e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year ended
December 31, 2006
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to .
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Commission File Number: 0-29370
Ultra Petroleum Corp.
(Exact Name of Registrant as
Specified in Its Charter)
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Yukon Territory, Canada
(Jurisdiction of
Incorporation or Organization)
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N/A
(I.R.S. Employer
Identification No.)
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363 North Sam Houston Parkway East, Suite 1200
Houston, Texas 77060
(Address of Principal Executive
Offices) (Zip Code)
281-876-0120
(Registrants Telephone Number, Including Area
Code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Shares, without par value
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American Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act.
YES þ 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 þ
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 requirement for the past
90 days. YES þ NO o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
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. þ
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.
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Act).
YES o NO þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant was
approximately $9,137,410,226 as of June 30, 2006 (based on
the last reported sales price of $59.27 of such stock on the
American Stock Exchange on such date).
As of February 15, 2007, there were 151,920,986 common
shares of the registrant outstanding.
Documents incorporated by reference: The definitive Proxy
Statement for the 2007 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission within
120 days after December 31, 2006, is incorporated by
reference in Part III of this
Form 10-K.
Certain
Definitions
Terms
used to describe quantities of oil and natural gas and
marketing
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Bbl One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
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Bcf One billion cubic feet of natural gas.
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Bcfe One billion cubic feet of natural gas
equivalent.
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BOE One barrel of oil equivalent, converting
natural gas to oil at the ratio of 6 Mcf of natural gas to
1 Bbl of oil.
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BTU British Thermal Unit.
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CFD Caofaedian the Chinese
designation for the area in Bohai Bay area in the vicinity of
the 04/36 and 05/36 Blocks, offshore China.
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Condensate An oil-like liquid produced in
association with natural gas production that condenses from
natural gas as it is produced and delivered into a separator or
similar equipment and collected in tanks at each well prior to
the delivery of such natural gas to the natural gas gathering
pipeline system.
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ICP Indonesian Crude Price.
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MBbl One thousand barrels.
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Mcf One thousand cubic feet of natural gas.
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Mcfe One thousand cubic feet of natural gas
equivalent, converting oil or condensate to natural gas at the
ratio of 1 Bbl of oil or condensate to 6 Mcf of
natural gas.
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MMBbl One million barrels of oil or other
liquid hydrocarbons.
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MMcf One million cubic feet of natural gas.
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MBOE One thousand BOE.
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MMBOE One million BOE.
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MMBTU One million British Thermal Units.
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Terms
used to describe the Companys interests in wells and
acreage
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Gross oil and natural gas wells or acres The
Companys gross wells or gross acres represent the total
number of wells or acres in which the Company owns a working
interest.
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Net oil and natural gas wells or acres
Determined by multiplying gross oil and natural gas
wells or acres by the working interest that the Company owns in
such wells or acres represented by the underlying properties.
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Prospect A location where hydrocarbons such
as oil and gas are believed to be present in quantities which
are economically feasible to produce.
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Terms
used to assign a present value to the Companys
reserves
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Standardized measure of discounted future net cash flows,
after income taxes The present value, discounted
at 10%, of the pre-tax future net cash flows attributable to
estimated net proved reserves. The Company calculates this
amount by assuming that it will sell the oil and natural gas
production attributable to the proved reserves estimated in its
independent engineers reserve report for the oil and
natural gas spot prices on the last day of the year, adjusted
for quality and transportation. The Company also assumes that
the cost to produce the reserves will remain constant at the
costs prevailing on the date of the report. The assumed costs
are subtracted from the assumed revenues resulting in a stream
of future net cash flows. Estimated future income taxes, using
rates in effect on the date of the report, are deducted from the
net
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cash flow stream. The after-tax cash flows are discounted at 10%
to result in the standardized measure of the Companys
proved reserves.
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Standardized measure of discounted future net cash flows
before income taxes The discounted present value
of proved reserves is identical to the standardized measure
described above, except that estimated future income taxes are
not deducted in calculating future net cash flows. The Company
discloses the discounted present value without deducting
estimated income taxes to provide what it believes is a better
basis for comparison of its reserves to the producers who may
have different income tax rates.
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Terms
used to classify the Companys reserve
quantities
The Securities and Exchange Commission (SEC)
definition of proved oil and natural gas reserves, per
Regulation S-X,
is as follows:
Proved oil and natural gas reserves. Proved
oil and natural gas reserves are the 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, i.e., prices and costs as of
the date the estimate is made as defined in
Rule 4-10(a)(2).
Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on
escalations based upon future conditions.
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(a)
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Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes
(1) that portion delineated by drilling and defined by
gas-oil
and/or
oil-water contacts, if any; and (2) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
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(b)
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Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on
which the project or program was based.
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(c)
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Estimates of proved reserves do not include the following:
(1) oil that may become available from known reservoirs but
is classified separately as indicated additional
reserves; (2) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir characteristics,
or economic factors; (3) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and
(4) crude oil, natural gas, and natural gas liquids, that
may be recovered from oil shales, coal, gilsonite and other such
sources.
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Proved developed reserves Proved reserves
that can be expected to be recovered through existing wells with
existing equipment and operating methods as defined in
Rule 4-10(a)(3).
Proved undeveloped reserves Proved reserves
that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is required as defined in Rule 4-10(a)(4).
Terms
used to describe the legal ownership of the Companys oil
and natural gas properties
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Working interest A real property interest
entitling the owner to receive a specified percentage of the
proceeds of the sale of oil and natural gas production or a
percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and
produce such oil and natural gas. A working interest owner who
owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or
disapprove the appointment of an operator and drilling and other
major activities in connection with the development and
operation of a property.
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Production sharing contract A commercial
contract between the investor and the owner, which allows the
investor to undertake large scale, long-term investments. The
purpose of the production sharing contract
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is to define the terms and conditions for the exploration and
development of resources by replacing existing tax and license
regimes with a contract based arrangement that exists for the
life of the project.
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Terms
used to describe seismic operations
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Seismic data Oil and natural gas companies
use seismic data as their principal source of information to
locate oil and natural gas deposits, both to aid in exploration
for new deposits and to manage or enhance production from known
reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are
reflected back to the surface by underground formations, where
they are detected by geophones which digitize and record the
reflected waves. Computers are then used to process the raw data
to develop an image of underground formations.
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2-D
seismic data
2-D seismic
survey data has been the standard acquisition technique used to
image geologic formations over a broad area.
2-D seismic
data is collected by a single line of energy sources which
reflect seismic waves to a single line of geophones. When
processed,
2-D seismic
data produces an image of a single vertical plane of
sub-surface
data.
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3-D
seismic data
3-D seismic
data is collected using a grid of energy sources, which are
generally spread over several miles. A
3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube
of information that can be divided into various planes, thus
improving visualization. Consequently,
3-D seismic
data is generally considered a more reliable indicator of
potential oil and natural gas reservoirs in the area evaluated.
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PART I
Ultra Petroleum Corp. (Ultra or the
Company) is an independent oil and gas company
engaged in the development, production, operation, exploration
and acquisition of oil and natural gas properties. The Company
was originally incorporated on November 14, 1979, under the
laws of the Province of British Columbia, Canada. Ultra remains
a Canadian company, but since March 2000, has operated under the
laws of The Yukon Territory, Canada pursuant to Section 190
of the Business Corporations Act (Yukon Territory). The
Companys operations are primarily in the Green River Basin
of southwest Wyoming and Bohai Bay, offshore China. The Company
continually evaluates other opportunities for the acquisition,
exploration and development of oil and natural gas properties.
Ultras current domestic operations are focused on
developing and expanding a tight gas sand project located in the
Green River Basin in southwest Wyoming. As of December 31,
2006, Ultra owns interests in approximately 147,917 gross
(79,566 net) acres in Wyoming covering approximately
230 square miles. The Company owns working interests in
approximately 464 gross producing wells in this area and is
operator of 50% of the 464 gross wells. In 2006, domestic
production was approximately 89.5% of the Companys total
oil and natural gas production on an Mcfe basis and 99.0% of the
Companys estimated net proved reserves were domestic on an
Mcfe basis. In 2006, domestic capital expenditures comprised
approximately 95.5% of the Companys total capital
expenditures.
Following the acquisition of Pendaries Petroleum
Ltd. (Pendaries) on January 16, 2001, the
Company became active in oil and natural gas exploration and
development covering the 04/36 Block and the 05/36 Block
(jointly the Blocks) in Bohai Bay, China. The
Company owns interests in approximately 687,300 gross
(130,290 net) acres in the Blocks. The exploration phase on
the 04/36 Block has been extended to September 2007 and the
05/36 Block exploration phase has been extended to February
2008. After the extension was granted on the 05/36 Block, one of
the parties to the contract elected not to participate in the
extension and the Company chose to acquire the available
exploration interest. In 2006, the Company spent approximately
4.5% of its total 2006 capital budget on developing these China
fields, as well as on engineering work focused on development of
additional fields and continuing exploration. A wholly-owned
subsidiary of Anadarko Petroleum Corporation, Kerr-McGee China
Petroleum Ltd., is the operator of the Blocks. Through its
Production Sharing Contracts (PSC), the Company owns
an interest in 79 gross (6.89 net) producing wells on
the Blocks. When Ultra acquired Pendaries, there were three oil
discoveries on the Blocks. Since then, six new discoveries have
been made with seven of these fields now developed and on
production. In addition, one discovery is being prepared for
development and another discovery is still under appraisal.
The Company also owns interests in 233,011 gross
(124,591 net) acres in Pennsylvania. The Company drilled
1 gross (1.0 net) test well on this acreage in 2005.
During 2006, this well was brought on production and the Company
commenced drilling operations on 2 gross (1.125 net)
additional exploratory wells in the area. At year end 2006, one
well remained drilling while the second well was suspended.
Ultra continually evaluates this area to determine plans for
future activity in the area.
The Companys annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
and current reports on
Form 8-K,
as well as any amendments to such reports and all other filings
pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 are available free of charge to the public
on the Companys website at www.ultrapetroleum.com. To
access the Companys SEC filings, select
Financials under the Investor Relations tab on the
Companys website. You may also request a copy of these
filings at no cost by making written or telephone requests for
copies to Ultra Petroleum Corp., Manager, Investor Relations,
363 N. Sam Houston Pkwy. E., Suite 1200, Houston, TX 77060,
(281) 876-0120.
Any materials that the Company has filed with the SEC may be
read and/or
copied at the SECs Public Reference Room at 100 F Street,
N.E., Room 1580, Washington, D.C. 20549. You may
obtain information on the operation of the Public Reference Room
by calling the SEC at
1-800-SEC-0330.
The SEC maintains an internet site that contains reports, proxy
and information statements, and other information regarding us.
The SECs website address is www.sec.gov.
6
Business
Strategy
Green
River Basin, Wyoming
In 2007, the Company plans to continue its ongoing program to
identify, develop and explore the acreage position now held in
the tight gas sand trend in the Green River Basin. The Company
expects that the majority of the wells drilled during 2007 will
target the sands of the upper Cretaceous Lance Pool in the
Pinedale and Jonah fields. The Lance Pool, as administered by
the Wyoming Oil and Gas Conservation Commission
(WOGCC), includes sands of both the Lance (found at
subsurface depths of approximately 8,000 to 12,000 feet)
and Mesaverde (found at subsurface depths of approximately
12,000 to 14,000 feet) in the Pinedale and Jonah fields
area of Sublette County, Wyoming. The Company plans to drill
delineation, step-out and exploration wells on its Green River
Basin acreage positions in an ongoing attempt to further define
and expand the current known producing limits of these two field
areas. Work is continuing in an effort to assess the need for
further increased density drilling to more efficiently recover
the vast resources present in the area. Currently, the Pinedale
field is approved by the WOGCC for a mix of well densities
ranging from 1 well per
40-acre
government quarter
(40-acre
equivalent) section down to 16 wells per government quarter
section (10-acre
equivalent). In the Jonah field, the current spacing is
8 wells per
80-acre
drilling and spacing unit
(10-acre
spacing) with several pilots testing spacing at 16 wells
per 80-acre
drilling and spacing unit
(5-acre
spacing). In addition to the ongoing efforts in the Lance Pool
section, the Company is drilling a deep test to further evaluate
the potential for production from the Rock Springs, Blair and
Hilliard Formations which underlie much of the Companys
acreage position in the Pinedale field. All of the
Companys drilling activity is conducted utilizing its
extensive integrated geological and geophysical data set. This
data set is being utilized to map the potentially productive
intervals, to identify areas for future extension of the Lance
fairway and to identify deeper objectives which may warrant
drilling.
Bohai
Bay, China
In 2007, the Company plans to continue producing oil at the CFD
11-1,
11-2,
11-3,
11-5, and
the unitized
11-6,
12-1 and
12-1S fields
and to begin development planning for the CFD 2-1 discovery. The
Company also plans to drill an additional exploration well
during 2007. The Company has nine discovered oil fields in the
Bohai Blocks with seven fields on production, one field being
readied for development and one remaining in the appraisal stage.
Pennsylvania
The Company is currently drilling a second test well in the
Marshlands prospect area and during 2007 plans to drill at least
one more test of the Silurian Tuscarora formation. Ultra plans
to continue to evaluate its acreage holding in the area, acquire
additional acreage, seismic and geologic data in the area as
needed, and develop an overall strategy to assess the potential
of the area and bring that potential to production in a timely
and cost effective manner. The initial discovery well continues
to produce above expectations and the Company continues to
monitor its production to gather additional information to guide
future decisions on development. During 2006, the Company also
participated in 1 gross (.125 net) exploratory well
drilled by others to evaluate a portion of the acreage position.
Drilling operations on this well are suspended and the wellbore
is being evaluated.
