Agreement has been duly and validly executed and delivered by Refiner, and
is
the valid and binding obligation of Refiner, enforceable against Refiner in
accordance with its terms, subject to Applicable Laws of bankruptcy, insolvency
and similar laws affecting creditors’ rights and remedies
generally;
(c) The
execution, delivery and performance by Refiner of this Agreement do not and
will
not (i) conflict with or violate any provision of its organizational documents;
(ii) violate any provision of any Applicable Laws; (iii) conflict with, violate,
result in a breach of, constitute a default under (without regard to
requirements of notice, lapse of time or elections of other Persons, or any
combination thereof) or accelerate or permit the acceleration of the performance
required by, any contracts or other instruments to which it is a party or by
which it or its properties may be bound or affected; or (iv) except in
connection with the construction and operation of the Refinery Modifications,
require any consent, approval or authorization of, or filing of any certificate,
notice, application, report or other document with, any Governmental Authority
or other Person;
(d) Subject
to obtaining any approvals from Governmental Authorities required to construct
and operate the Refinery Modifications, Refiner is not subject to any Applicable
Law
8
that
would preclude or prohibit any of its obligations hereunder, all in accordance
with the terms and conditions of this Agreement; and
(e) Refiner
has the requisite authority, ability, skills, technical support and capacity
to
perform all of its obligations hereunder, all in accordance with this Agreement
in all material respects.
ARTICLE
9
EVENTS
OF DEFAULT; REMEDIES; LIMITATION ON DAMAGES
9.1 Events
of Default.
An
event of default (“Event
of Default”)
with
respect to a Party (the “Defaulting
Party”)
shall
mean any of the following:
(a) the
failure of Defaulting Party to pay when due any payment under this Agreement,
and such payment (and any interest accrued thereon pursuant to this Agreement)
shall remain unpaid for 10 Days following receipt by the Defaulting Party of
notice of failure to pay; or
(b) the
failure of the Defaulting Party to comply in any material respect with any
of
its other obligations under this Agreement, and such failure is not remedied
in
all material respects within 30 Days after notice thereof; or
(c) any
representation or warranty made by the Defaulting Party under this Agreement
is
or was untrue or misleading in any material respect when made and such breach
is
not cured within 30 Days after notice thereof; or
(d) the
entry
of a decree or order by a court having jurisdiction in the premises resulting
from the commencement of proceedings against the Defaulting Party by a third
party and approving as properly filed a petition seeking dissolution or
winding-up of the Defaulting Party under any bankruptcy, insolvency or analogous
laws, or appointing a receiver of the Defaulting Party, and the continuance
of
any such decree or order unstayed, undischarged and in effect for a period
of 20
Days from the date thereof; or
(e) the
institution by the Defaulting Party of proceedings to be adjudicated a bankrupt
or insolvent, or the consent by it to the institution of bankruptcy or
insolvency proceedings against it, or the filing by it of a petition, answer
or
consent seeking dissolution or winding-up under any bankruptcy, insolvency
or
analogous laws, or the consent by it to the filing of any such petition or
to
the appointment of a receiver of the Defaulting Party or the making by it of
a
general assignment for the benefit of creditors, or the Defaulting Party
admitting in writing its inability to pay its debts generally as they become
due.
9.2 Remedies.
Upon
the occurrence and during the continuation of an Event of Default as to the
Defaulting Party, the other Party (the “Non-Defaulting
Party”)
may,
in its sole discretion, (a) notify the Defaulting Party of an early termination
date (which shall be no earlier than the date of such notice and no later than
30 Days after the date of such notice) on which date this Agreement shall
terminate and declare that any amounts of money outstanding hereunder shall
be
due and payable immediately without any further notice or demand of any kind
or
(b) withhold performance of any of its obligations due to the Defaulting Party
until such Event of
9
Default
is cured. Any rights of a Nondefaulting Party under this Section
9.2
shall be
in addition to any other rights or remedies such Nondefaulting Party may have
under this Agreement, at law or in equity.
9.3 Right
of Set-Off Warranty.
Upon the occurrence and during the continuance of an Event of Default, the
Non-Defaulting Party is hereby authorized at any time and from time to time
thereafter, on reasonable notice to the Defaulting Party and to the fullest
extent permitted by law, to set-off and apply any and all indebtedness at any
time owing by the Non-Defaulting Party to or for the credit or the account
of
the Defaulting Party against any and all of the obligations of the Defaulting
Party now or hereafter existing under this Agreement. The Non-Defaulting Party
agrees to promptly notify the Defaulting Party after any such set-off and
application.
9.4 Limitation
on Damages.
Liability for breach of any provision of this Agreement is limited to actual
direct damages only (which in the case of a failure by Supplier to deliver
Crude
Oil that is not permitted by this Agreement shall be deemed to include lost
margins on Refinery production and other costs (e.g., transportation costs)
incidental to such failure), and such actual direct damages are the sole and
exclusive monetary remedy under this Agreement for any such breach. Except
as
provided in the preceding sentence, neither Party is liable for incidental,
punitive, exemplary, consequential, special or indirect damages of any nature
(including damages associated with lost profits, business interruption and
loss
of goodwill) arising at any time, whether in tort (including negligence or
gross
negligence), warranty, strict liability, by contract or statute, under any
indemnity provision (unless such damages are required to be paid to a third
party) or otherwise.
ARTICLE
10
FORCE
MAJEURE
10.1 General.
Notwithstanding anything herein to the contrary, each Party shall be excused
from performance of its obligations hereunder (other than any obligation to
pay
money then due or becoming due with respect to performance prior to the event)
in the event and to the extent its performance is prevented by an event of
Force
Majeure.
10.2 Notice
Requirements Warranty.
If an
event of Force Majeure occurs, the Party whose performance is prevented shall
promptly provide notice to the other Party of the event of Force Majeure, the
nature of the event, the extent to which the event of Force Majeure affects
or
delays the affected Party’s performance hereunder, the particular obligations so
affected, the steps taken and proposed to be taken to lessen and cure the Force
Majeure, and the estimated duration of the event of Force Majeure. If there
is
any material change, addition or alteration to the circumstances giving rise
to,
or the information provided pursuant to, the notice, the affected Party shall
promptly provide the other Party with notice of the same.
10.3 Efforts
to Remove Force Majeure.
At all
times during an event of Force Majeure, both Parties shall use commercially
reasonable efforts to remove the event of Force Majeure and to avoid or minimize
the consequences of the event of Force Majeure; provided that nothing contained
in this Agreement shall be construed as requiring either Party hereto to accede
to the demands of labor or labor unions it considers unreasonable in its sole
discretion. The
10
.performance
of this Agreement shall be resumed as soon as practicable after such disability
has been removed.
ARTICLE
11
TERMINATION
11.1 Termination.
This
Agreement shall terminate on the earliest of:
(a) Expiration
of Primary Term.
The
date that is the six year anniversary of the Effective Date; provided that
a
Party has provided notice of such termination to the other Party at least 120
Days prior to the expiration of such period; provided further that the
termination date shall automatically be extended for one additional year if
such
notice is not provided, and for additional one-year periods if such notice
is
not provided at least 120 Days prior to the end of each such one-year extension.
In the event of an extension for an additional year, no later than 60 days
prior
to the beginning of any such extension, Supplier may request that Refiner
provide to Supplier a Continuing Guaranty (For Extension Period) substantially
in the form attached hereto as Schedule 11.1(a), for such additional year.