Marketing
and Pricing
Ultra derives its revenues principally from the sale of its
natural gas and associated condensate production from wells
operated by the Company and others in the Green River Basin in
southwest Wyoming. To a lesser extent, the Company derives
revenues from the sale of its share of oil production from its
producing fields in the Bohai Bay area, offshore China. The
Company also derives a small portion of its revenues from the
sale of natural gas in Pennsylvania. The Companys revenues
are determined, to a large degree, by prevailing natural gas
prices for production situated in the Rocky Mountain Region of
the United States, specifically, southwest Wyoming, and to a
lesser extent by prevailing prices for crude oil produced in the
Bohai Bay region of China and natural gas in Pennsylvania.
Energy commodity prices in general, and the Companys
regional prices in particular, have been highly volatile in the
past, and such high levels of volatility are expected to
continue in the future. The Company cannot predict or control
the market prices for the sale of its natural gas, condensate,
or oil production.
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The Company, from time to time, in the regular course of its
business, has hedged a portion of its natural gas production
primarily through the use of fixed price, forward sales of
physical gas, or through the limited use of financial swaps with
creditworthy financial counterparties. The Company may elect to
hedge additional portions of its forecast natural gas production
in the future, in much the same manner as it has done
previously. The Company has not, to date, hedged any of its
Chinese oil production; although, it may do so in the future.
For a more detailed description of the Companys hedging
activities, see Item 7A. Quantitative and Qualitative
Disclosures About Market Risk. The Companys hedging policy
limits the amounts of resources hedged to not more than 50% of
its forecast production without Board approval. As a result of
its hedging activities, the Company may realize prices that are
less than the spot prices that it would have received otherwise.
Natural
Gas Marketing
Ultra currently sells all of its natural gas production to a
diverse group of third-party, non-affiliated entities in a
portfolio of transactions of various durations (daily, monthly
and longer term). The Companys customers are predominately
located in the western United States primarily
California and the Pacific Northwest, as well as the Front Range
area of Colorado and in Utah. The sale of the Companys
natural gas is as produced. As such, the Company
does not maintain any significant inventories or imbalances of
natural gas. The Company maintains credit policies intended to
mitigate the risk of uncollectible accounts receivable. The
Company does not have any outstanding, uncollectible accounts
for its natural gas sales.
During 2006, the Company re-negotiated gathering and processing
agreements with one of its midstream service providers that
gathers, compresses and processes natural gas owned or
controlled by the Company from its producing wells in the
Pinedale Anticline field in southwest Wyoming. Under these
agreements, the midstream service provider will expand its
facility capacities in southwest Wyoming to accommodate growing
volumes from wells in which the Company owns an interest. These
agreements or amendments, whichever is applicable to the area,
contain multi-year commitments for midstream services. The
Company lowered some of the gathering and processing fees for
such midstream services, in exchange for committing to these
longer term arrangements. As a result of such negotiations (in
both 2005 and 2006), two new, large cryogenic gas processing
plants are currently being constructed in southwest Wyoming, and
are projected to be completed during 2007. The new facilities
will add incremental cryogenic processing capacity of
approximately 1.1 Bcf per day to the southwest Wyoming
area. The Company has contractually secured capacity at both of
these facilities for the processing of its natural gas. Ultra
believes that the capacity of the midstream infrastructure
related to the Companys production will continue to be
adequate to allow it to sell essentially all of its available
production.
During 2006, the Company realized natural gas prices that were
lower than those seen in the previous year in the southwest
Wyoming region. The market price for natural gas in the Rockies
generally, and in southwest Wyoming specifically, is influenced
by a number of regional and national factors; all of which are
unpredictable and beyond the Companys ability to control
or to predict. These factors include, among others, weather,
natural gas supplies, natural gas demand, and pipeline export
capacity. A warmer than normal summer, plus the impact of two
major hurricanes (Katrina and Rita) on natural gas production
from the Gulf of Mexico, caused natural gas prices in the Rocky
Mountain Region, and other parts of the country, to increase
dramatically during the third and fourth quarters of 2005.
During 2006, by contrast, record warm temperatures were observed
during January and December of 2006 (both critical months for
natural gas demand used for heating) and throughout the entire
year. The U.S. National Climatic Data Center (a division of
the National Oceanic and Atmospheric Administration) recently
announced that 2006 was the warmest year in the United States in
112 years of record keeping. These record warm temperatures
diminished demand for natural gas, and caused larger than normal
inventories of natural gas in storage during 2006. As a result
of the diminished demand due to warmer weather and high levels
of natural gas in storage, natural gas prices declined during
2006, both nationally and in southwest Wyoming.
Because production exceeds local demand for natural gas, the
Rocky Mountain Region is usually a net-exporter of natural gas.
Historically, natural gas production in southwest Wyoming has
sold at a discount relative to other U.S. natural gas
production sources or market areas. These regional pricing
differentials or discounts are typically referred to as
basis or basis differentials. The
Company has seen significant basis differentials for its Wyoming
production, versus the Henry Hub pricing reference point in
south Louisiana in the past. This trend continued in 2006. As a
result, the Company realized prices that were lower than those
received by companies with
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natural gas production in other regions of the
U.S. Increases in pipeline capacity to transport production
from Rocky Mountain production areas to markets in the West in
recent years have served to improve (i.e. lower) basis
differentials for Wyoming natural gas production. (Examples
include: Kern River Pipeline in service May 2003;
the Cheyenne Plains Pipeline in service February
2005; and Rockies Express Pipeline expansion to Cheyenne,
Wyoming placed into service on February 14, 2007). These
expansions of pipeline export capacity have historically reduced
but not eliminated the basis differential for natural gas prices
in southwest Wyoming when compared to prices at the Henry Hub
pricing reference point. There have been, from time to time,
numerous other proposed pipeline projects that have been
announced to transport Rockies and Wyoming natural gas
production to markets.
During 2006, the Company continued to take action toward
assuring that the pipeline infrastructure to move its natural
gas supplies away from southwest Wyoming will be expanded to
provide sufficient capacity to transport its natural gas
production and to provide for reasonable basis differentials for
its natural gas in the future. The Company agreed to become an
anchor shipper on the proposed Rockies Express Pipeline project,
sponsored by subsidiaries of Kinder Morgan, Conoco Phillips, and
Sempra Energy. The Rockies Express Pipeline, if built as
proposed, would be the largest natural gas transmission pipeline
project of its type built in the United States in more than
20 years, beginning at the Opal Processing Plant in
southwest Wyoming and traversing Wyoming and several other
states to an ultimate terminus in eastern Ohio. This pipeline is
projected to cover more than 1,800 miles and is
contemplated to be a large-diameter (42), high-pressure
natural gas pipeline. The Rockies Express Pipeline, if built,
will be an interstate pipeline and would therefore be subject to
the jurisdiction of the United States Federal Energy Regulatory
Commission (FERC).
On December 19, 2005, the Company entered into two
Precedent Agreements (Precedent Agreements) with
Rockies Express Pipeline, LLC (REX) and Entrega Gas
Pipeline, LLC. The Precedent Agreements govern the parties
through the design, regulatory process and construction of the
pipeline facilities and, subject to certain conditions
precedent, the Company will take firm transportation service, if
and when the pipeline facilities are constructed. Commencing
upon completion of the pipeline facilities, the Companys
commitment involves a capacity of 200,000 MMBtu per day of
natural gas for a term of 10 years, and the Company will be
obligated to pay REX certain demand charges related to its
rights to hold this firm transportation capacity as an anchor
shipper. Based on current assumptions, current projections
regarding the cost of the expansion and the participation of
other shippers in the expansion (noting specifically that these
assumptions are likely to change materially), the Company
currently projects that annual demand charges due may be
approximately $70.0 million per year for the term of the
contract, exclusive of fuel and surcharges. The Companys
Board of Directors approved the Precedent Agreements on
February 6, 2006 and Kinder Morgan, as the managing member
of REX, advised the Company of their final approval of the
Precedent Agreements, and their intent to proceed with the
construction of the Rockies Express Pipeline on
February 28, 2006.
The pipeline facilities are currently anticipated to be
completed in stages between 2008 and 2009. REX filed its
application for a Certificate of Public Convenience and
Necessity for the Rockies Express West Project
(REX-West) with the FERC on May 31, 2006. The
REX-West portion of the project is 713 miles of pipeline
commencing at Cheyenne Hub (Weld County, CO) and ending in
Audrain County, Missouri. The FERC issued a Preliminary
Determination on Non-Environmental Issues related to the
REX-West application on September 21, 2006, stating that,
subject to certain conditions, REXs proposals are in the
public interest. This order did not consider or evaluate any
environmental issues, which will be addressed in a subsequent
FERC order, which is expected during 2007. FERC also issued a
Draft Environmental Impact Statement on REX-West, on
November 3, 2006. REX has indicated to the Company that,
upon receipt of the final FERC order on environmental issues,
construction of the REX-West portion of the project will
commence. This is expected to occur early in the second quarter
of 2007. The REX partners have indicated that they will file an
application for a Certificate of Public Convenience and
Necessity for the Rockies Express East segment (Missouri to
Ohio) for the proposed project following receipt of the order
approving the REX-West Certificate of Public Convenience and
Necessity.
Although the Company is optimistic that the Rockies Express
Pipeline project will receive the necessary regulatory approvals
and be constructed in a timely manner, there are no assurances
that the Rockies Express Pipeline will be built, nor are there
any assurances that, if built, the pipeline will eliminate or
reduce the basis differentials historically seen in its Wyoming
production.
9
Oil
Marketing
Through its wholly-owned subsidiary,
Sino-American
Energy Corporation, the Company markets its share of oil
production from the 04/36 and 05/36 Blocks in Bohai Bay, China.
In addition, the first two of its fields in the previously
non-producing 05/36 Block, Bohai Bay, offshore China (CFD
12-1 and
12-1 South),
began producing oil in the third quarter of 2006 along with the
CFD 11-6 on
the 04/36 Block.
The Companys Chinese oil production (CFD
crude) is sold on a tanker/cargo lifting basis. As the
Companys share of inventories on the CFD fields
Floating Production Storage and Offloading Vessel
(FPSO) become sufficient to schedule a lifting
(typically 200,000 300,000 barrels per cargo),
the Company coordinates with the operator and its markets to
lift a cargo. By necessity, the Company will, from time to time,
carry inventories of crude oil to accommodate the lifting
schedules for its share of oil from the FPSO. The Company may
also, from time to time, find itself in an over-lifted position
as well. Each of the partners in the CFD fields are responsible
for the disposition of their respective shares of the CFD crude
production. The operator of these fields manages the lifting
schedule.
The Company has traditionally sold most of its share of the CFD
crude production to an affiliate of its Chinese partner, Chinese
National Offshore Oil Corporation (CNOOC) China,
Ltd., at prices that are derived from the Indonesian Crude Price
(ICP) Duri monthly average price. In 2006, CNOOC
again purchased the majority of the Companys share of the
CFD production. The Company sold some of its remaining share of
the CFD crude production outside of China. The Company continues
to assess its opportunities to market its share of the CFD crude
production to other markets such as Taiwan, Korea, Japan,
Malaysia, the United States and Singapore. The Company does not
have any outstanding, uncollectible accounts for CFD crude oil
sales as of December 31, 2006.
The CFD crude is a heavy, sweet crude oil, with an API gravity
of approximately 19 degrees. The production from these first
seven fields is from multiple productive reservoirs, which have
variability in the quality of oil. Due to its quality and
physical characteristics, refiners and other markets for the CFD
crude oil typically expect to be able to purchase CFD crude at
prices that are lower than light sweet crude oils like West
Texas Intermediate or Brent. Oil produced and sold from the
seven CFD fields is typically priced based upon the monthly
official ICP for Duri field crude. The Duri crude, produced in
Indonesia, is of similar quality to the CFD crude produced in
the Bohai Bay area. The official ICP Duri price is a monthly
weighted average of three, independent daily assessments of the
price of Duri crude, reported by Platts Asian Petroleum
Price Index published by Seapac Services Limited, and RIM
Intelligence Co. To the monthly official ICP Duri marker price,
a premium or discount is added to reflect transportation and
quality differentials for the CFD crude relative to the Duri
marker crude. The premium or discount for the CFD crude
(relative to the Duri price) is negotiated monthly between the
Company and its partners, including CNOOC. During 2006, the
premium or discount from the ICP Duri price ranged from a
discount of approximately $10.00 USD to a premium of more than
$1.00 USD.
Environmental
Matters
In 1998, the U.S. Bureau of Land Management
(BLM) initiated a requirement for an Environmental
Impact Statement (EIS) for federal lands in the
Pinedale Anticline area in the Green River Basin. The Company
also co-owns leases on state and privately owned lands in the
vicinity of the Pinedale Anticline that do not fall under the
federal jurisdiction of the BLM and are not subject to the EIS
requirement. An EIS evaluates the effects that an
industrys activities will have on the environment in which
the activity is proposed. This EIS encompasses the area north of
the Jonah Field, including the Pinedale Anticline, which is
where most of the Companys exploration and development is
taking place. This environmental study includes an analysis of
the geological and reservoir characteristics of the area plus
the necessary environmental studies related to wildlife, surface
use, socio-economic and air quality issues. On July 27,
2000, the BLM issued its Record of Decision (ROD)
with respect to the final EIS. The ROD/EIS allows for the
drilling of 700 producing surface locations within the area
covered by the EIS, but does not authorize the drilling of
particular wells. Ultra must submit applications to the
BLMs Pinedale field manager for permits to drill and other
required authorizations, such as
rights-of-way
for pipelines, for the drilling of each specific well or
particular pipeline location. Development activities in the
Pinedale Anticline area, as on all federal leaseholds, remain
subject to regulatory agency approval. In making its
determination on whether to approve specific drilling or
development activities, the BLM applies the requirements
outlined in the ROD/EIS.
10
The ROD/EIS imposes limitations and restrictions on activities
in the Pinedale Anticline area, including limits on winter
drilling and completion activity, proposes mitigation
guidelines, standard practices for industry activities and best
management practices for sensitive areas. The ROD/EIS also
provides for annual reviews to compare actual environmental
impacts to the environmental impacts estimated in the EIS and
provides for adjustments to mitigate such impacts, if necessary.
The review team is comprised of operators, local residents and
other affected persons. The Company cannot predict if or how
these changes may affect permitting, development and compliance
under the ROD/EIS. The BLMs field manager may also impose
additional limitations and mitigation measures as are deemed
reasonably necessary to mitigate the impact of drilling and
production operations in the area.
As of December 31, 2006, the Company had approximately
130 well locations that both the BLM and the WOGCC have
approved permits to drill on Company operated federal leases in
the Pinedale Anticline and Jonah field areas.
To date, the Company has expended significant resources in order
to satisfy applicable environmental laws and regulations in the
Pinedale Anticline area and other areas of operation under the
jurisdiction of the BLM. The Companys future costs of
complying with these regulations may continue to be substantial.
Further, any additional limitations and mitigation measures
could further increase production costs, delay exploration,
development and production activities or curtail exploration,
development and production activities altogether.
In August 1999, the BLM required an Environmental Assessment
(EA) for the potential increased density drilling in
the Jonah Field area. An EA is a more limited environmental
study than that conducted under an EIS. The EA was required to
address the potential environmental impacts of developing the
field on a well density of two wells per
80-acre
drilling and spacing unit as opposed to the one well per
80-acre
drilling and spacing unit as was approved in the initial Jonah
field EIS approved in 1998. The new EA was completed in June
2000. With the approval of this EA and the earlier approval by
the WOGCC for drilling of two wells per
80-acre
drilling and spacing unit, the Company was permitted to drill
infill wells at this well density on the 2,160 gross (1,322
net) acres then owned by the Company in the Jonah field. Prior
to these approvals, the Company had drilled 21 gross
(7.7 net) wells in the field. Since the increased density
approvals, the Company has drilled an additional 22 gross
(14.0 net) wells in the field. All 43 wells drilled by
Ultra in the Jonah field have been productive. Subsequently,
various other operators have received approval for the drilling
of increased density wells in pilot areas at well densities
ranging from four wells per
80-acre
drilling and spacing unit to sixteen wells per drilling and
spacing unit. Results of all of these pilot projects were
utilized in acquiring approval from the WOGCC in November 2004
to increase the overall density of development for the Jonah
Field to eight wells per
80-acre
drilling and spacing unit.
The BLM conducted a new EIS covering the Jonah field to assess
the impact of increased density development and define the
parameters under which this increased density development will
be allowed to proceed. The draft EIS was made available in
February 2005 and the final ROD was issued on March 14,
2006. Key components of the ROD approval require an annual
operations plan that includes all previous year activity
including the number of wells drilled, total new surface
disturbance by well pads, roads, and pipelines, and current
status of all reclamation activity. Also required is a plan of
development for the upcoming year reflecting the planned number
of wells to be drilled and an estimate of new surface
disturbance and reclamation activity. Other components include a
drilling rig forecast, emission reduction report, annual water
well monitoring reports, a three-year operational forecast and
the use of flareless-completion technology to reduce noise,
visual impacts and air emissions, including greenhouse gases as
well as other monitoring and mitigation measures described in
the BLM ROD. As of December 31, 2006, Ultra had two rigs
operating within the area of approval.
During 2003, 2004 and 2005, Ultra and other operators in the
Pinedale field received approval from the WOGCC to drill
increased density pilot project wells in several areas across
the Pinedale field. These pilot projects are designed to test
the feasibility of developing this field in well densities
greater than the currently approved one well per
40-acres.
The results of some of this work led to the WOGCC in July 2004
approving the development of the northern portion of the
anticline on two wells per
40-acre
density. The acreage is operated by Questar Exploration and
Production Company (Questar), a working interest
partner of the Company, and the Company owns a working interest
in the majority of this acreage. This approval covers
approximately 14,432 gross acres. Since this time,
additional increased density pilot wells have been drilled by
Ultra and others on the pilot areas within the Pinedale field.
Based on the data gathered through these pilot projects, the
WOGCC approved several
11
additional Increased Density Applications during 2005. In August
2005, approval was granted for development of a significant
portion of the northern portion of the Pinedale field for
drilling on four wells per
40-acre
density. This approval covers approximately 11,256 gross
acres in which Ultra owns an interest and are operated by
Questar. In November 2005, approval was granted for development
of a significant portion of the central Pinedale field and
surrounding area on a two wells per
40-acre
density. This approval covers approximately 23,816 gross
acres in which Ultra owns an interest. Ultra operates the
majority of the acreage covered by this approval. During 2006,
Ultra and other operators in the Pinedale field received
approval from the WOGCC to drill increased density wells in two
new areas of the Pinedale field. These two areas cover a total
of 10,043 acres and will permit the development of the
Lance Pool in these areas at the equivalent of one well per
10-acres. Of
the 1,043 locations now available in these two areas, the
Company owns an interest in 947 of them and will be the operator
of 724 locations. With this approval nearly 50% of the
productive area of the Pinedale field has now been approved by
the WOGCC for drilling at the equivalent of
10-acre
density. An additional 30% has been approved for drilling at
equivalent
20-acre
density with the balance still under the state wide
40-acre well
density rules. Further drilling and testing within the areas
approved for increased density continues and the results of
these are being evaluated to determine the appropriate course of
action as to the overall development strategy for the Pinedale
field and the ultimate need for future increases in development
density.
In April 2004, Questar asked the BLM to modify winter access
restrictions to allow operations on three active pads with two
drilling rigs per pad during the winter restriction period. This
request required an EA to weigh the negative impacts of winter
activity relative to the extensive mitigation measures proposed
by Questar. On November 9, 2004, Questar received approval
in the form of a Finding of No Significant Impact
(FONSI) from the BLM to phase in over the next year
the proposed year-round drilling program which allowed two
drilling rigs on one pad during the winter of
2004-2005.
Questars proposed mitigation measures included
construction of a water and condensate gathering system during
the summer of 2005. Questars proposal allows six rigs to
operate from three active pads beginning in the winter of
2005-2006
through the winter of
2013-2014
once implementation of the proposed mitigation measures is
complete.
The BLM approved Questars proposal after considering
extensive input from the participating agencies received during
a public comment process. Key components of the approval are:
1) one pad with two drilling rigs during the winter of
2004-2005;
2) three pads with two drilling rigs per pad in the winter
of 2005-2006
and thereafter through the winter of
2013-2014;
3) activities during the May-November period will continue
to be governed by the original Pinedale Anticline EIS;
4) directional drilling with up to 16 wells per pad
resulting in only one-third of the drilling phase surface
disturbance contemplated under the original EIS;
5) construction of a produced water and condensate
gathering system in 2005; 6) funding for continued
monitoring of mule deer and other critical wildlife for the
duration of development activity; 7) use of
flareless-completion technology to reduce noise, air and visual
pollution during well-completion operations; 8) funding for
air-quality monitoring; and 9) wildlife habitat enhancement
as well as other monitoring and mitigation measures described in
the BLM decision record.
Questar is proceeding with the winter drilling program as
proposed. Currently there are six Questar operated drilling rigs
operating within the area of approval, two rigs on each of three
separate winter pads. These wells will be drilled to total
depth, logged and cased during the winter restriction period
with completion activity to commence in the spring with the
lifting of the normal seasonal wildlife restrictions.
In early 2005, Ultra, along with Anschutz and Shell
(Proponents) proposed a winter access demonstration
project to the BLM for the Mesa area of the Pinedale field. This
area is normally subject to the winter big game stipulation
which prohibits drilling and completion activities in the area
from November 15th until April 30th. Under the
terms of the proposal, the Proponents would be able to operate a
total of six rigs, two each on three different winter pads.
During this winter demonstration project, the Proponents
employed innovative technologies and practices for operations to
provide a more beneficial alternative to the current wildlife
restrictions. Upon successful completion of the winter
demonstration project, the Proponents intend to apply the
operations principles demonstrated to implement a long-term
development plan that will result in substantially less impact
to wildlife, habitat, and local communities than what is allowed
under the current Pinedale Anticline Project Area
(PAPA) ROD while providing assurance of year-round
access from the BLM to permit the implementation of a
comprehensive development scenario for the Pinedale field. An EA
was conducted by the BLM to evaluate the winter
12
demonstration project proposal and associated impacts and the
Proponents received approval in the form of a FONSI ruling from
the BLM in September 2005. The Proponents began activities in
the winter demonstration project in November 2005. The FONSI
ruling includes several conditions of approval requiring
monitoring and mitigation of impacts on wildlife and monitoring
and mitigation of rig engine emissions and noise levels
associated with project drilling activities. Ultra operated four
rigs during the
2005-2006
winter demonstration project and met its commitments under the
terms of the approval. The wells were drilled to total depth,
logged and cased during winter restriction period. Completion
activity commenced in the spring of 2006 with the lifting of
normal seasonal wildlife restrictions.
Subsequent to the FONSI ruling allowing implementation of the
winter demonstration project, the Proponents submitted a
development proposal for the Pinedale field which includes broad
application of operations principles being evaluated in the
demonstration project area. The Proponents entered into a
memorandum of understanding with the BLM to commence the
preparation of a Supplemental Environmental Impact Statement
(SEIS) for year-round access in the Pinedale field.
The SEIS process is proceeding and impacts the development
proposal that will be analyzed to assess alternative
considerations and mitigation requirements that should be
considered as alternatives to those included in the proposal or
in addition to those measures now proposed. The proposed action
includes commitments to reduce surface disturbance by utilizing
fewer overall pads and drilling more directional wells than
called for in the PAPA ROD. Also, if approved, the
Proponents proposal commits to reduced air emissions. The
Proponents have proposed to apply technology to drilling rig
engines to reduce emissions, to reduce vehicle traffic by
installing a liquids gathering system as appropriate in the
field, and by expanding the use of telemetry to reduce
production operations traffic requirements. The Proponents
have also proposed additional monitoring to assess benefits of
mitigation activities on the impacts of development activities
on the wildlife in the project area. The proposal commits to 3:1
offsite mitigation measures should the monitoring indicate it is
warranted. If approved, the Proponents proposal commits to
reduced reserve pit use and to accelerated surface reclamation.
The draft SEIS (DSEIS) was sent out for public
comment on December 15, 2006. The closing date for public
comment is anticipated for March 15, 2007 and the final ROD
is anticipated in the summer of 2007.
Development activities in the Pennsylvania area also remain
subject to regulatory agency approval and compliance with
performance standards. Ultra must submit applications to the
Pennsylvania Department of Environmental
Protection (DEP) for permits to drill and for
other required authorizations, such as
rights-of-way
for pipelines for each specific well or pipeline location. In
February 2006, the Company submitted a general permit for
construction to the Pennsylvania DEP for the Marshlands Pipeline
PL-101 gathering line in Tioga County and the associated
Preparedness, Prevention, Contingency Plan. As of
December 31, 2006, there was one rig operating in the
permit area and the Company had approximately one additional
well location with respect to which Pennsylvania DEP has
approved permits to drill on Company-operated leases in the
Pennsylvania area.
In September 2002, the Company received the Oil and Gas
Wildlife Stewardship award from the Wyoming Game and Fish
Department in recognition of its contribution to wildlife
management in the Pinedale area. During 2001, the Company
received the Agency/Corporation of the Year award
from the Wyoming Wildlife Federation and the Regional
Administrators Award for Environmental Achievement
from the U.S. Environmental Protection Agency.
Regulation
Oil
and Gas Regulation
The availability of a ready market for oil and natural gas
production depends upon numerous factors beyond the
Companys control. These factors may include, among other
things, state and federal regulation of oil and natural gas
production and transportation, as well as regulations governing
environmental quality and pollution control, state limits on
allowable rates of production by a well or proration unit, the
amount of oil and natural gas available for sale, the
availability of adequate pipeline and other transportation and
processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be
shut-in because of a lack of an available natural
gas pipeline in the areas in which the Company may conduct
operations. State and federal regulations are generally intended
to prevent waste of oil and natural gas, protect rights to
produce oil and natural
13
gas between owners in a common reservoir, control the amount of
oil and natural gas produced by assigning allowable rates of
production and control contamination of the environment.
Pipelines and natural gas plants are also subject to the
jurisdiction of various federal, state and local agencies.
The Companys sales of natural gas are affected by the
availability, terms and costs of transportation both in the
gathering systems that transport the natural gas from the
wellhead to the interstate pipelines and in the interstate
pipelines themselves. The rates, terms and conditions applicable
to the interstate transportation of natural gas by pipelines are
regulated by the FERC under the Natural Gas Act, as well as
under Section 311 of the Natural Gas Policy Act. Since
1985, the FERC has implemented regulations intended to increase
competition within the natural gas industry by making natural
gas transportation more accessible to natural gas buyers and
sellers on an open-access, non-discriminatory basis. On
February 25, 2000, the FERC issued a statement of policy
and a final rule concerning alternatives to its traditional
cost-of-service
rate-making methodology to establish the rates interstate
pipelines may charge for services. The final rule revises the
FERCs pricing policy and current regulatory framework to
improve the efficiency of the market and further enhance
competition in natural gas markets. The FERC is also considering
a number of regulatory initiatives that could affect the terms
and costs of interstate transportation of natural gas by
interstate pipelines on behalf of natural gas shippers,
including policy inquiries about natural gas quality and
interchangeability, selective discounting of transportation
services by pipelines to shippers, and proposed rules governing
pipeline creditworthiness and collateral standards. Because
these regulatory initiatives have not been made final, the
approach the FERC will take and the potential impact on natural
gas suppliers remain unclear.