If
Refiner does not provide such a guaranty within 30 Days after such request,
such
extension shall not be effective and this Agreement shall terminate at the
end
of the current term;
(b) Event
of Default.
The
date on which either Party terminates this Agreement pursuant to Section
9.2;
(c) Force
Majeure.
The
date on which the applicable Party terminates this Agreement pursuant to
Section
11.3,
by
providing notice of such termination to the other Party;
(d) Processes
and Specifications.
The
date on which Refiner terminates this Agreement pursuant to Section
3.1(a),
by
providing notice to Supplier; and
(e) Change
in Law.
In the
event of a change in Applicable Laws that Refiner reasonably determines will
have
an
adverse effect on anticipated refinery economics using LP analysis and industry
practice, the date indicated in a notice by Refiner to Supplier; provided that
such termination date shall not be sooner than 180 days following the date
of
such notice. Whether or not Refiner’s determination satisfies the standard set
forth in this Section 11.1(e) shall be subject to arbitration under Section
13.7.
11.2 Effect
of Termination.
Termination of this Agreement for any reason shall not affect: (i) each Party’s
obligation to perform its obligations arising hereunder prior to such
termination, (ii) each Party’s indemnification and defense obligations and any
other duties of either Party which by their nature are to be performed after
termination of this Agreement, or (iii) damages as a result of an Event of
Default.
11.3 Termination
for Extended Force Majeure.
If an event of Force Majeure claimed by Refiner or Supplier persists for a
continuous period of at least 180 Days or if the duration of an event of Force
Majeure claimed by Refiner or Supplier is reasonably estimated by the Party
claiming Force Majeure to be at least 180 Days, then the Party not claiming
the
Force Majeure shall have the right, but not the obligation, to terminate this
Agreement by giving notice of termination to the other Party. For purposes
of
this Section
11.3,
if the
period between the end of
11
one
event
of Force Majeure and the commencement of another event of Force Majeure is
less
than 30 Days, the period of Force Majeure shall be deemed to be continuous,
but
the time between the Force Majeure periods shall not be counted in determining
the 180-Day period required before termination hereunder is allowed.
ARTICLE
12
INDEMNIFICATION
AND DAMAGES
12.1 Refiner’s
Indemnification Obligations.
Refiner
agrees to indemnify, defend and hold harmless Supplier Indemnified Parties
from
and against any and all Claims arising out of, relating to or in connection
with:
(a) Any
injury or death of persons or damage to property arising out of, relating to,
or
in connection with, the transportation, carriage, handling, care, storage,
resale or use of the crude oil sold hereunder after delivery to Refiner at
the
Delivery Point, except to the extent arising out of a Supplier Indemnified
Party’s gross negligence or willful misconduct; and
(b) Any
breach by Refiner of any of its representations, warranties, covenants,
agreements or obligations herein.
12.2 Supplier’s
Indemnification Obligations.
Supplier agrees that it shall indemnify, defend and hold harmless Refiner
Indemnified Parties from and against any and all Claims arising out of, relating
to, or in connection with:
(a) Any
injury or death of persons or damage to property arising out of, relating to,
or
in connection with, the production, transportation, carriage, handling, care,
storage, resale or use of the crude oil sold hereunder until delivery to Refiner
at the Delivery Point except to the extent arising out of a Refiner Indemnified
Party’s gross negligence or willful misconduct; and
(b) Any
breach by Supplier of any of its representations, warranties, covenants,
agreements or obligations herein.
12.3 EXPRESS
NEGLIGENCE.
EXCEPT AS EXPRESSLY PROVIDED OTHERWISE ABOVE, THE FOREGOING INDEMNITIES SET
FORTH IN THIS ARTICLE
12
ARE INTENDED TO BE ENFORCEABLE AGAINST THE PARTIES REGARDLESS OF THE SIMPLE
OR
GROSS NEGLIGENCE (WHETHER SOLE, CONCURRENT, ACTIVE OR PASSIVE) OR OTHER FAULT
OR
STRICT LIABILITY OF ANY INDEMNIFIED PARTIES.
ARTICLE
13
GENERAL
PROVISIONS
13.1 Confidentiality.
Neither this Agreement nor information or documents that come into the
possession of a Party or its Affiliates in connection with the performance
of
this Agreement may be used or communicated to Persons (other than the Parties
and their Affiliates) without the mutual written agreement of the Parties,
except that either Party shall have the right to disclose such information
or
documents without obtaining the other Party’s prior consent in any of the
situations described below:
12
(a) Accountants,
bankers, other professional consultants or underwriters, provided such
disclosure is solely to assist the purpose for which the aforesaid were so
engaged and further provided that such Persons agree to hold such information
or
documents under terms of confidentiality equivalent to this Section
13.1
and for
the benefit of the Parties;
(b) To
legal
counsel, provided such disclosure is solely to assist the purpose for which
the
aforesaid were so engaged;
(c) Prospective
assignees of a Party’s interest under this agreement or Persons potentially
providing financing to a Party, provided that such Persons agree to hold such
information or documents under terms of confidentiality equivalent to this
Section
13.1
and for
the benefit of the Parties;
(d) If
required by any court of law or any Applicable Law, or if requested by a
Governmental Authority having or asserting jurisdiction over a Party and having
or asserting authority to require such disclosure in accordance with that
authority, or pursuant to the rules of any recognized stock exchange or agency
established in connection therewith;
(e) If
required, in the reasonable good faith judgment of the disclosing Party, as
a
response to any environmental or other emergency; and
(f) To
the
extent any such information or document has entered the public domain other
than
through the fault or negligence of the Party receiving the information.
13.2 Consultation
as to Announcements.
Without limiting Section
13.1,
no
public announcement or press release concerning the transactions contemplated
by
this Agreement shall be made by either Party without prior consultation with
the
other Party; provided that such consultation shall not be required for any
public announcement or press release required to be made: (a) under Applicable
Law; or (b) by the reasonable good faith judgment of the disclosing Party as
a
response to any environmental or other emergency; provided further that all
such
consultations and reviews shall be completed within 24 hours of either Party
seeking the other’s consultation, a disclosing Party shall be under no
obligation to accept the consulting Party’s comments or requirements, and after
24 hours the disclosing Party shall be entitled to make the proposed disclosure
if permitted by Section
13.1.
13.3 Notices.
i) Addresses.
All
notices, requests, waivers, consents, approvals, agreements and other
communications under this Agreement shall, except as expressly provided
otherwise herein, be in writing to be effective and shall be delivered in person
or by certified mail with postage prepaid and return receipt requested, courier
or overnight delivery service with charges prepaid or facsimile transmission,
and if to Supplier, addressed as follows:
Berry
Petroleum Company
Attention:
Manager of Marketing
5201
Truxtun Avenue, Suite 300
Bakersfield,
CA 93309
13
Fax
No.
(661) 616-3882;
Copy
to:
Musick
Peeler & Garrett LLP
Attn:
Laura K. McAvoy, Esq.
2801
Townsgate Road, Suite 200
Westlake
Village, CA 91361
Fax
No.
(805) 418-3101
and
if to
Refiner, addressed as follows:
Holly
Refining & Marketing Company - Woods Cross
Attention:
[--]
100
Crescent Court
Suite
1600
Dallas,
Texas 75201
Fax
No.
214-871-3560
Copy
to:
Office
of
General Counsel
100
Crescent Court
Suite
1600
Dallas,
Texas 75201.
Either
Party shall have the right to change its address by notice to the other Party
at
the addresses in force hereunder.
(b) Effectiveness
of Notices.
Any
communications addressed as described above shall be deemed to have been
received as follows:
(i) If
delivered in person, when delivered;
(ii) If
delivered by facsimile, on the date of transmission thereof as reflected on
the
confirmation of the transmitting machine if such confirmation reflects
transmission of such facsimile prior to 5:00 P.M., Applicable Time, on a
Business Day; provided that if any such confirmation reflects that such
transmission occurred after 5:00 P.M., Applicable Time, on a Business Day or
any
time on a non-Business Day, such communication shall be deemed to have been
received on the next Business Day;
(iii) If
delivered by certified mail, on the third Business Day following the date of
mailing as shown on the certified mail receipt; and
(iv) If
delivered by overnight delivery service, on the Business Day on which it is
actually delivered by such delivery service as shown on the receipt provided
to
the delivering Party by the overnight delivery service or the next Business
Day
if delivered on a non-Business Day.
14
(c) Wire
Transfer Information.
Wire
transfers to Supplier shall be made in accordance with the following
instructions:
Berry
Petroleum Company
Wells
Fargo Bank
Denver,
CO
ABA
Routing No./ Transit Number: ***
Account
No.: ***.
Any
questions regarding wire transfers to Supplier should be directed
to:
Berry
Petroleum Company
Attn:
Treasurer
Phone:
(661) 616-3809
Facsimile:
(661) 616-3884.
Supplier
shall have the right to change the information provided in this Section
13.3(c)
by
notice in accordance with Section
13.3(a).
(d) Wire
transfers to Refiner shall be made in accordance with the following
instructions:
Holly
Refining & Marketing Company
Bank
of
America
Charlotte,
North Carolina
ABA
Routing No. ***
Account
No.: ***
Any
questions regarding wire transfers to Supplier should be directed
to:
Holly
Refining & Marketing Company - Woods Cross
Attn:
Steve Wise, Treasurer
Phone:
214-871-3877
Facsimile:
214-237-3051.
Refiner
shall have the right to change the information provided in this Section
15.3(d)
by
notice in accordance with Section
15.3(a).
13.4 Taxes.
Refiner shall pay, without duplication, and be responsible for all sales taxes
assessed as a result of the sale of crude oil hereunder imposed or assessed
on
itself or Supplier as a result of this Agreement but, for the avoidance of
doubt, shall not be responsible for any income, severance, ad valorem or other
taxes imposed on Supplier.
13.5 Headings
and References.
(a) Headings.
The
headings are inserted for convenience only and are to be ignored in construing
this Agreement.
15
References.
References to articles, sections or paragraphs are to articles, sections or
paragraphs of this Agreement. The words “hereto,” “herein,” “hereof,”
“hereunder,” “this Agreement” and similar expressions mean and refer to this
Agreement as a whole and not to any particular portion or provision of this
Agreement.
13.6 Rules
of Interpretation.
(a) The
singular includes the plural and vice versa.
(b) Except
as
otherwise expressly provided herein, all references to “$” or money mean Dollars
and all payments hereunder or pursuant hereto shall be made in
Dollars.
(c) The
words
“include,” “includes” and “including” shall be deemed to be followed by the
words “without limitation.”
(d) If
a
conflict or inconsistency exists between any exhibit or schedule and this
Agreement (exclusive of the exhibits and schedules), the provisions of this
Agreement (exclusive of the exhibits and schedules) shall control. If any
conflict or inconsistency exists between or among the exhibits and schedules,
the exhibit or schedule dealing with the matter in more detail shall
control.
(e) Except
as
otherwise expressly provided herein, all references in this Agreement to
contracts, agreements and other documents shall be deemed to refer to such
contracts, agreements and other documents, as amended, modified and supplemented
from time to time.
(f) Except
as
otherwise expressly provided herein, all references to any Applicable Law is
a
reference to such Applicable Law as amended, modified or re-enacted from time
to
time and any replacements thereof.
13.7 Resolution
of Disputes - Negotiation and Arbitration
(a) Negotiation
Period.
The
Parties shall endeavor in good faith to negotiate a settlement of any and all
disputes arising out of or related to this Agreement, its performance, validity
or the breach or termination of this Agreement, regardless of whether such
dispute is based on common law, contractual or statutory causes of action,
including tort claims (each a “Dispute”).
(b) Initiation
of Arbitration.
The
pre-arbitration negotiation process provided in the foregoing Section 13.7(a)
is
to be considered a settlement negotiation for the purposes of all state and
federal rules protecting disclosures made during such negotiations from later
discovery or use in evidence. If a Dispute is not resolved within 45 Days after
either Party first notifies the other of the Dispute in a written request for
negotiations, or such later date as may be mutually agreed by the Parties,
then
each Party shall have the right at any time thereafter to refer the Dispute
to
binding arbitration under the International Institute for Conflict Prevention
and Resolution Rules for Non-Administered Arbitration (the “Rules”)
then
in force, to the extent such Rules are not inconsistent with the provisions
of
this Agreement.
16
(c) Selection
of Arbitrators.
The
arbitral panel shall be composed of three arbitrators (the “Tribunal”).
With
the request for arbitration, the Party requesting arbitration (the “Claimant”)
shall
appoint one arbitrator. The Party named as respondent by the Claimant (the
“Respondent”) shall appoint one arbitrator within the time specified in the
Rules. The two arbitrators nominated by the Claimant and Respondent shall
together nominate the third arbitrator, who shall be the chairman of the
Tribunal, by mutual agreement within 20 Days of the second appointment of an
arbitrator. If within the time specified a Party fails to nominate its
party-appointed arbitrator or the two party-appointed arbitrators fail to
nominate the third arbitrator, either party may request the CPR to make the
appointment according to the Rules. If any nominated arbitrator is not
appointed, declines, resigns, becomes incapacitated, or otherwise refuses or
fails to serve or to continue to serve as an arbitrator, the Party or
arbitrators entitled to appoint that arbitrator shall promptly nominate a
successor. If the arbitrators are unable to agree on a replacement third
arbitrator, then the CPR shall make the appointment according to the
Rules.
In the
event that an arbitrator is objected to, the two remaining arbitrators shall
decide whether the objection is valid and whether the challenged arbitrator
shall be removed. The arbitrators shall be independent of the Parties and not
have a financial interest in either of the Parties or their Affiliates or in
the
dispute, and shall be unaffiliated and without prior financial alliances with
any Party, or either of the other arbitrators. The arbitrators shall be governed
by the AAA/ABA Code of Ethics for Arbitrators in Commercial Disputes. The
chairman shall be a former judge with experience in matters involving the oil
and gas industry in the United States and with suitable experience of complex
commercial disputes.
(d) Seat,
Discovery, Hearing.