The Companys sales of oil are also affected by the
availability, terms and costs of transportation. The rates,
terms, and conditions applicable to the interstate
transportation of oil by pipelines are regulated by the FERC
under the Interstate Commerce Act. The FERC has implemented a
simplified and generally applicable ratemaking methodology for
interstate oil pipelines to fulfill the requirements of
Title XVIII of the Energy Policy Act of 1992 comprised of
an indexing system to establish ceilings on interstate oil
pipeline rates.
If the Company conducts operations on federal, tribal or state
lands, such operations must comply with numerous regulatory
restrictions, including various operational requirements and
restrictions, nondiscrimination statutes and royalty and related
valuation requirements. In addition, some operations must be
conducted pursuant to certain
on-site
security regulations, bonding requirements and applicable
permits issued by the BLM or Minerals Management Service, Bureau
of Indian Affairs, tribal or other applicable federal, state
and/or
Indian Tribal agencies.
The Mineral Leasing Act of 1920 (Mineral Act)
prohibits direct or indirect ownership of any interest in
federal onshore oil and gas leases by a foreign citizen of a
country that denies similar or like privileges to
citizens of the United States. Such restrictions on citizens of
a non-reciprocal country include ownership or holding or
controlling stock in a corporation that holds a federal onshore
oil and gas lease. If this restriction is violated, the
corporations lease can be canceled in a proceeding
instituted by the United States Attorney General. Although the
regulations of the BLM (which administers the Mineral Act)
provide for agency designations of non-reciprocal countries,
there are presently no such designations in effect. The Company
owns interests in numerous federal onshore oil and gas leases.
It is possible that holders of the Companys equity
interests may be citizens of foreign countries, which could be
determined to be citizens of a non-reciprocal country under the
Mineral Act.
See Risk Factors for a discussion of the
risks involved in our international operations.
Environmental
Regulations
General. The Companys activities in the
United States are subject to existing federal, state and local
laws and regulations governing environmental quality, oil spills
and pollution control. Activities in China are subject to the
laws and regulations of China. It is anticipated that, absent
the occurrence of an extraordinary event, compliance with
existing federal, state and local laws, rules and regulations
governing the release of materials in the environment or
otherwise relating to the protection of the environment, will
not have a material effect upon the Companys operations,
capital expenditures, earnings or competitive position.
14
The Companys exploration, drilling and production
activities from wells and natural gas facilities, including the
operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing
oil, natural gas and other products, are subject to stringent
environmental regulation by state and federal authorities,
including the Environmental Protection Agency (EPA).
Such regulation can increase the cost of planning, designing,
installing and operating such facilities. Usually, the EPA
regulatory requirements relate to water and air pollution
control measures.
Solid and Hazardous Waste. The Company has
previously owned or leased and currently owns or leases,
numerous properties that have been used for the exploration and
production of oil and natural gas for many years. Although the
Company utilized standard operating and disposal practices,
hydrocarbons or other solid wastes may have been disposed of or
released on or under such properties on or under locations where
such wastes have been taken for disposal. In addition, many of
these properties are or have been operated by third parties over
whom the Company has no control, nor has ever had control as to
such entities treatment of hydrocarbons or other wastes or
the manner in which such substances may have been disposed of or
released. State and federal laws applicable to oil and natural
gas wastes and properties have gradually become stricter over
time. As the law evolves, the Company could be required to
remediate property, including ground water, containing or
impacted by previously disposed wastes (including wastes
disposed of or released by prior owners or operators) or to
perform remedial plugging operations to prevent future, or
mitigate existing contamination.
The Company may generate wastes, including hazardous wastes that
are subject to the federal Resource Conservation and Recovery
Act (RCRA) and comparable state statutes. The EPA
and various state agencies have limited the disposal options for
certain wastes, including wastes designated as hazardous under
the RCRA and state analogs (Hazardous Wastes) and is
considering adopting stricter disposal standards for
non-hazardous wastes. Furthermore, certain wastes generated by
the Companys oil and natural gas operations that are
currently exempt from treatment as Hazardous Wastes may in the
future be designated as Hazardous Wastes under the RCRA or other
applicable statutes, and therefore be subject to more rigorous
and costly operating and disposal requirements.
Superfund. The federal Comprehensive
Environmental Response, Compensation and Liability Act
(CERCLA), also known as the Superfund
law, generally imposes joint and several liability for costs of
investigation and remediation and for natural resource damages,
without regard to fault or the legality of the original conduct,
on certain classes of persons with respect to the release into
the environment of substances designated under CERCLA as
hazardous substances (Hazardous Substances). These
classes of persons, or so-called potentially responsible parties
(PRP), include current and certain past owners and
operators of a facility where there has been a release or threat
of release of a Hazardous Substance and persons who disposed of
or arranged for the disposal of the Hazardous Substances found
at such a facility. CERCLA also authorizes the EPA and, in some
cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from
the PRP the costs of such action. Although CERCLA generally
exempts petroleum from the definition of Hazardous
Substance, in the course of its operations, the Company has
generated and will generate wastes that fall within
CERCLAs definition of Hazardous Substances. The Company
may also be an owner or operator of facilities on which
Hazardous Substances have been released. The Company may be
responsible under CERCLA for all or part of the costs to clean
up facilities at which such substances have been released and
for natural resource damages. To its knowledge, the Company has
not been named a PRP under CERCLA nor have any prior owners or
operators of its properties been named as PRPs related to
their ownership or operation of such property.
National Environmental Policy Act. The federal
National Environmental Policy Act provides that, for those
federal actions that are major federal actions significantly
affecting the quality of the human environment, the federal
agency taking such action must follow certain steps in
evaluating the environmental impacts of the federal action. This
evaluation generally takes the form of an EIS. In the EIS, the
agency is required to evaluate alternatives to the proposed
action and the environmental impacts of such alternatives.
Actions such as drilling on federal lands, to the extent the
drilling requires federal approval, likely trigger the
requirements of the National Environmental Policy Act, with few
exceptions. Certain of the Companys activities may trigger
these requirements. The requirements of the National
Environmental Policy Act may result in increased costs,
significant delays and the imposition of restrictions or
obligations, including but not limited to the restricting or
prohibiting of drilling on a companys activities.
15
Oil Pollution Act. The Oil Pollution Act of
1990 (OPA), which amends and augments oil spill
provisions of the Clean Water Act (CWA), imposes
certain duties and liabilities on certain responsible
parties related to the prevention of oil spills and
damages resulting from such spills in or threatening United
States waters or adjoining shorelines. A liable
responsible party includes the owner or operator of
a facility, vessel or pipeline that is a source of an oil
discharge or that poses the substantial threat of discharge or,
in the case of offshore facilities, the lessee or permittee of
the area in which a discharging facility is located. The OPA
assigns joint and several liability, without regard to fault, to
each liable party for oil removal costs and a variety of public
and private damages. Although defenses and limitations exist to
the liability imposed by OPA, they are limited. In the event of
an oil discharge or substantial threat of discharge, a company
could be liable for costs and damages.
Air Emissions. The Companys operations
are subject to local, state and federal regulations for the
control of emissions from sources of air pollution. Federal and
state laws require new and modified sources of air pollutants to
obtain permits prior to commencing construction. Major sources
of air pollutants are subject to stringent, federally imposed
requirements such as obtaining permits. Other federal and state
laws designed to control hazardous (toxic) air pollutants, might
require installation of additional controls. Administrative
enforcement agencies can bring actions for failure to strictly
comply with air pollution regulations or permits and generally
enforce compliance by imposing monetary fines and identified
deficiencies. Alternatively, regulatory agencies can file
lawsuits for civil penalties or the use of certain air emission
sources for construction, modification or operations.
Clean Water Act. The CWA restricts the
discharge of wastes, including produced waters and other oil and
natural gas wastes, into waters of the United States, a term
broadly defined. These controls have become more stringent over
the years, and it is probable that additional restrictions will
be imposed in the future. Permits must be obtained to discharge
pollutants into federal waters. The CWA provides for civil,
criminal and administrative penalties for unauthorized
discharges of pollutants and of oil and hazardous substances. It
imposes substantial potential liability for the costs of removal
or remediation associated with discharges of oil or hazardous
substances. State laws governing discharges to water also
provide varying civil, criminal and administrative penalties and
impose liabilities in the case of a discharge of petroleum or
its derivatives, or other hazardous substances, into state
waters. In addition, the EPA has promulgated regulations that
may require permits to discharge storm water runoff, including
discharges associated with construction activities. In the event
of an unauthorized discharge of wastes, a company may be liable
for penalties and costs.
Endangered Species Act and the Migratory Bird Treaty
Act. The Endangered Species Act (ESA)
was established to provide a means to conserve the ecosystems
upon which endangered and threatened species depend, to provide
a program for conservation of these endangered and threatened
species, and to take the appropriate steps that are necessary to
bring any endangered or threatened species to the point where
measures provided for in the ESA are no longer necessary. The
Migratory Bird Treaty Act decreed that all migratory birds and
their parts (including eggs, nests, and feathers) were fully
protected. The Company conducts operations on federal oil and
natural gas leases that have species, such as raptors that are
listed as threatened or endangered and also sage grouse or other
sensitive species, that potentially could be listed as
threatened or endangered under the ESA. If a species is listed
as threatened or endangered, the U.S. Fish and Wildlife
Service must also designate the species critical habitat
and suitable habitat as part of the effort to ensure survival of
the species. A critical habitat or suitable habitat designation
could result in further material restrictions to federal land
use and may materially delay or prohibit land access for oil and
natural gas development. If a company were to have a portion of
its leases designated as critical or suitable habitat, it may
adversely impact the value of the affected leases.
OSHA and other Regulations. The Company is
subject to the requirements of the federal Occupational Safety
and Health Act (OSHA) and comparable state statutes.
The OSHA hazard communication standard, the EPA community
right-to-know
regulations under Title III of CERCLA and similar state
statutes require a company to organize
and/or
disclose information about hazardous materials used or produced
in its operations.
The Company believes that it is in substantial compliance with
current applicable environmental laws and regulations and that
continued compliance with existing requirements will not have a
material adverse impact on the Company.
16
Employees
As of December 31, 2006, the Company had 68 full-time
employees, including officers.
There
are inherent limitations in all control systems and failure of
our controls and procedures to detect error or fraud could
seriously harm our business and results of
operations.
Our management, including our Chief Executive Officer and Chief
Financial Officer, does not expect that our internal controls
and disclosure controls will prevent all possible error and all
fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance
that the objectives of the control system are met. In addition,
the design of a control system must reflect the fact that there
are resource constraints and the benefit of controls must be
relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of our controls can provide
absolute assurance that all control issues and instances of
fraud, if any, in our Company have been detected. These inherent
limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur
because of simple error or mistake. Further, controls can be
circumvented by the individual acts of some persons or by
collusion of two or more persons. The design of any system of
controls is based in part upon the likelihood of future events,
and there can be no assurance that any design will succeed in
achieving its intended goals under all potential future
conditions. Over time, a control may become inadequate because
of changes in conditions or the degree of compliance with its
policies or procedures may deteriorate. Because of inherent
limitations in a cost-effective control system, misstatements
due to error or fraud may occur without detection.
Our
reserve estimates may turn out to be incorrect if the
assumptions upon which these estimates are based are inaccurate.
Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and
present value of our reserves.
There are numerous uncertainties inherent in estimating
quantities of proved reserves and projected future rates of
production and timing of development expenditures, including
many factors beyond our control. The reserve data and
standardized measures set forth herein represent only estimates.
Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be
measured in an exact way and the accuracy of any reserve
estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a
result, estimates of different engineers often vary. In
addition, results of drilling, testing and production data
acquired subsequent to the date of an estimate may justify
revising such estimates. Accordingly, reserve estimates are
often different from the quantities of oil and natural gas that
are ultimately recovered. Further, the estimated future net
revenues from proved reserves and the present value thereof are
based upon certain assumptions, including geologic success,
prices, future production levels and costs that may not prove
correct over time. Predictions of future production levels are
subject to great uncertainty, and the meaningfulness of such
estimates is highly dependent upon the accuracy of the
assumptions upon which they are based. Historically, oil and
natural gas prices have fluctuated widely.
Competitive
industry conditions may negatively affect our ability to conduct
operations.
We compete with numerous other companies in virtually all facets
of our business. The competitors in development, exploration,
acquisitions and production include major integrated oil and
natural gas companies as well as numerous independents,
including many that have significantly greater resources.
Therefore, competitors may be able to pay more for desirable
leases and evaluate, bid for and purchase a greater number of
properties or prospects than the financial or personnel
resources that our Company can permit. Our ability to increase
reserves in the future will be dependent on our ability to
select and acquire suitable prospects for future exploration and
development.
Factors that affect our ability to compete in the marketplace
include:
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our access to the capital necessary to drill wells and acquire
properties;
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our ability to acquire and analyze seismic, geological and other
information relating to a property;
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17
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our ability to retain the personnel necessary to properly
evaluate seismic and other information relating to a
property; and
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our ability to access platforms and pipelines, and the locations
of facilities used to produce and transport oil and natural gas
production.
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Factors
beyond our control affect our ability to effectively market
production and may ultimately affect our financial
results.
The ability to market oil and natural gas depends on numerous
factors beyond our control. These factors include:
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the extent of domestic production and imports of oil and natural
gas;
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the availability of pipeline capacity;
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the proximity of natural gas production to those natural gas
pipelines;
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the effects of inclement weather;
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the demand for oil and natural gas by utilities and other end
users;
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the availability of alternative fuel sources;
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state and federal regulations of oil and natural gas marketing;
and
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federal regulation of natural gas sold or transported in
interstate commerce.