The
seat of the arbitration shall be Salt Lake City, Utah. The evidentiary hearing
shall be transcribed by a certified court reporter. The Tribunal shall determine
the appropriate procedural rules, including the admissibility of evidence,
subject to any procedures specified in this Agreement or the Rules. Within
twenty (20) Days after the arbitration is commenced, the Parties shall confer
and attempt to agree on the disclosure of specific documents or narrowly-defined
categories of documents that are reasonably expected to be material to the
issues in the Dispute and the identification of persons likely to have knowledge
of facts reasonably expected to be material to the issues in the Dispute. If
the
Parties are unable to agree on a procedure within ten (10) Days, the Tribunal
may make orders to any Party to disclose the documents and/or to identify the
persons described above, which the Parties consent in advance to obey. If a
Party fails or refuses to comply with an order for discovery, the Tribunal
may
take that failure into account when deciding the issues and may infer that
the
evidence not produced would have supported the opposing Party’s claims. Any
applicable legal privileges against disclosure shall be recognized. Within
thirty (30) Days after completion of discovery, each Party shall submit by
overnight delivery to the other Party and the arbitrators a precise Statement
of
Claims (or Counterclaims) and the factual and/or legal support therefore,
including documents and statements of fact and expert witnesses. Within twenty
(20) Days after receiving such statement, the other Party shall submit by
overnight delivery to the first Party and the arbitrators a precise Statement
of
Defense to the Claims (or Counterclaims) asserted against it and the factual
and/or legal support therefore, including documents and statements of fact
and
expert witnesses. The Tribunal shall conduct a hearing no later than ninety
(90)
Days following selection of the third arbitrator, or thirty (30) Days after
all
discovery has been completed, whichever is later.
17
(e) Award.
The
arbitrators shall consider the terms and conditions of this Agreement, and
any
relevant evidence and testimony, and shall render their award (the “Award”)
within
30 Days following conclusion of the hearing. The Tribunal shall have no power
to
award any remedy not authorized by the governing law or barred by this
Agreement, and they may not rely on any law or legal principle to avoid such
limitations on remedies. The Award shall be in writing, shall give reasons
for
the decisions reached by the Tribunal and shall be signed and dated by the
arbitrators, and a copy of the award shall be delivered to each of the Parties.
The award may be made unanimously or by a majority of arbitrators. The award
shall be final and binding on the parties and may be confirmed in, and judgment
upon the award entered by, any court having jurisdiction over the Parties.
The
Tribunal’s award shall be entitled to all of the protections and benefits of a
final judgment as to any Dispute, including compulsory counterclaims, that
were
or could have been presented to the Tribunal, and shall be final and binding
on
the Parties and non-appealable to the maximum extent permitted by law. The
Award
shall provide for interest on the Award at a per annum rate which shall be
two
percentage points above the U.S. prime rate as published in the Wall Street
Journal (or such other publications as the arbitrators select) in effect on
the
date of the Award, commencing on the 31st Day following delivery of the Award
to
the Parties and continuing until the Award and any accrued interest is paid
in
full.
(f) Exclusive
Method of Resolving Claims; Assistance of Courts.
If a
Party refuses to honor its obligations under this agreement to arbitrate, the
other Party may obtain appropriate relief staying such litigation and/or
compelling arbitration in any court having jurisdiction over the refusing Party;
each Party hereby consenting to the non-exclusive personal jurisdiction and
venue in the federal and State courts in Salt Lake City, Utah for the purpose
of
enforcing this Agreement. Notwithstanding Section
13.7(a),
a Party
may seek interim or injunctive relief from the courts to aid arbitration or
preserve the status quo ante between the Parties pending the completion of
the
arbitration. After a Tribunal has been formed, it shall also have the power
to
issue interim remedies, provisional measures or partial awards as it deems
appropriate. Each Party agrees that arbitration pursuant to this Section
13.7
shall be
the exclusive method for resolving all Disputes and that it will not commence
an
action or proceeding, except as provided in this Section
13.7.
(h) Costs.
The
Tribunal shall have the authority to assess the costs and expenses of the
arbitration proceeding (including the arbitrators’ fees and expenses) against
either or both parties. Each Party shall bear its own attorneys’ fees and other
legal costs; provided, however, that any costs incurred by a Party in seeking
judicial enforcement of any Award shall be chargeable to and borne exclusively
by the Party against whom such court order is obtained.
13.8 Governing
Law.
This
Agreement shall be governed by and construed in accordance with the laws of
the
State of Utah, U.S.A., without regard to any choice of law principles that
would
direct the application of the law of another jurisdiction.
13.9 Assignment;
Delegation.
The rights and obligations of any Party under this Agreement may not be assigned
or delegated without the prior written consent of the other Party, and any
assignment or delegation not in compliance with the foregoing shall be null
and
void, provided that, (i) either Party may assign or delegate its rights or
obligations hereunder to any of its Affiliates without the other Party’s
consent, provided that no such assignment or delegation
18
shall
relieve the assigning or delegating Party from any obligation hereunder, (ii)
Supplier
may assign or delegate its rights or obligations hereunder without Refiner’s
consent in connection with the sale of all or substantially all of its Uinta
Basin, Utah producing properties that produce Crude Oil
and
(iii) Refiner may assign or delegate its rights or obligations hereunder without
Supplier’s consent in connection with the sale of the Refinery; provided that,
with respect to the exceptions set forth in subclauses (ii) and (iii) above
the
assignee or delegate must acknowledge its obligations hereunder to the
nonassigning Party pursuant to an instrument reasonably satisfactory to the
nonassigning Party and upon assignment the assignor shall be relieved of its
obligations hereunder to be performed with respect to periods after the
assignment. All covenants, terms and conditions and provisions of this Agreement
shall be binding upon the Parties and shall extend to and be binding upon the
successors and permitted assignees and delegates of the Parties.
13.10 Time
and Performance of Essence.
Time
and full performance hereunder by the Parties are of the essence in this
Agreement.
13.11 Nonwaiver;
No Third-Party Beneficiaries.
No waiver by any Party of any of its rights with respect to the other Party
or
with respect to any matter or default arising in connection with this Agreement
shall be construed as a waiver of any subsequent right, matter or default
whether of a like kind or different nature. Any waiver shall be in writing
signed by the waiving Party. No Party shall be deemed to have waived, released
or modified any of its rights under this Agreement unless such Party has
expressly stated, in writing, that it does waive, release or modify such right.
A waiver shall not be a continuing waiver unless it expressly states otherwise.
This Agreement is made and entered into for the sole protection and legal
benefit of the Parties, and their permitted successors and assigns, and no
other
Person, other than any Persons who have explicit indemnity rights herein, shall
be a direct or indirect legal beneficiary of, or have any direct or indirect
cause of action or claim in connection with, this Agreement; provided that,
the
Parties reserve solely to themselves the power to amend or terminate this
Agreement without the consent of any other Person.
13.12 Counterparts;
Severability; Survival.
This
Agreement may be executed in several counterparts, each of which is an original
and all of which constitute one and the same instrument. Each Party agrees
to
accept the facsimile signature of the other Party and to be bound by its own
facsimile signature. Except as may otherwise be stated herein, any provision
hereof that is declared or rendered unenforceable, unlawful or invalid by any
Governmental Authority, or deemed unenforceable, unlawful or invalid because
of
a change in Applicable Law, will not otherwise affect the enforceable, lawful
or
valid obligations that arise under this Agreement. If any provision of this
Agreement is declared unenforceable, unlawful or invalid, the Parties will
promptly renegotiate to restore this Agreement as near as possible to its
original intent and effect. All representations, warranties, covenants,
agreements and obligations made or agreed to herein shall survive the
termination of this Agreement until the expiration of the applicable statute
of
limitations, if any.
13.13 Expenses.
Except
as specifically provided herein, each Party will bear its own costs and expenses
incurred in connection with or arising out of the execution, delivery or
performance of this Agreement.
19
13.14 Further
Assurances.
Each of the Parties agrees to take such further actions (including the execution
and delivery of such further documents and instruments) as the other Party
may
reasonably request after the Effective Date to fulfill the purposes of this
Agreement.
13.15 Entire
Agreement; Amendment; Drafting.
This
Agreement, including any Schedules and Exhibits hereto constitute the entire
agreement among the Parties relating to the subject matter contemplated by
this
Agreement and supersede any prior or contemporaneous agreements or
representations affecting the same subject matter. No amendment, modification
or
change to this Agreement shall be enforceable unless reduced to a writing
executed by both Parties. The Parties acknowledge that each Party and its
counsel have participated in the drafting of this Agreement and have reviewed
and revised this Agreement, and that the rule of construction that any
ambiguities are to be resolved against the drafting Party shall not be used
in
the interpretation of this Agreement.
20
IN
WITNESS WHEREOF,
the
Parties hereto have executed this Agreement in the presence of their respective
representatives duly authorized in this regard on the Day and year first above
written.
|
BERRY
PETROLEUM COMPANY
|
HOLLY
REFINING & MARKETING COMPANY - WOODS CROSS
|
|
Per:
\s\ Ralph J.
Goehring
|
Per:
\s\David L. Lamp
|
|
Name: Ralph
J. Goehring
|
Name: David
L. Lamp
|
|
Title: Executive
Vice President and Chief Financial
Officer
|
Title:
President
|
21
SCHEDULE
1.1
DEFINITIONS
In
the
Agreement to which this Schedule is attached and in all Schedules thereto,
the
following words have the meanings given to such words below:
“Affiliate”
means
any Person which, directly or indirectly, controls, is controlled by or is
under
common control with the applicable Party. For purposes of this definition,
control of a Person means the power, direct or indirect, to direct or cause
the
direction of the management and policies of such Person, whether through
ownership of voting securities, by contract or otherwise.
“Agreement”
means
this Crude Oil Supply Agreement, including the Schedules hereto, and any future
amendments or supplements.
“Applicable
Laws”
means
all applicable statutes, regulations, rules, ordinances, codes, licenses,
permits, orders and approvals of each Governmental Authority having jurisdiction
over the Parties or crude oil sold and delivered hereunder, including, without
limitation, Environmental Laws, all health, building, fire, safety and other
codes, ordinances and requirements, in each case, as amended, and any judicial
or administrative interpretation thereof, including any applicable judicial
order, consent, decree, sanction or judgment.
“Applicable
Time”
means
the Official U.S. time for the Central Time Zone as calculated by the National
Institute of Standards and Technology and the U.S. Naval Observatory
(http://www.time.gov).
“Award”
is
defined in Section
13.7(f).
“Barrel”
means,
with respect to crude oil, a unit volume equivalent to (a) 42 United States
standard gallons of oil, (b) 158.9118 liters or (c) 0.1590 cubic meters measured
at 60 degrees Fahrenheit or 15.56 degrees Celsius.
“Base
Annual Volume”
means
the Base Daily Volume multiplied by the number of Days in a Contract Year or
the
applicable 12 month period; provided that any change in the Base Daily Volume
during such period shall only apply to the Days affected by such
change.
“Business
Day”
means
a
Day, other than a Saturday, a Sunday or any other Day on which banking
institutions in New York, New York are required or authorized to be
closed.
“Claim”
means
any claim, demand, suit, action, cause of action, assessment, loss, cost,
expense, Liability, judgment, fine, penalty, interest, payment, damage,
including costs or expenses of any and all investigations or proceedings and
reasonable fees and expenses of attorneys, accountants and other
experts.
“Contract
Year”
means
each 12-month period during the Term commencing with the Effective Date;
provided that the final Contract Year may be less than 12-month if the Term
expires prior to the expiration of the final 12-month period during the
Term.
Schedule
1.1 - Page 1
“CPR”
means
The International Institute for Conflict Prevention &
Resolution.
“Crude
Oil”
is
defined in Section
3.1(a).
“Day”
means
a
calendar day, extending from 12:00 A.M. (Midnight) Applicable Time until 11:59
P.M. Applicable Time, and “Daily” shall have a correlative meaning.
“Defaulting
Party”
is
defined in Section
9.1.
“Delivery
Point”
is
defined in Section
2.3.
“Dispute”
is
defined in Section
13.7(a).
“Dollars”
means
United States dollars unless expressly provided otherwise.
“Effective
Date”
is
defined in the preamble.
“Environmental
Laws”
means
any one or more of the following statutes, any amendments thereto and any
regulations promulgated thereunder, any similar or equivalent state laws, and
any other applicable federal, state and local laws concerning pollution,
protection of the environment or the use, storage, handling, treatment,
management, discharge or disposal of Hazardous Materials, now existing,
including, but not limited to, the: Comprehensive Environmental Response
Compensation and Liability Act of 1980 (“CERCLA”), as amended by the Superfund
Amendments and Reauthorization Act of 1986, 42 U.S.C. 9601 et seq.; Solid Waste
Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976
(“RCRA”), 42 U.S.C. 6901 et seq.; Federal Water Pollution Control Act, 33 U.S.C.
1251 et seq.; Toxic Substances Control Act, 15 U.S.C. 2601 et seq.; Clean Air
Act, 42 U.S.C. 7501 et seq.; and any similar state analogs, in each case, as
amended, and any judicial or administrative interpretation thereof, including
any applicable judicial order, consent, decree, sanction or judgment.
Environmental Laws do not include laws relating to industrial hygiene or worker
safety.
“Event
of Default”
is
defined in Section
9.1.
“Force
Majeure”
means
an event that (a) is not within the reasonable control of the Party (or in
the
case of third party obligations or facilities, the third party) claiming Force
Majeure (the “Claiming
Party”),
(b)
by the exercise of due diligence, the Claiming Party (or third party) is unable
to overcome or avoid or cause to be avoided and (c) prevents the Claiming Party
from performing its obligations hereunder. Force Majeure may include, but is
not
limited to, the following events to the extent the same meet the standards
set
forth in clauses (a), (b) and (c) above: acts of God; act of public enemy;
war;
terrorism; lightning; fire; civil disturbance; labor dispute; sabotage; action
or restraint by court order or Governmental Authority (so long as the Claiming
Party has not applied for or assisted in the application for, and has opposed,
to the extent reasonable, such government action); environmental catastrophe;
inability to obtain permits or utility services or similar events or
occurrences, provided that such permits or services were promptly applied for;
or mechanical failures, breakdowns of or damage to the Refinery [or to more
than
50% of Supplier’s producing facilities in the Uinta Basin, Utah. For the
avoidance of doubt, Force Majeure shall not include the availability of a more
attractive market or source..
Schedule
1.1 - Page 2
“Governmental
Authority”
means
the United States federal government or any other national government or any
provincial, tribal, state, local, departmental or other political subdivision
of
any of the foregoing, or any entity, body or authority exercising executive,
legislative, judicial, regulatory, administrative or other governmental
functions or any court, department, commission, board, bureau, agency,
instrumentality or administrative body of any of the foregoing.
“Hazardous
Materials”
means
(a) any substance included within the definitions of “hazardous substances,”
“hazardous materials,” “toxic substances,” “pollutant,” “contaminant”,
“hazardous waste” or “solid waste” in any Environmental Law; (b) petroleum,
including crude oil or any fraction thereof, (c) polychlorinated biphenyls;
(d)
asbestos and asbestos containing materials (whether friable or nonfriable);
(e)
lead and lead based paint or other lead containing materials (whether friable
or
nonfriable); and (f) naturally occurring radioactive materials.