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Because of these factors, we may be unable to market all of our
oil and natural gas that we produce, including oil and natural
gas that may be produced from the Bohai Bay properties in China.
In addition, we may be unable to obtain favorable prices for the
oil and natural gas we produce.
We may
experience a temporary decline in revenues if we lose one of our
significant customers.
A significant customer as used herein is one that individually
accounts for 10% or more of our total natural gas or oil sales.
In 2006, we had one significant customer for our CFD Chinese
crude oil: CNOOC, and three significant customers
for our natural gas production Southern California
Gas Company, J. Aron (Goldman Sachs), and Sempra Energy Trading.
To the extent these or any other significant customer reduces
the volume of its oil or natural gas purchases from us, we could
experience a temporary interruption in sales of, or a lower
price for, our oil and natural gas.
A
decrease in oil and natural gas prices may adversely affect our
results of operations and financial condition.
Our revenues are determined, to a large degree, by prevailing
natural gas prices for production situated in the Rocky Mountain
Region of the United States, specifically, southwest Wyoming, as
well as prevailing prices for crude oil produced in the Bohai
Bay region of China. Energy commodity prices in general, and our
regional prices in particular, have been historically highly
volatile, and such high levels of volatility are expected to
continue in the future. We cannot accurately predict the market
prices that we will receive for the sale of our natural gas,
condensate, or oil production.
Oil and natural gas prices are subject to a variety of
additional factors beyond our control, such as large
fluctuations in oil and natural gas prices in response to
relatively minor changes in the supply of and demand for oil and
natural gas and market uncertainty. These factors include but
are not limited to weather conditions in the United States, the
condition of the United States economy, the actions of the
Organization of Petroleum Exporting Countries, governmental
regulation, political stability in the Middle East and
elsewhere, the foreign supply of oil and natural gas, the price
of foreign oil and natural gas imports and the availability of
alternate fuel sources and transportation interruption. Any
substantial and extended decline in the price of oil or natural
gas could have an adverse effect on the carrying value of our
proved reserves, borrowing capacity, our ability to obtain
additional capital, and the Companys revenues,
profitability and cash flows from operations.
18
Volatile oil and natural gas prices make it difficult to
estimate the value of producing properties for acquisition and
divestiture and often cause disruption in the market for oil and
natural gas producing properties, as buyers and sellers have
difficulty agreeing on such value. Price volatility also makes
it difficult to budget for and project the return on
acquisitions and development and exploitation projects.
A
price decrease may more adversely affect the price received for
our Wyoming production than production in other
U.S. regions.
Natural gas prices in the southwest Wyoming region are critical
to our business. The market price for this natural gas differs
from the market indices for natural gas in the Gulf Coast region
of the United States due potentially to insufficient pipeline
capacity
and/or low
demand during certain months of the year for natural gas in the
Rocky Mountain region of the United States. Therefore, a price
decrease may more adversely affect the price received for our
Wyoming production than production in the other
U.S. regions. There have been, from time to time, numerous
proposed pipeline projects, including the Rockies Express
Pipeline, that have been announced to transport Rockies
and Wyoming natural gas production to markets. There can be no
assurance that such infrastructures will be built or that if
built, they would prevent large basis differentials from
occurring in the future.
Compliance
with environmental and other government regulations could be
costly and could negatively impact our production.
Our operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and
regulations may:
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require that we acquire permits before commencing drilling;
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restrict the substances that can be released into the
environment in connection with drilling and production
activities;
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limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas;
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require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells; and
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require governmental approval of the overall development plan
prior to the start of development of fields in China.
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Under these laws and regulations, we could be liable for
personal injury and
clean-up
costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain
limited insurance coverage for sudden and accidental
environmental damages, but do not maintain insurance coverage
for the full potential liability that could be caused by sudden
and accidental environmental damages. Accordingly, we may be
subject to liability or may be required to cease production from
properties in the event of environmental damages.
A significant percentage of our United States operations are
conducted on federal lands. These operations are subject to a
variety of
on-site
security regulations as well as other permits and authorizations
issued by the BLM, the Wyoming Department of Environmental
Quality and other federal agencies. A portion of our acreage is
affected by winter lease stipulations that prohibit exploration,
drilling and completing activities generally from
November 15th to April 30th, but allow production
activities all year round. To drill wells in Wyoming, we are
required to file an Application for Permit to Drill with the
WOGCC. Drilling on acreage controlled by the federal government
requires the filing of a similar application with the BLM. These
permitting requirements may adversely affect our ability to
complete our drilling program at the cost and in the time period
anticipated. On large-scale projects, lessees may be required to
perform an EIS to assess the environmental impact of potential
development, which can delay project implementation
and/or
result in the imposition of environmental restrictions that
could have a material impact on cost or scope.
19
We may
not be able to replace our reserves or generate cash flows if we
are unable to raise capital. We will be required to make
substantial capital expenditures to develop our existing
reserves and to discover new oil and gas reserves.
Our ability to continue exploration and development of our
properties and to replace reserves may be dependent upon our
ability to continue to raise significant additional financing,
including debt financing or obtain other potential arrangements
with industry partners in lieu of raising financing. Any
arrangements that may be entered into could be expensive to us.
There can be no assurance that we will be able to raise
additional capital in light of factors such as the market demand
for our securities, the state of financial markets for
independent oil and gas companies (including the markets for
debt), oil and natural gas prices and general market conditions.
See Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources for a discussion of our capital budget.
We expect to continue using our bank credit facility to borrow
funds to supplement our available cash flow. The amount we may
borrow under the credit facility may not exceed a borrowing base
determined by the lenders based on their projections of our
future production, future production costs and taxes, commodity
prices and other factors. We cannot control the assumptions the
lenders use to calculate the borrowing base. The lenders may,
without our consent, adjust the borrowing base at any time. If
our borrowings under the credit facility exceed the borrowing
base, the lenders may require that we repay the excess
borrowing. If this occurred, we may have to sell assets or seek
financing from other sources. We can make no assurances that we
would be successful in selling assets or arranging substitute
financing. For a description of the bank credit facility and its
principal terms and conditions, see Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
Our
operations may be interrupted by severe weather or drilling
restrictions, particularly in the Rocky Mountain
region.
Our operations are conducted primarily in the Rocky Mountain
region of the United States. The weather in this area can be
extreme and can cause interruption in our exploration and
production operations. Severe weather can result in damage to
our facilities entailing longer operational interruptions and
significant capital investment. Likewise, our Rocky Mountain
operations are subject to disruption from winter storms and
severe cold, which can limit operations involving fluids and
impair access to our facilities. A portion of our acreage is
affected by winter lease stipulations that prohibit drilling and
completing activities from November 15th to
April 30th, but allow production activities all year round.
Our
focus on exploration projects increases the risks inherent in
our oil and gas activities.
We have historically invested a significant portion of our
capital budget in drilling exploratory wells in search of
unproved oil and gas reserves. We cannot be certain that these
exploratory wells will be productive or that we will recover all
or any portion of our investments. To increase the chances for
exploratory success, we often invest in seismic or other
geoscience data to assist us in identifying potential drilling
objectives. Additionally, the cost of drilling, completing and
testing exploratory wells is often uncertain at the time of our
initial investment. Depending on complications encountered while
drilling, the final cost of the well may significantly exceed
our original estimate. We use the full cost method of accounting
for exploration and development activities as defined by the
SEC. Under this method of accounting, the costs of unsuccessful,
as well as successful, exploration and development activities
are capitalized as properties and equipment and are then
depleted using the unit of production method based on our proved
reserves.
Unless
we are able to replace reserves which we have produced, our cash
flows and production will decrease over time.
Our future success depends on our ability to find, develop and
acquire additional oil and gas reserves that are economically
recoverable. Without successful exploration, development or
acquisition activities, our reserves and production will
decline. We can give no assurance that we will be able to find,
develop or acquire additional reserves at acceptable costs.
20
We are
exposed to operating hazards and uninsured risks that could
adversely impact our results of operations and cash
flow.
The oil and natural gas business involves a variety of operating
risks, including fire, explosion, pipe failure, casing collapse,
abnormally pressured formations, and environmental hazards such
as oil spills, natural gas leaks, and discharges of toxic gases.
The occurrence of any of these events with respect to any
property we own or operate (in whole or in part) could have a
material adverse impact on us. We and the operators of our
properties maintain insurance in accordance with customary
industry practices and in amounts that management believes to be
reasonable. However, insurance coverage is not always
economically feasible and is not obtained to cover all types of
operational risks. The occurrence of a significant event that is
not fully insured could have a material adverse effect on our
financial condition.
There
are risks associated with our drilling activity that could
impact our results of operations.
Our oil and natural gas operations are subject to all of the
risks and hazards typically associated with drilling for, and
production and transportation of, oil and natural gas. These
risks include the necessity of spending large amounts of money
for identification and acquisition of properties and for
drilling and completion of wells. In the drilling of exploratory
or development wells, failures and losses may occur before any
deposits of oil or natural gas are found. The presence of
unanticipated pressure or irregularities in formations,
blow-outs or accidents may cause such activity to be
unsuccessful, resulting in a loss of our investment in such
activity. If oil or natural gas is encountered, there can be no
assurance that it can be produced in quantities sufficient to
justify the cost of continuing such operations or that it can be
marketed satisfactorily.
Our
decision to drill a prospect is subject to a number of factors
which may alter our drilling schedule or our plans to drill at
all.
This report includes certain descriptions of our future drilling
plans with respect to our prospects. A prospect is an area which
our geoscientists have identified what they believe, based on
available seismic and geological information, to be indications
of hydrocarbons. Our prospects are in various stages of review.
Whether or not we ultimately drill a prospect depends on the
following factors:
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receipt of additional seismic data or reprocessing of existing
data;
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material changes in oil or natural gas prices;
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the costs and availability of drilling equipment;
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success or failure of wells drilled in similar formations or
which would use the same production facilities;
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availability and cost of capital;
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changes in the estimates of costs to drill or complete wells;
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the approval of partners to participate in the drilling or, in
the case of CNOOC, approval of expenditures for budget purposes;
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our ability to attract other industry partners to acquire a
portion of the working interest to reduce exposure to costs and
drilling risks;
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decisions of our joint working interest owners; and
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the BLMs interpretation of an EIS and the results of the
permitting process.
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We will continue to gather data about our prospects, and it is
possible that additional information may cause us to alter our
drilling schedule or determine that a prospect should not be
pursued at all.
21
If oil
and natural gas prices decrease, we may be required to take
write-downs of the carrying value of our oil and gas
properties.
We follow the full cost method of accounting for our oil and gas
properties. A separate cost center is maintained for
expenditures applicable to each country in which we conduct
exploration
and/or
production activities. Under such method, the net book value of
properties on a
country-by-country
basis, less related deferred income taxes, may not exceed a
calculated ceiling. The ceiling is the estimated
after tax future net revenues from proved oil and gas
properties, discounted at 10% per year. In calculating
discounted future net revenues, oil and natural gas prices in
effect at the time of the calculation are held constant, except
for changes which are fixed and determinable by existing
contracts. The net book value is compared to the ceiling on a
quarterly basis. The excess, if any, of the net book value above
the ceiling is required to be written off as an expense. Under
SEC full cost accounting rules, any write-off recorded may not
be reversed even if higher oil and natural gas prices increase
the ceiling applicable to future periods. Future price decreases
could result in reductions in the carrying value of such assets
and an equivalent charge to earnings.
We are
not the operator, and have limited influence over the
operations, of our Bohai Bay properties.
Because we are not the operator and hold a minority interest, we
cannot control the pace of exploration or development in the
Bohai Bay properties or major decisions affecting the drilling
of wells or the plan for development and production, although
contract provisions give the Company certain consent rights in
some matters. The operators influence over these matters
can affect the pace at which we spend money on this project. If
the operator were to shift its focus from this project, the pace
of development could slow down or stop altogether. On the other
hand, if the operator were to decide to accelerate development
of this project, we could be required to fund our share of costs
at a faster pace than anticipated, which might exceed our
ability to raise funds. If, because of this, we were unable to
pay our share of costs, we could lose or be forced to sell our
interest in the Bohai Bay properties or be forced to not
participate in the exploration or development of specific
prospects or fields, potentially diminishing the value of our
Bohai Bay assets.
Political,
economic or legal factors associated with our ownership of
properties in China could impact our results of
operations.
Ownership of property interests and production operations in
areas outside the United States are subject to various risks
inherent in foreign operations. These risks may include:
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loss of revenue, property and equipment as a result of
expropriation, nationalization, war or insurrections;
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increases in taxes and governmental royalties;
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renegotiation of contracts with governmental entities and
quasi-governmental agencies;
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change in laws and policies governing operations of foreign
based companies;
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labor problems;
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other uncertainties arising out of foreign government
sovereignty over its international operations; and
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currency restrictions and exchange rate fluctuations.
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Tensions between China and its neighbors or various western
countries, regional political or military disruption, changes in
internal Chinese leadership, social or political disruptions
within China, a downturn in the Chinese economy, or a change in
Chinese laws or attitudes toward foreign investment could make
China an unfavorable environment in which to invest. Although
all the foreign interest owners in the Bohai Bay properties have
the right to sell production in the world market, the regulation
of the concession by China, and the likely participation by
CNOOC as a large working interest owner, make Chinese internal
and external affairs important to the investment in the Bohai
Bay property. If any of these negative events were to occur, it
could lead to a decision that there is an intolerable level of
risk in continuing with the investment, or we may be unable to
attract equity investors or lenders, or satisfy any then
existing lenders.
22
In the event of a dispute arising from our foreign operations,
we may be subject to the exclusive jurisdiction of foreign
courts or may not be successful in subjecting foreign persons to
the jurisdiction of courts in the United States or a potentially
more favorable country.
In addition, our Chinese PSC terminates after
15-years of
production, unless extended as provided for, which may be prior
to the end of the productive life of the fields.
Our
operations in China have special operational risks that may
negatively affect the value of those assets.
Offshore operations, such as our Bohai Bay properties, are
subject to a variety of operating risks specific to the marine
environment, such as capsizing, collisions
and/or loss
from storms or other adverse weather conditions. These
conditions can cause substantial damage to facilities and
interrupt production. As a result, we could incur substantial
liabilities that could result in financial losses or failures.
China has many regulations similar to those addressed in
Item 1, Environmental Regulation, that may expose us to
liability. Offshore projects, like the China field developments,
are typically large, complex construction projects that are
potentially subject to delays which may cause delays in
achieving production and profitability.
Forward-Looking
Statements
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Item 7, Managements Discussion and Analysis of
Financial Condition and Results of Operations regarding our
financial position, estimated quantities and net present values
of reserves, business strategy, plans and objectives of the
Companys management for future operations, covenant
compliance and those statements preceded by, followed by or that
otherwise include the words believe,
expects, anticipates,
intends, estimates,
projects, target, goal,
plans, objective, should, or
similar expressions or variations on such expressions are
forward-looking statements. The Company can give no assurances
that the assumptions upon which such forward-looking statements
are based will prove to be correct.
Forward-looking statements include statements regarding:
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our oil and natural gas reserve quantities, and the discounted
present value of those reserves;
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the amount and nature of our capital expenditures;
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drilling of wells;
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the timing and amount of future production and operating costs;
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business strategies and plans of management; and
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prospect development and property acquisitions.
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Some of the risks which could affect our future results and
could cause results to differ materially from those expressed in
our forward-looking statements include:
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general economic conditions;
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the volatility of oil and natural gas prices;
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the uncertainty of estimates of oil and natural gas reserves;
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the impact of competition;
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the availability and cost of seismic, drilling and other
equipment;
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operating hazards inherent in the explorations for and
production of oil and natural gas;
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difficulties encountered during the explorations for and
production of oil and natural gas;
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difficulties encountered in delivering oil and natural gas to
commercial markets;
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changes in customer demand and producers supply;
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the uncertainty of our ability to attract capital;
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compliance with, or the effect of changes in, the extensive
governmental regulations regarding the oil and natural gas
business;
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actions of operators of our oil and natural gas properties; and
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weather conditions.
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The information contained in this report, including the
information set forth under the heading Risk
Factors, identifies additional factors that could affect
our operating results and performance. We urge you to carefully
consider these factors and the other cautionary statements in
this report. Our forward-looking statements speak only as of the
date made, and we have no obligation to update these
forward-looking statements.
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Item 1B.
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Unresolved
Staff Comments.
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None.
Location
and Characteristics
The Company depends on oil and natural gas leases in Wyoming and
Pennsylvania and two PSCs in China in order to explore for
and produce oil and natural gas. The leases in Wyoming are
primarily federal leases with
10-year
lease terms until establishment of production. Production on a
lease extends the lease terms until cessation of that
production. There are 39 leases totaling approximately
65,345 gross (36,618 net) acres currently held by
production (HBP) in Wyoming. The HBP acreage
includes all of the Companys leases held within the
productive area of the Pinedale and Jonah fields. The leases in
Pennsylvania are all from private individuals, typically with
lease terms of five-years until establishment of production.
Production on the Pennsylvania leases extends the lease terms
until cessation of that production. There are approximately
320 gross (320 net) acres currently held by production
in Pennsylvania. The China petroleum contracts extend for a
maximum of
30-years and
are divided into three periods; exploration, development and
production. The exploration period is for approximately seven
years and work is to be performed and expenditures are to be
incurred to delineate the extent and amount of hydrocarbons, if
any, for each block. The development period occurs when a field
is discovered and commences on the date of approval of the
Ministry of Energy. There is no limit on the time allowed to
develop a field other than the combined maximum of
30-years.
The production period of any oil and natural gas field in a
block is a period of 15 consecutive years beginning on the date
of commencement of commercial production from the field, unless
extended. All of the Companys Chinese proved reserves are
estimated to be recovered within the current license terms.
Green
River Basin, Wyoming
As of December 31, 2006, the Company owned developed oil
and natural gas leases totaling 15,067 gross
(6,404 net) acres in the Green River Basin of Sublette
County, Wyoming which represents 95% of the Companys total
domestic developed net acreage. The Company owns undeveloped oil
and natural gas leases totaling 132,850 gross
(73,162 net) acres in the Green River Basin of Sublette
County, Wyoming which represents 37% of the Companys total
domestic undeveloped net acreage. The Companys acreage in
the Green River Basin primarily covers the Pinedale field with
several other undeveloped acreage blocks north and west of the
Pinedale field as well as acreage in the Jonah field. Holding
costs of leases in Wyoming not held by production were
approximately $71,960 for the fiscal year ended
December 31, 2006. The primary target on the Companys
Wyoming acreage is the tight gas sands of the upper Cretaceous
Lance Pool formation.
Exploratory Wells. During 2006, the Company
participated in the drilling of a total of 44 gross
(19.79 net) productive exploratory wells on the Green River
Basin properties. At December 31, 2006, there were
29 gross (10.98 net) additional exploratory wells that
commenced during the year that were either still drilling or had
drilling
24
operations suspended at a depth short of total depth and thus a
determination of productive capability could not be made at year
end.
Development Wells. During 2006, the Company
participated in the drilling of 80 gross (38.44 net)
productive development wells on the Green River Basin
properties. At year-end 2006, there were 17 gross
(6.66 net) additional development wells that commenced
during 2006 and were either still drilling or had drilling
operations suspended at a depth short of total depth. For
purposes of this report, development wells are wells identified
as proven, undeveloped locations by the Companys
independent petroleum engineering firm, Netherland,
Sewell & Associates, Inc., at the previous year end
reserve evaluation. When drilled, these locations will be
counted as development wells.
Bohai
Bay, China
Block 04/36: The PSC covering this block
became effective October 1, 1994. Negotiations with the
Chinese government in 2005 resulted in an extension of the third
exploration term to September 2007. Barring another extension,
at that time, all acreage not under appraisal, development or
production must be relinquished. The Company holds an 18.18%
exploration interest in the exploration portion of the block and
an 8.91% working interest in the CFD
11-1 and
11-2 and the
CFD 11-3 and
11-5 fields.
This block covers 413,623 gross (75,197 net) acres
under the exploration phase and 40,377 gross
(3,598 net) acres under development, or approximately 60%
of the Companys total net international acreage.
Block 05/36: The PSC covering this block
became effective March 1, 1996. Negotiations with CNOOC in
early 2006 resulted in a two year extension of the third
exploration term to February 28, 2008 when, barring an
extension, all acreage not under appraisal, development or
production must be relinquished. The Company holds a 23.03%
exploration interest in this block which covers
218,079 gross (50,376 net) acres under the exploration
phase and 15,221 gross (1,119) acres under development.
This acreage constitutes approximately 40% of the Companys
total net international acreage.
Block 04/36 and Block 05/36 Unitized
Development: Three new fields, CFD
11-6 in the
04/36 Block and CFD
12-1 and
12-1S in the
05/36 Block came on production in 2006. Because the fields were
located in close proximity, the Blocks were developed under a
single development plan. Further, because two of the fields were
located in the 05/36 Block and one was located in the 04/36
Block with different parties having different levels of interest
in the two Blocks, the three fields were unitized and a
Unitization Agreement was executed that assigned the Company a
7.82% working interest in the combined field unit.
Exploration/Appraisal Activity: In 2006, the
Company participated in drilling 1 exploration well
(0.23 net) which failed to find commercial quantities of
oil. The primary target formations on the Blocks are the Upper
and Lower Minghuazhen, Guantao and Dongying formations.
Development Activity: In July 2004, the
Company began production at the CFD
11-1 and
11-2 fields
on the 04/36 Block. Development drilling at these fields
continued through mid-2006. As of December 31, 2006, the
Company has participated in drilling a total of 58 production
wells at the CFD
11-1 and
11-2 fields.
In July 2005, the Company commenced production at the CFD
11-3 and
11-5 fields
on the 04/36 Block. The Company has participated in drilling a
total of 6 production wells at the CFD
11-3 and
11-5 fields.
In late September 2006, the Company commenced production at the
CFD 11-6,
12-1 and
12-1S
fields. The Company has participated in drilling a total of 15
production wells at the CFD
11-6,
12-1 and
12-1S
fields. The seven field production complex consists of
79 gross (6.89 net) production wells, six production
platforms and an anchored FPSO vessel.
Upon declaration of commerciality of a field or area by CNOOC,
the Companys share of all expenses within that area is
decreased by 51%, with the participation of CNOOC. For example,
the Companys 18.18% exploration interest is reduced to an
8.91% working interest in the fields on production in the 04/36
Block. Upon initiation of production, the sharing of production
is determined by the language of the PSC which states that for
each individual field: 1) a Chinese National Industrial Tax
and Royalty are applied to 100% of the gross volumes of oil,
2) Lease Operating Expenses (LOE) are then
taken out of the remainder oil and 3) after these
deductions, 62.5% of the remaining production stream is
dedicated to Exploration and Development Cost Recovery for the
participants. The Exploration Cost Recovery will be recovered
without interest, while the Development Cost Recovery will be
25
calculated with a fixed annual interest rate of 9% uplift, and
4) the remaining 37.5% of production goes to the
remainder oil category which is divided into a
share oil for CNOOC and an allocable remainder
oil for the contractors determined by a sliding scale
(determined by yearly production), X factor. Project
profit is subject to a Chinese corporate tax. During 2006, the
Chinese government levied the Petroleum Special Profits Tax
which is dependent on the sales price of oil production.
On October 16, 2003, a
15-year
contract, which provides for extension for up to an additional
10-years,
was signed by the operator to lease an FPSO. The Company
ratified the contract. The FPSO is a 110,000-150,000 dead weight
ton, double hull FPSO with a 900,000-1,100,000 barrel
storage capacity, a single point mooring and a processing plant
capable of processing 60,000 barrels of oil per day (expandable
to 80,000 barrels of oil per day). The FPSO service
agreement calls for a day rate lease payment and a sliding scale
per barrel payment that decreases based on cumulative barrels
processed.
Pennsylvania
As of December 31, 2006, the Company owned developed oil
and gas leases totaling 320 gross (320 net) acres in
the Pennsylvania portion of the Appalachian Basin which
represents 5% of the Companys total domestic developed net
acreage. The Company owns undeveloped oil and gas leases
totaling 232,691 gross (124,271 net) acres in this
area which represents 63% of the Companys total domestic
undeveloped net acreage. The Companys acreage in
Pennsylvania covers the Marshlands prospect and several other
prospects in the surrounding area. Holding costs of leases in
Pennsylvania not held by production were approximately $248,017
for the fiscal year ended December 31, 2006.
Exploratory Wells. During the year ended
December 31, 2005, the Company participated in the drilling
and completion of a total of one gross (1.0 net) well which
was completed as a field discovery from the Silurian Tuscarora
formation. The well was placed into production during May of
2006. This well continues to produce at rates of approximately
5 MMcf of gas per day at flowing pressures over 1,100 psi
casing pressure. During the year ended December 31, 2006,
the Company also participated in the drilling of a total of
2 gross (1.125 net) exploratory wells on the
Pennsylvania properties. One gross (.125 net) well was drilled
to test the Oriskany sand and Marcellus shale sections and was
being evaluated at December 31, 2006. One gross
(1.0 net) well, to test the Trenton and Black River
formations at the Marshlands prospect, was drilling at
December 31, 2006. During 2006, on the newly acquired
acreage position, the Company acquired a 3D seismic survey
covering a large prospect area. Processing and interpretation of
this data set is ongoing.
26
Oil and
Gas Reserves
The following table sets forth the Companys quantities of
domestic proved reserves, for the years ended December 31,
2006, 2005, and 2004 as estimated by independent petroleum
engineers Netherland, Sewell & Associates, Inc. The
table summarizes the Companys domestic proved reserves,
the estimated future net revenues from these reserves and the
standardized measure of discounted future net cash flows
attributable thereto at December 31, 2006, 2005 and 2004.