“Historical
Period Average Prices” means
average quoted prices for relevant crude oil for the previous 12 consecutive
Month periods next preceding the Month in which notice is given:
(a) if
data
for all the quoted items is available for more than 12 Months, but less than
24
Months then the most recent 12 Months shall be used to compute such average
prices;
(b) if
data
for all the quoted items is available for more than 24 Months, but less than
36
Months, then the most recent 24 Months shall be used to compute such average
prices;
(c) if
data
for all the quoted items is available for more than 36 Months, but less than
48
Months, then the most recent 36 Months shall be used to compute such average
prices; and
(d) if
data
for all the quoted items is available for more than 48 Months, but less than
60
Months, then the most recent 48 Months shall be used to compute such average
prices; and
(e) if
data
for all the quoted items is available for more than 60 Months, then the most
recent 60 Months shall be used to compute such average prices.
“Liability”
means
any liability, obligation, debt or commitment of any kind (whether known or
unknown, whether asserted or unasserted, whether absolute or contingent, whether
accrued or unaccrued, whether liquidated or unliquidated, and whether due or
to
become due), including any liability for taxes.
“LP”
means
the linear programming model as utilized by Refiner.
“Minimum
Quality Specifications”
is
defined in Section
3.1(b).
Schedule
1.1 - Page 3
“Month”
means
a
calendar month, extending from 12:00 A.M. Applicable Time on the first Day
of
such calendar month until 11:59 P.M. Applicable Time on the last Day of such
calendar month.
“Non-Defaulting
Party”
is
defined in Section
9.2.
“NYMEX”
means
the New York Mercantile Exchange.
“Party”
and
“Parties”
are
defined in the preamble.
“Person”
or
“Persons”
means
any individual, corporation, partnership, limited liability company, trust,
unincorporated organization, Governmental Authority or any other form of
entity.
“Price
Formula”
is
defined in Section
4.1.
“Prudent
Industry Practices”
means
those practices, methods, standards of safety and acts, which are as a minimum
in accordance with standards generally observed and applicable to the crude
pipeline and refining industry in the United States which a reasonable and
prudent Person would follow in connection with refining facilities similar
to
the Refinery to accomplish the desired result lawfully, reliably and
safely.
“Purchase
Price”
means
the price determined using the Price Formula.
“Refiner”
is
defined in the preamble.
“Refiner
Indemnified Party”
means
Refiner, its Affiliates and their respective officers, directors, employees
and
agents.
“Refinery”
is
defined in the Recitals.
“Refinery
Modifications”
means
the design, engineering, construction, startup and operation of modifications
to
the Refinery such that the Refinery is capable of processing not less than
5000
Barrels per Day of Crude Oil.
“Refinery
Modification Completion”
means
that the Refinery Modifications have been successfully completed and are
operational, in the sole judgment of Refiner.
“Supplier”
is
defined in the preamble.
“Supplier
Indemnified Party”
means
Supplier, its Affiliates and their respective officers, directors, employees
and
agents.
“Term”
is
defined in Section
5.1.
“WTI,
Cushing”
means
the New York Mercantile Exchange (NYMEX) calendar month average light sweet
crude oil front month contract price for the month of delivery.
Schedule
1.1 - Page 4
SCHEDULE
2.1
QUALITY
RANGES OF CRUDE OIL
|
Property
|
Test
Methodology
|
Units
|
Typical
Range
|
MIN/MAX
|
|
API
Density
|
ASTM-D4052
|
°
API
|
35
|
30/40
|
|
Sulfur
|
ASTM-D4294
|
wt
%
|
0.1
|
0/0.1
|
|
Distillation
|
ASTM-D1160
|
See
Below
|
||
|
Water
Content
|
Vol.
%
|
1.5
|
0/2.0
|
|
TBP
by
Simulated Distillation
Percent
off
Temp F
5
313
|
10
|
392
|
|
20
|
515
|
|
30
|
616
|
|
40
|
702
|
|
50
|
776
|
|
60
|
843
|
|
70
|
930
|
|
80
|
964
|
|
90
|
1034
|
Schedule 2.3 -
Page 1
SCHEDULE
2.3
DELIVERY
POINT
Berry
to
supply locations of lease tankage where its Uinta Basin, Utah production will
be
delivered to Refiner from time to time.
Schedule 2.3
- Page 1
SCHEDULE
3.2
QUALITY
TESTING PROCEDURES
Schedule 3.2
- Page 1
SCHEDULE
3.3
MEASUREMENT
PROCEDURES
All
measurements shall be made from static tank gauges on a 100 percent tank table
basis or by positive displacement meters or by approved custody transfer meter.
All measurements and tests shall be made in accordance with the latest
applicable API, ASTM or ASME-API (Petroleum PD Meter Code) published methods.
Volume and gravity shall be adjusted to 15.56ºC (60ºF) by the use of Tables 6A
and 5A of the Petroleum Measurement Tables ASTM Designation D1250 in their
latest revision.
Schedule 3.3
- Page 1
SCHEDULE
7.8
CONTINUING
GUARANTY
WHEREAS,
Holly Refining & Marketing Company - Wood Cross (hereinafter referred to as
"CUSTOMER") has requested Berry Petroleum Company, and any of its Subsidiaries,
Affiliates or Divisions (hereinafter collectively referred to as "BERRY"),
to
supply and/or exchange or to continue to supply and/or exchange crude oil and
petroleum products and any related charges and services (hereinafter referred
to
as "PRODUCT") to CUSTOMER; and
WHEREAS,
Berry has requested this Guaranty from HOLLY CORPORATION (here-in-after referred
to as "GUARANTOR"), parent company of CUSTOMER:
NOW,
THEREFORE, in order to induce BERRY to continue to extend credit to CUSTOMER
and
in consideration of BERRY’s entering into that certain Crude Oil Supply
Agreement dated February 27, 2007 (“CONTRACT”) with CUSTOMER and of the first
PRODUCT delivered by Berry to CUSTOMER on credit after the execution of the
CONTRACT which GUARANTOR acknowledges is sufficient consideration for the
issuance of this Guaranty by GUARANTOR, GUARANTOR hereby guarantees to BERRY
the
full and prompt payment to BERRY of all Indebtedness which CUSTOMER hereafter
incurs for PRODUCT which BERRY sells and/or exchanges to CUSTOMER or otherwise
for CUSTOMER’s performance of the CONTRACT (“Indebtedness”) so long as the
CONTRACT is in full force and effect and until CUSTOMER has fully performed
the
CONTRACT.
Notwithstanding
any other provision of this GUARANTY, (a) GUARANTOR’S liability under this
GUARANTY shall not exceed the aggregate amount of $25,000,000 and (b)
GUARANTOR’S liability under this GUARANTY shall terminate automatically on July
1, 2013, but such termination shall not relieve GUARANTOR from liability for
any
Indebtedness covered by this GUARANTY and incurred by CUSTOMER prior to July
1,
2013.
In
the
event of nonpayment by CUSTOMER of any indebtedness covered by this Guaranty,
BERRY may enforce its rights or remedies against either CUSTOMER or GUARANTOR
in
such manner as it may in its sole discretion determine, and may proceed upon
the
GUARANTY herein contained without first proceeding either against CUSTOMER
or to
enforce any lien rights and further may exercise its rights and remedies
simultaneously against both CUSTOMER and GUARANTOR. GUARANTOR specifically
acknowledges that the obligations under this GUARANTY shall remain in full
force
and effect notwithstanding any bankruptcy or reorganization case or proceeding
concerning CUSTOMER.
This
GUARANTY shall be governed by and construed in accordance with the laws of
the
State of Utah and, to the extent controlling, laws of the United States of
America.
GUARANTOR
authorizes BERRY, either before or after revocation hereof, without notice
to or
demand on GUARANTOR and without affecting GUARANTOR’s liability hereunder, from
time to time to: (a) alter, compromise, renew, extend, accelerate or otherwise
change the time for payment of, or otherwise change the terms of the CONTRACT
or
any part thereof, including increase or decrease of the rate of interest
thereon; and (b) apply payments received by BERRY from CUSTOMER to any
Indebtedness of CUSTOMER to BERRY, in such order as BERRY
Schedule 7.8
- Page 1
shall
determine in its sole discretion, whether or not any such Indebtedness is
covered by this GUARANTY, and GUARANTOR hereby waives any provision of law
regarding application of payments which specifies otherwise. BERRY may with
notice assign this GUARANTY in whole or in part.
GUARANTOR
has established adequate means of obtaining from CUSTOMER on a continuing basis
financial and other information pertaining to CUSTOMER’s financial condition.
GUARANTOR agrees to keep adequately informed from such means of any facts,
events or circumstances that might in any way affect GUARANTOR’s risks
hereunder, and GUARANTOR further agrees that BERRY shall have no obligation
to
disclose to GUARANTOR any information or material about CUSTOMER that is
acquired by BERRY in any manner.
All
reasonable and actually incurred payments, advances, charges, costs and
expenses, including reasonable attorney fees, made or incurred by BERRY in
the
enforcement of this GUARANTY or in the collection of any of the Indebtedness
of
CUSTOMER to BERRY shall be paid by GUARANTOR promptly upon demand, and, if
not
paid within 10 days of receiving notice, together with interest at a rate per
annum equal to the interest rate being charged by BERRY’s primary lender to
BERRY under outstanding credit facilities.
This
GUARANTY represents the final agreement between GUARANTOR and BERRY may not
be
contradicted by evidence of prior, contemporaneous or subsequent oral agreements
of the parties. There are no unwritten oral agreements between GUARANTOR and
BERRY.
HOLLY
CORPORATION
Date:_____________________
By:
Schedule 7.8
- Page 2
SCHEDULE
11.1A
CONTINUING
GUARANTY (FOR EXTENSION PERIOD)
WHEREAS,
Holly Refining & Marketing Company - Wood Cross (hereinafter referred to as
"CUSTOMER") has requested Berry Petroleum Company, and any of its Subsidiaries,
Affiliates or Divisions (hereinafter collectively referred to as "BERRY"),
to
supply and/or exchange or to continue to supply and/or exchange crude oil and
petroleum products and any related charges and services (hereinafter referred
to
as "PRODUCT") to CUSTOMER; and
WHEREAS,
Berry has requested this Guaranty from HOLLY CORPORATION (here-in-after referred
to as "GUARANTOR"), parent company of CUSTOMER:
NOW,
THEREFORE, in order to induce BERRY to continue to extend credit to CUSTOMER
and
in consideration of BERRY’s entering into an extension of the Term under that
certain Crude Oil Supply Agreement dated February 27, 2007 (“CONTRACT”) with
CUSTOMER and of the first PRODUCT delivered by Berry to CUSTOMER on credit
after
the extension of the Term of the CONTRACT which GUARANTOR acknowledges is
sufficient consideration for the issuance of this Guaranty by GUARANTOR,
GUARANTOR hereby guarantees to BERRY the full and prompt payment to BERRY of
all
Indebtedness which CUSTOMER hereafter incurs for PRODUCT which BERRY sells
and/or exchanges to CUSTOMER or otherwise for CUSTOMER’s performance of the
CONTRACT during the extension of the Term (“Indebtedness”) so long as the
CONTRACT is in full force and effect and until CUSTOMER has fully performed
the
CONTRACT.
Notwithstanding
any other provision of this GUARANTY, (a) GUARANTOR’S liability under this
GUARANTY shall not exceed the aggregate amount of $25,000,000 and (b)
GUARANTOR’S liability under this GUARANTY shall terminate automatically on
[insert expiration date of term extension], but such termination shall not
relieve GUARANTOR from liability for any Indebtedness covered by this GUARANTY
and incurred by CUSTOMER prior to [repeat date].
In
the
event of nonpayment by CUSTOMER of any indebtedness covered by this Guaranty,
BERRY may enforce its rights or remedies against either CUSTOMER or GUARANTOR
in
such manner as it may in its sole discretion determine, and may proceed upon
the
GUARANTY herein contained without first proceeding either against CUSTOMER
or to
enforce any lien rights and further may exercise its rights and remedies
simultaneously against both CUSTOMER and GUARANTOR. GUARANTOR specifically
acknowledges that the obligations under this GUARANTY shall remain in full
force
and effect notwithstanding any bankruptcy or reorganization case or proceeding
concerning CUSTOMER.
This
GUARANTY shall be governed by and construed in accordance with the laws of
the
State of Utah and, to the extent controlling, laws of the United States of
America.
Schedule 11.1A
- Page 1
GUARANTOR
authorizes BERRY, either before or after revocation hereof, without notice
to or
demand on GUARANTOR and without affecting GUARANTOR’s liability hereunder, from
time to time to alter, compromise, renew, extend, accelerate or otherwise change
the time for payment of, or otherwise change the terms of the CONTRACT or any
part thereof, including increase or decrease of the rate of interest thereon.
BERRY may with notice assign this GUARANTY in whole or in part only connection
with an assignment permitted pursuant to the CONTRACT.
GUARANTOR
has established adequate means of obtaining from CUSTOMER on a continuing basis
financial and other information pertaining to CUSTOMER’s financial condition.
GUARANTOR agrees to keep adequately informed from such means of any facts,
events or circumstances that might in any way affect GUARANTOR’s risks
hereunder, and GUARANTOR further agrees that BERRY shall have no obligation
to
disclose to GUARANTOR any information or material about CUSTOMER that is
acquired by BERRY in any manner.
All
reasonable and actually incurred payments, advances, charges, costs and
expenses, including reasonable attorney fees, made or incurred by BERRY in
the
enforcement of this GUARANTY or in the collection of any of the Indebtedness
of
CUSTOMER to BERRY shall be paid by GUARANTOR promptly upon demand, and, if
not
paid within 10 days of receiving notice, together with interest at a rate per
annum equal to the interest rate being charged by BERRY’s primary lender to
BERRY under outstanding credit facilities.
This
GUARANTY represents the final agreement between GUARANTOR and BERRY may not
be
contradicted by evidence of prior, contemporaneous or subsequent oral agreements
of the parties. There are no unwritten oral agreements between GUARANTOR and
BERRY.
HOLLY
CORPORATION
Date:_____________________ By:
Schedule 11.1A
- Page 2
Exhibit
23.1
CONSENT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We
hereby
consent to the incorporation by reference in the Registration Statements
on Form
S-3
(No.