In accordance with Ultras three-year planning and
budgeting cycle, proved undeveloped reserves included in this
table include only economic locations that are forecast to be on
production before January 1, 2010. As of December 31,
2006, proved undeveloped reserves represent 62.7% of the
Companys domestic total proved reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
1,415,132
|
|
|
|
1,264,632
|
|
|
|
899,315
|
|
Oil (MBbl)
|
|
|
11,321
|
|
|
|
10,117
|
|
|
|
7,195
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
842,969
|
|
|
|
635,591
|
|
|
|
514,686
|
|
Oil (MBbl)
|
|
|
6,522
|
|
|
|
5,087
|
|
|
|
4,195
|
|
Total Proved Reserves (MMcfe)
|
|
|
2,365,159
|
|
|
|
1,991,447
|
|
|
|
1,482,341
|
|
Estimated future net cash flows,
before income tax
|
|
$
|
6,590,206
|
|
|
$
|
12,067,267
|
|
|
$
|
5,889,630
|
|
Standardized measure of discounted
future net cash flows, before income taxes(1)
|
|
$
|
2,690,464
|
|
|
$
|
5,311,312
|
|
|
$
|
2,438,837
|
|
Future income tax
|
|
$
|
905,384
|
|
|
$
|
1,809,228
|
|
|
$
|
823,372
|
|
Standardized measure of discounted
future net cash flows, after income tax
|
|
$
|
1,785,080
|
|
|
$
|
3,502,084
|
|
|
$
|
1,615,465
|
|
Calculated weighted average price
at December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas ($/Mcf) WY
|
|
$
|
4.50
|
|
|
$
|
8.00
|
|
|
$
|
5.46
|
|
Gas ($/Mcf) PA
|
|
$
|
5.51
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
59.95
|
|
|
$
|
60.81
|
|
|
$
|
42.80
|
|
|
|
|
(1) |
|
Management believes that the presentation of the standardized
measure of discounted future net cash flows, before income
taxes, of estimated proved reserves, discounted at 10% per
annum, may be considered a non-GAAP financial measure as defined
in Item 10(e) of
Regulation S-K,
therefore the Company has included this reconciliation of the
measure to the most directly comparable GAAP financial measure
(Standardized measure of discounted future net cash flows, after
income taxes). Management believes that the presentation of the
standardized measure of future net cash flows before income
taxes, provides useful information to investors because it is
widely used by professional analysts and sophisticated investors
in evaluating oil and gas companies. Because many factors that
are unique to each individual company may impact the amount of
future income taxes to be paid, the use of the pre-tax measure
provides greater comparability when evaluating companies. It is
relevant and useful to investors for evaluating the relative
monetary significance of the Companys oil and natural gas
properties. Further, investors may utilize the measure as a
basis for comparison of the relative size and value of the
Companys reserves to other companies. The standardized
measure of discounted future net cash flows, before income
taxes, is not a measure of financial or operating performance
under GAAP, nor is it intended to represent the current market
value of the estimated oil and natural gas reserves owned by the
Company. Standardized measure of discounted future net cash
flows, before income taxes, should not be considered in
isolation or as a substitute for the standardized measure of
discounted future net cash flows as defined under GAAP. |
27
The following table sets forth the Companys quantities of
proved reserves in China, for the years ended December 31,
2006, 2005 and 2004 as estimated by independent petroleum
engineers Ryder Scott Company. In accordance with the
Companys new field reserve booking policy,
proved reserves were booked after production has commenced. The
table summarizes the Companys proved reserves in China,
the estimated future net revenues from these reserves and the
standardized measure of discounted future net cash flows
attributable thereto at December 31, 2006, 2005 and 2004.
In accordance with Ultras three-year planning and
budgeting cycle, proved undeveloped reserves included in this
table include only economic locations that are forecast to be on
production before January 1, 2010. At December 31,
2006, proved undeveloped reserves represent 32.6% of the
Companys total proved reserves in China.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
1,301
|
|
|
|
2,577
|
|
|
|
3,231
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
2,686
|
|
|
|
2,484
|
|
|
|
4,356
|
|
Total Proved Reserves (MMcfe)
|
|
|
23,922
|
|
|
|
30,366
|
|
|
|
45,526
|
|
Estimated future net cash flows,
before income tax
|
|
$
|
111,994
|
|
|
$
|
166,931
|
|
|
$
|
137,762
|
|
Standardized measure of discounted
future net cash flows, before income taxes(1)
|
|
$
|
91,984
|
|
|
$
|
134,271
|
|
|
$
|
103,518
|
|
Future Income Tax
|
|
$
|
5,511
|
|
|
$
|
59,861
|
|
|
$
|
49,647
|
|
Standardized measure of discounted
future net cash flows, after income tax
|
|
$
|
86,473
|
|
|
$
|
74,410
|
|
|
$
|
53,871
|
|
Calculated weighted average price
at December 31, Oil ($/Bbl)
|
|
$
|
46.57
|
|
|
$
|
48.74
|
|
|
$
|
29.46
|
|
|
|
|
(1) |
|
Management believes that the presentation of the standardized
measure of discounted future net cash flows, before income
taxes, of estimated proved reserves, discounted at 10% per
annum, may be considered a non-GAAP financial measure as defined
in Item 10(e) of
Regulation S-K,
therefore the Company has included this reconciliation of the
measure to the most directly comparable GAAP financial measure
(Standardized measure of discounted future net cash flows, after
income taxes). Management believes that the presentation of the
standardized measure of future net cash flows, before income
taxes, provides useful information to investors because it is
widely used by professional analysts and sophisticated investors
in evaluating oil and gas companies. Because many factors that
are unique to each individual company may impact the amount of
future income taxes to be paid, the use of the pre-tax measure
provides greater comparability when evaluating companies. It is
relevant and useful to investors for evaluating the relative
monetary significance of the Companys oil and natural gas
properties. Further, investors may utilize the measure as a
basis for comparison of the relative size and value of the
Companys reserves to other companies. The standardized
measure of discounted future net cash flows, before income
taxes, is not a measure of financial or operating performance
under GAAP, nor is it intended to represent the current market
value of the estimated oil and natural gas reserves owned by the
Company. Standardized measure of discounted future net cash
flows, before income taxes, should not be considered in
isolation or as a substitute for the standardized measure of
discounted future net cash flows as defined under GAAP. |
28
The following table sets forth the Companys quantities of
total proved reserves both domestically and in China, for the
years-ended December 31, 2006, 2005 and 2004 as estimated
by independent petroleum engineers Netherland, Sewell &
Associates, Inc. and Ryder Scott Company. The table summarizes
the Companys total proved reserves, the estimated future
net revenues from these reserves and the standardized measure of
discounted future net cash flows attributable thereto at
December 31, 2006, 2005 and 2004. In accordance with
Ultras three-year planning and budgeting cycle, proved
undeveloped reserves included in this table include only
economic locations that are forecast to be on production before
January 1, 2010. At December 31, 2006, proved
undeveloped reserves represent 62.4% of the Companys total
proved reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
1,415,132
|
|
|
|
1,264,632
|
|
|
|
899,315
|
|
Oil (MBbl)
|
|
|
12,622
|
|
|
|
12,694
|
|
|
|
10,426
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
842,969
|
|
|
|
635,591
|
|
|
|
514,686
|
|
Oil (MBbl)
|
|
|
9,208
|
|
|
|
7,571
|
|
|
|
8,551
|
|
Total Proved Reserves (MMcfe)
|
|
|
2,389,081
|
|
|
|
2,021,813
|
|
|
|
1,527,867
|
|
Estimated future net cash flows,
before income tax
|
|
$
|
6,702,200
|
|
|
$
|
12,234,198
|
|
|
$
|
6,027,392
|
|
Standardized measure of discounted
future net cash flows, before income taxes(1)
|
|
$
|
2,782,448
|
|
|
$
|
5,445,583
|
|
|
$
|
2,542,355
|
|
Future income tax
|
|
$
|
910,895
|
|
|
$
|
1,869,089
|
|
|
$
|
873,019
|
|
Standardized measure of discounted
future net cash flows, after income tax
|
|
$
|
1,871,553
|
|
|
$
|
3,576,494
|
|
|
$
|
1,669,336
|
|
|
|
|
(1) |
|
Management believes that the presentation of the standardized
measure of discounted future net cash flows, before income
taxes, of estimated proved reserves, discounted at 10% per
annum, may be considered a non-GAAP financial measure as defined
in Item 10(e) of
Regulation S-K,
therefore the Company has included this reconciliation of the
measure to the most directly comparable GAAP financial measure
(Standardized measure of discounted future net cash flows, after
income taxes). Management believes that the presentation of the
standardized measure of future net cash flows, before income
taxes, provides useful information to investors because it is
widely used by professional analysts and sophisticated investors
in evaluating oil and gas companies. Because many factors that
are unique to each individual company may impact the amount of
future income taxes to be paid, the use of the pre-tax measure
provides greater comparability when evaluating companies. It is
relevant and useful to investors for evaluating the relative
monetary significance of the Companys oil and natural gas
properties. Further, investors may utilize the measure as a
basis for comparison of the relative size and value of the
Companys reserves to other companies. The standardized
measure of discounted future net cash flows, before income
taxes, is not a measure of financial or operating performance
under GAAP, nor is it intended to represent the current market
value of the estimated oil and natural gas reserves owned by the
Company. Standardized measure of discounted future net cash
flows, before income taxes, should not be considered in
isolation or as a substitute for the standardized measure of
discounted future net cash flows as defined under GAAP. |
29
Production
Volumes, Average Sales Prices and Average Production
Costs
The following table sets forth certain information regarding the
production volumes and average sales prices received for and
average production costs associated with the Companys sale
of oil and natural gas for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
78,395,453
|
|
|
|
61,722,349
|
|
|
|
43,667,384
|
|
Oil (Bbl) US
|
|
|
594,128
|
|
|
|
464,330
|
|
|
|
349,673
|
|
Oil (Bbl) China
|
|
|
1,603,360
|
|
|
|
1,556,280
|
|
|
|
624,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfe)
|
|
|
91,580,381
|
|
|
|
73,846,009
|
|
|
|
49,512,782
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas sales
|
|
$
|
470,324,244
|
|
|
$
|
422,091,034
|
|
|
$
|
224,207,694
|
|
Oil sales US
|
|
|
38,335,280
|
|
|
|
26,639,931
|
|
|
|
14,659,219
|
|
Oil sales China
|
|
|
84,008,059
|
|
|
|
67,762,036
|
|
|
|
20,179,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
592,667,583
|
|
|
$
|
516,493,001
|
|
|
$
|
259,046,447
|
|
Lease Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs US(a)
|
|
$
|
15,067,413
|
|
|
$
|
9,047,390
|
|
|
$
|
6,286,715
|
|
Production costs
China(a)
|
|
|
8,922,400
|
|
|
|
7,352,000
|
|
|
|
2,286,000
|
|
Severance/production
taxes US
|
|
|
57,899,339
|
|
|
|
52,689,060
|
|
|
|
28,151,661
|
|
Severance/production
taxes China
|
|
|
8,398,473
|
|
|
|
3,388,089
|
|
|
|
1,009,098
|
|
Gathering
|
|
|
19,721,269
|
|
|
|
17,125,147
|
|
|
|
13,135,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Lease Operating Expenses
|
|
$
|
110,008,894
|
|
|
$
|
89,601,686
|
|
|
$
|
50,869,283
|
|
Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf, including
hedges)
|
|
$
|
6.00
|
|
|
$
|
6.84
|
|
|
$
|
5.13
|
|
Natural Gas ($/Mcf, excluding
financial hedges)(b)
|
|
$
|
6.00
|
|
|
$
|
6.99
|
|
|
$
|
5.32
|
|
Oil ($/Bbl) US
|
|
$
|
64.52
|
|
|
$
|
57.37
|
|
|
$
|
41.92
|
|
Oil ($/Bbl) China
|
|
$
|
52.40
|
|
|
$
|
43.57
|
|
|
$
|
32.31
|
|
Operating Costs per
Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
0.26
|
|
|
$
|
0.22
|
|
|
$
|
0.17
|
|
Severance/production taxes
|
|
$
|
0.72
|
|
|
$
|
0.76
|
|
|
$
|
0.59
|
|
Gathering
|
|
$
|
0.22
|
|
|
$
|
0.23
|
|
|
$
|
0.27
|
|
DD&A
|
|
$
|
1.02
|
|
|
$
|
0.79
|
|
|
$
|
0.61
|
|
Interest
|
|
$
|
0.04
|
|
|
$
|
0.04
|
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Costs per Mcfe
|
|
$
|
2.26
|
|
|
$
|
2.04
|
|
|
$
|
1.72
|
|
|
|
|
(a) |
|
Production costs include lifting costs and remedial workover
expenses. |
|
(b) |
|
In addition to our financial hedges and to a larger extent, we
sell a portion of our production pursuant to fixed price forward
natural gas sales contracts. During 2004, 2005 and 2006, we sold
12.1 MMBtu (24%), 22.2 MMBtu (30%) and 20.4 MMBtu
(22%) pursuant to these contracts, respectively. The average
price we received for production sold pursuant to term fixed
price contracts was $4.40, $5.95 and $5.86 per MMBtu in
2004, 2005 and 2006, respectively. The average spot price (as
measured by the Inside FERC First of Month Index for
Northwest Pipeline Rocky Mountains) was $5.24, $6.96
and $5.66 per MMBtu in 2004, 2005 and 2006, respectively.
If we had sold the production we sold under the fixed price
contracts at spot market prices during these periods, we may
have received more or less than these prices, because the amount
of production |
30
|
|
|
|
|
we sell could have influenced the spot market prices in the
areas in which we produce and because we are able to select
among several market indices when selling our production. |
Productive
Wells
As of December 31, 2006, the Companys total gross and
net wells were as follows:
|
|
|
|
|
|
|
|
|
Productive Wells*
|
|
Gross Wells
|
|
|
Net Wells
|
|
|
Domestic
|
|
|
|
|
|
|
|
|
Natural Gas and Condensate
|
|
|
488.00
|
|
|
|
209.70
|
|
China
|
|
|
|
|
|
|
|
|
China Oil
|
|
|
79.00
|
|
|
|
6.89
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
567.00
|
|
|
|
216.59
|
|
|
|
|
* |
|
Productive wells are producing wells plus shut-in wells the
Company deems capable of production. A gross well is a well in
which a working interest is owned. The number of net wells
represents the sum of fractional working interests the Company
owns in gross wells. |
Oil and
Gas Acreage
As of December 31, 2006, the Company had total gross and
net developed and undeveloped oil and natural gas leasehold
acres in the United States and China as set forth below. The
Companys material undeveloped properties are not subject
to a material acreage expiry. The developed acreage is stated on
the basis of spacing units designated by state regulatory
authorities. The acreage and other additional information
concerning the Companys oil and natural gas operations are
presented in the following tables.