333-135055) and Form S-8 (Nos. 333-62799, 333-62871, 333-98379 and
333-127018) of Berry Petroleum Company of our report dated February 28,
2007 relating to the financial statements, management’s assessment of the
effectiveness of internal control over financial reporting, and the
effectiveness of internal control over financial reporting which appears
in this
Form 10-K.
/s/
PricewaterhouseCoopers LLP
Los
Angeles, California
February
28, 2007
1
Exhibit
23.2
DeGolyer
and MacNaughton
5001
Spring Valley Road
Suite
800
East
Dallas,
Texas 75244
February
28, 2007
Berry
Petroleum Company
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309-0640
Gentlemen:
In connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2006, (the Annual Report) of Berry Petroleum Company (the Company), we hereby consent to (i) the use of and reference to our “Appraisal Report as of December 31, 2006 on Certain Properties owned by Berry Petroleum Company,” “Appraisal Report as of December 31, 2005 on Certain Properties owned by Berry Petroleum Company,” and “Appraisal Report as of December 31, 2004 on Certain Properties owned by Berry Petroleum Company,” (the “Reports”), under the captions “Business” and “Oil and Gas Properties” in Item 1 of the Annual Report, under the caption “Selected Financial Data” in Item 6 of the Annual Report, and under the caption “Supplemental Information About Oil & Gas Producing Activities (Unaudited)” in Item 8 of the Annual Report; and (ii) the use of and reference to the name DeGolyer and MacNaughton as the independent petroleum engineering firm that prepared the Reports under such items; provided, however, that since the cash-flow calculations in the Annual Report include estimated income taxes not included in the Reports, we are unable to verify the accuracy of the cash-flow values in the Annual Report.
Very
truly yours,
/s/
DeGOLYER and MacNAUGHTON
1
Exhibit 31.1
Certification
of Chief Executive Officer
Pursuant
to Section 302 of Sarbanes Oxley Act of 2002
I,
Robert
F. Heinemann, President, Chief Executive Officer, and Director certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Berry Petroleum Company
(the
Company);
|
||
|
|
||||
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such
statements
were made, not misleading with respect to the period covered by
this
report;
|
||
|
|
||||
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial
information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
Company
as of, and for, the periods presented in this annual
report;
|
||
|
|
||||
|
|
4.
|
The
Company’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined
in Exchange
Act Rules 13a - 15(e) and 15d - (e) and internal control over
financial reporting (as defined in Exchange Act Rules 13a - 15(f)
and 15d
- 15(f)) for the Company and have:
|
||
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the Company is made known
to us by
others within those entities, particularly during the period in
which this
annual report is being prepared;
|
||
|
|
||||
|
|
b)
|
designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designated under our supervision,
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;
|
||
|
|
c)
|
evaluated
the effectiveness of the Company’s disclosure controls and procedures and
presented in this report our conclusions abut the effectiveness
of the
disclosure controls and procedures as of the end of the period
covered by
this report based on such evaluation; and
|
||
|
|
||||
|
|
d)
|
disclosed
in this report any change in the Company’s internal control over financial
reporting that occurred during the Company’s most recent fiscal quarter
that has materially affected or is reasonably likely to materially
affect
the Company’s internal control over financial reporting.
|
||
|
|
5.
|
The
Company’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting,
to the
Company’s auditors and the audit committee of the Company’s board of
directors:
|
|
|
a)
|
all
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the Company’s ability to record,
process, summarize and report financial information and have identified
for the registrant’s auditors any material weaknesses in internal
controls; and
|
||
|
|
||||
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the Company’s internal controls
over financial reporting.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Robert F. Heinemann
|
|
||
|
|
Robert
F. Heinemann
|
|
||
|
February
28, 2007
|
President,
Chief Executive Officer, and Director
|
|
||
1
Exhibit 31.2
Certification
of Chief Financial Officer
Pursuant
to Section 302 of Sarbanes Oxley Act of 2002
I,
Ralph
J. Goehring, Executive Vice President and Chief Financial Officer, certify
that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Berry Petroleum Company
(the
Company);
|
||
|
|
||||
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make
the
statements made, in light of the circumstances under which such
statements
were made, not misleading with respect to the period covered by
this
report;
|
||
|
|
||||
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial
information
included in this report, fairly present in all material respects
the
financial condition, results of operations and cash flows of the
Company
as of, and for, the periods presented in this annual
report;
|
||
|
|
||||
|
|
4.
|
The
Company’s other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined
in Exchange
Act Rules 13a - 15(e) and 15d - (e) and internal control over
financial reporting (as defined in Exchange Act Rules 13a - 15(f)
and 15d
- 15(f)) for the Company and have:
|
||
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the Company is made known
to us by
others within those entities, particularly during the period in
which this
annual report is being prepared;
|
||
|
|
||||
|
|
b)
|
designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designated under our supervision,
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;
|
||
|
|
c)
|
evaluated
the effectiveness of the Company’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the
disclosure controls and procedures as of the end of the period
covered by
this report based on such evaluation; and
|
||
|
|
||||
|
|
d)
|
disclosed
in this report any change in the Company’s internal control over financial
reporting that occurred during the Company’s most recent fiscal quarter
that has materially affected or is reasonably likely to materially
affect
the Company’s internal control over financial reporting;
|
||
|
|
5.
|
The
Company’s other certifying officer and I have disclosed, based on our most
recent evaluation of internal control over financial reporting
to the
Company’s auditors and the audit committee of the Company’s board of
directors:
|
|
|
a)
|
all
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the Company’s ability to record,
process, summarize and report financial information;
and
|
||
|
|
||||
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the Company’s internal controls
over financial reporting.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Ralph J. Goehring
|
|
||
|
|
Ralph
J. Goehring
|
|
||
|
February
28, 2007
|
Executive
Vice President and Chief Financial Officer
|
|
||
1
Exhibit 32.1
Certification
of Chief Executive Officer
Pursuant
to Section 906 of Sarbanes Oxley Act of 2002
In
connection with the Annual Report of Berry Petroleum Company (the “Company”) on
Form 10-K for the period ending December 31, 2006 as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Robert
F. Heinemann, President, Chief Executive Officer and Director of the Company,
certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the
Sarbanes-Oxley Act of 2002, that:
|
|
1)
|
The
Report fully complies with the requirements of section 13(a) or
15(d) of
the Securities Exchange Act of 1934; and
|
||
|
|
||||
|
|
2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of
the
Company.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Robert F. Heinemann
|
|
||
|
|
Robert
F. Heinemann
|
|
||
|
February
28, 2007
|
President,
Chief Executive Officer and Director
|
|
||
1
Exhibit 32.2
Certification
of Chief Financial Officer
Pursuant
to Section 906 of Sarbanes Oxley Act of 2002
In
connection with the Annual Report of Berry Petroleum Company (the “Company”) on
Form 10-K for the period ending December 31, 2006 as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Ralph
J. Goehring, Executive Vice President and Chief Financial Officer of the
Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of
the
Sarbanes-Oxley Act of 2002, that:
|
|
1)
|
The
Report fully complies with the requirements of section 13(a) or 15(d)
of
the Securities Exchange Act of 1934; and
|
||
|
|
||||
|
|
2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
||
|
|
|
|
|
|
|
|
|
|
||
|
|
/s/
Ralph J. Goehring
|
|
||
|
|
Ralph
J. Goehring
|
|
||
|
February
28, 2007
|
Executive
Vice President and Chief Financial Officer
|
|
||
|
|
||||
1