United
States Acreage:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Wyoming
|
|
|
15,067
|
|
|
|
6,404
|
|
|
|
132,850
|
|
|
|
73,162
|
|
Pennsylvania
|
|
|
320
|
|
|
|
320
|
|
|
|
232,691
|
|
|
|
124,271
|
|
Texas
|
|
|
80
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All States
|
|
|
15,467
|
|
|
|
6,738
|
|
|
|
365,541
|
|
|
|
197,433
|
|
As of December 31, 2006, the Company had total gross and
net developed and undeveloped oil and natural gas leasehold
acres in the Bohai Bay, China as set forth below.
Bohai
Bay Acreage:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Block 04/36
|
|
|
40,377
|
|
|
|
3,598
|
|
|
|
413,623
|
|
|
|
75,197
|
|
Block 05/36
|
|
|
15,221
|
|
|
|
1,119
|
|
|
|
218,079
|
|
|
|
50,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Bohai Acreage
|
|
|
55,598
|
|
|
|
4,717
|
|
|
|
631,702
|
|
|
|
125,573
|
|
31
Drilling
Activities
For each of the three fiscal years ended December 31, 2006,
2005 and 2004, the number of gross and net wells drilled by the
Company was as follows:
Wyoming
Green River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
80.00
|
|
|
|
38.44
|
|
|
|
60.00
|
|
|
|
23.68
|
|
|
|
34.00
|
|
|
|
14.48
|
|
Dry
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
80.00
|
|
|
|
38.44
|
|
|
|
60.00
|
|
|
|
23.68
|
|
|
|
34.00
|
|
|
|
14.48
|
|
At year end, there were 17 gross (6.66 net) additional
development wells that were either drilling or had drilling
operations suspended. This includes wells in both the Pinedale
and Jonah fields.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
44.00
|
|
|
|
19.79
|
|
|
|
18.00
|
|
|
|
8.62
|
|
|
|
32.00
|
|
|
|
14.00
|
|
Dry
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
44.00
|
|
|
|
19.79
|
|
|
|
18.00
|
|
|
|
8.62
|
|
|
|
32.00
|
|
|
|
14.00
|
|
At year end there were 29 gross (10.98 net) additional
exploratory wells that were either drilling or had drilling
operations suspended.
Pennsylvania
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
1.00
|
|
|
|
1.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Dry
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
1.00
|
|
|
|
1.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
At year end there were 2 gross (1.125 net) additional
exploratory wells that were either drilling or had drilling
operations suspended.
Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Dry
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
1.00
|
|
|
|
0.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
1.00
|
|
|
|
0.73
|
|
32
China
Bohai Bay
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
26.00
|
|
|
|
2.16
|
|
|
|
17.00
|
|
|
|
1.52
|
|
|
|
36.00
|
|
|
|
3.21
|
|
Dry
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
26.00
|
|
|
|
2.16
|
|
|
|
17.00
|
|
|
|
1.52
|
|
|
|
36.00
|
|
|
|
3.21
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive and Successful
Appraisal*
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Dry
|
|
|
1.00
|
|
|
|
0.23
|
|
|
|
1.00
|
|
|
|
0.18
|
|
|
|
1.00
|
|
|
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1.00
|
|
|
|
0.23
|
|
|
|
1.00
|
|
|
|
0.18
|
|
|
|
1.00
|
|
|
|
0.18
|
|
|
|
|
* |
|
A successful appraisal well is a well that is drilled into a
formation shown to be productive of oil or natural gas by an
earlier well for the purpose of obtaining more information about
the reservoir. |
|
|
Item 3.
|
Legal
Proceedings.
|
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such
pending or threatened litigation is not likely to have a
material adverse effect on the Companys financial position
or results of operations.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders.
|
No matters were submitted to a vote of the Companys
security holders during the fourth quarter of the fiscal year
ended December 31, 2006.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
The common shares of the Company have been listed and posted for
trading on the American Stock Exchange (AMEX) since
January 17, 2001 under the symbol UPL. The
following table sets forth the high and low
intra-day
sales prices on the AMEX for 2006 and 2005 as reported by the
exchange. The prices are adjusted for a 2 for 1 stock split
effective May 10, 2005.
AMERICAN
STOCK EXCHANGE (US$)
|
|
|
|
|
|
|
|
|
2006
|
|
High
|
|
|
Low
|
|
|
First Quarter
|
|
$
|
70.00
|
|
|
$
|
49.65
|
|
Second Quarter
|
|
$
|
68.60
|
|
|
$
|
44.40
|
|
Third Quarter
|
|
$
|
61.84
|
|
|
$
|
41.80
|
|
Fourth Quarter
|
|
$
|
56.80
|
|
|
$
|
44.60
|
|
AMERICAN
STOCK EXCHANGE (US$)
|
|
|
|
|
|
|
|
|
2005
|
|
High
|
|
|
Low
|
|
|
First Quarter
|
|
$
|
29.17
|
|
|
$
|
22.20
|
|
Second Quarter
|
|
$
|
30.50
|
|
|
$
|
21.48
|
|
Third Quarter
|
|
$
|
57.89
|
|
|
$
|
30.36
|
|
Fourth Quarter
|
|
$
|
60.32
|
|
|
$
|
45.10
|
|
33
On February 15, 2007, the last reported sales price of the
common stock on the AMEX was $51.55 per share. As of
February 15, 2007 there were approximately 447 holders of
record of the common stock.
The Company has not declared or paid and does not anticipate
declaring or paying any dividends on its common stock in the
near future. The Company intends to retain its cash flow from
operations for the future operation and development of its
business. In addition, the Companys current credit
facility limits payment of dividends on its common stock.
On May 17, 2006, the Company announced that its Board of
Directors authorized a share repurchase program for up to an
aggregate $1 billion of the Companys outstanding
common stock which has been and will be funded by cash on hand
and the Companys senior credit facility. Pursuant to this
authorization, the Company has commenced an initial program to
purchase up to $250.0 million in shares of its common stock
through open market transactions or privately negotiated
transactions. At December 31, 2006, the Company had
repurchased 3,969,532 shares of its common stock for an
aggregate $197.6 million at a weighted average price of
$49.77 per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
|
|
|
Number (or
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate Dollar
|
|
|
|
|
|
|
|
|
|
|
|
|
Value) of Shares
|
|
|
|
|
|
|
|
|
|
Total Number of Shares
|
|
|
that may yet be
|
|
|
|
Total Number
|
|
|
Average Price
|
|
|
Purchased as Part of
|
|
|
Purchased
|
|
|
|
of Shares
|
|
|
Paid
|
|
|
Publicly Announced
|
|
|
Under the Plans or
|
|
Period
|
|
Purchased
|
|
|
Per Share
|
|
|
Plans or Programs
|
|
|
Programs
|
|
|
May 1 - May 31, 2006
|
|
|
283,417
|
|
|
$
|
56.29
|
|
|
|
283,417
|
|
|
$
|
984 million
|
|
June 1 - June 30, 2006
|
|
|
1,147,157
|
|
|
$
|
50.03
|
|
|
|
1,147,157
|
|
|
$
|
927 million
|
|
July 1 - July 31, 2006
|
|
|
572,858
|
|
|
$
|
53.14
|
|
|
|
572,858
|
|
|
$
|
896 million
|
|
Aug 1 - Aug 31, 2006
|
|
|
278,900
|
|
|
$
|
53.02
|
|
|
|
278,900
|
|
|
$
|
881 million
|
|
Sept 1 - Sept 30, 2006
|
|
|
1,198,700
|
|
|
$
|
46.50
|
|
|
|
1,198,700
|
|
|
$
|
826 million
|
|
Oct 1 - Oct 31, 2006
|
|
|
488,500
|
|
|
$
|
47.56
|
|
|
|
488,500
|
|
|
$
|
802 million
|
|
Nov 1 - Nov 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
802 million
|
|
Dec 1 - Dec 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
802 million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
3,969,532
|
|
|
$
|
49.77
|
|
|
|
3,969,532
|
|
|
$
|
802 million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Item 6.
|
Selected
Financial Data.
|
The selected consolidated financial information presented below
for the years ended December 31, 2006, 2005, 2004, 2003,
and 2002 is derived from the Consolidated Financial Statements
of the Company. The earnings per share information (Basic income
per common share and Diluted income per common share) have been
updated to reflect the 2 for 1 stock split on May 10, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
470,324
|
|
|
$
|
422,091
|
|
|
$
|
224,208
|
|
|
$
|
114,841
|
|
|
$
|
38,503
|
|
Oil sales
|
|
|
122,343
|
|
|
|
94,402
|
|
|
|
34,839
|
|
|
|
6,740
|
|
|
|
3,839
|
|
Interest and other
|
|
|
1,943
|
|
|
|
612
|
|
|
|
91
|
|
|
|
37
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
594,610
|
|
|
$
|
517,105
|
|
|
$
|
259,138
|
|
|
$
|
121,618
|
|
|
$
|
42,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses and taxes
|
|
|
110,009
|
|
|
|
89,602
|
|
|
|
50,869
|
|
|
|
25,224
|
|
|
|
11,411
|
|
Depreciation, depletion and
amortization
|
|
|
93,499
|
|
|
|
58,103
|
|
|
|
30,249
|
|
|
|
16,216
|
|
|
|
9,712
|
|
General and administrative
|
|
|
13,378
|
|
|
|
11,484
|
|
|
|
6,152
|
|
|
|
5,733
|
|
|
|
4,199
|
|
Stock compensation
|
|
|
1,557
|
|
|
|
2,859
|
|
|
|
924
|
|
|
|
1,018
|
|
|
|
1,211
|
|
Interest
|
|
|
3,909
|
|
|
|
3,286
|
|
|
|
3,783
|
|
|
|
2,851
|
|
|
|
2,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
222,352
|
|
|
|
165,333
|
|
|
|
91,977
|
|
|
|
51,042
|
|
|
|
29,224
|
|
Income before income taxes
|
|
|
372,258
|
|
|
|
351,772
|
|
|
|
167,160
|
|
|
|
70,576
|
|
|
|
13,141
|
|
Income tax provision
|
|
|
141,063
|
|
|
|
123,472
|
|
|
|
58,010
|
|
|
|
25,254
|
|
|
|
5,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
231,195
|
|
|
$
|
228,300
|
|
|
$
|
109,150
|
|
|
$
|
45,323
|
|
|
$
|
8,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income per common share
|
|
$
|
1.50
|
|
|
$
|
1.49
|
|
|
$
|
0.73
|
|
|
$
|
0.31
|
|
|
$
|
0.05
|
|
Diluted income per common share
|
|
$
|
1.43
|
|
|
$
|
1.41
|
|
|
$
|
0.68
|
|
|
$
|
0.29
|
|
|
$
|
0.05
|
|
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
435,857
|
|
|
$
|
414,353
|
|
|
$
|
175,343
|
|
|
$
|
90,051
|
|
|
$
|
21,490
|
|
Investing activities
|
|
|
(454,840
|
)
|
|
|
(306,547
|
)
|
|
|
(165,014
|
)
|
|
|
(103,622
|
)
|
|
|
(64,360
|
)
|
Financing activities
|
|
|
(10,705
|
)
|
|
|
(80,344
|
)
|
|
|
4,770
|
|
|
|
13,988
|
|
|
|
42,908
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
14,707
|
|
|
$
|
44,395
|
|
|
$
|
16,933
|
|
|
$
|
1,834
|
|
|
$
|
1,418
|
|
Working capital (deficit)
|
|
|
(41,429
|
)
|
|
|
42,713
|
|
|
|
(9,969
|
)
|
|
|
(22,057
|
)
|
|
|
(4,415
|
)
|
Oil and gas properties
|
|
|
1,119,368
|
|
|
|
702,663
|
|
|
|
474,634
|
|
|
|
307,864
|
|
|
|
207,362
|
|
Total assets
|
|
|
1,257,769
|
|
|
|
847,266
|
|
|
|
537,186
|
|
|
|
345,770
|
|
|
|
221,874
|
|
Total long-term debt
|
|
|
165,000
|
|
|
|
|
|
|
|
102,000
|
|
|
|
99,000
|
|
|
|
86,000
|
|
Other long-term obligations
|
|
|
26,573
|
|
|
|
20,577
|
|
|
|
9,735
|
|
|
|
5,120
|
|
|
|
3,859
|
|
Deferred income taxes, net
|
|
|
250,925
|
|
|
|
155,746
|
|
|
|
85,035
|
|
|
|
33,446
|
|
|
|
10,033
|
|
Total shareholders equity
|
|
|
629,005
|
|
|
|
571,201
|
|
|
|
267,992
|
|
|
|
149,453
|
|
|
|
104,067
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the consolidated financial statements and related notes of
the Company. Except as otherwise
35
indicated all amounts are expressed in U.S. dollars. We
have one operating segment, natural gas and oil exploration and
development with two geographical segments, the United States
and China.
The Company currently generates the majority of its revenue,
earnings and cash flow from the production and sales of natural
gas and oil from its property in southwest Wyoming. The price of
natural gas in the southwest Wyoming region is a critical factor
to the Companys business. The price of natural gas in
southwest Wyoming historically has been volatile. The average
annual realizations for the period
2002-2006
have ranged from $2.33 to $8.64 per Mcf. This volatility could
be detrimental to the Companys financial performance. The
Company seeks to limit the impact of this volatility on its
results by entering into forward sales and derivative contracts
for natural gas in southwest Wyoming. The average realization
for the Companys natural gas during calendar 2006 was
$6.00 per Mcf, basis Opal, Wyoming, including the effect of
hedges. For the quarter ended December 31, 2006, the
average realization for the Companys natural gas was
$5.62 per Mcf, basis Opal, Wyoming, including the effect of
hedges.
On July 18, 2004 the Company initiated production at the
first two fields of the nine fields discovered on its oil
properties offshore Bohai Bay, China. Production from these
fields is characterized as heavy, sweet crude. The Company sold
its first cargo of oil in September 2004. During the
twelve-month period ended December 31, 2006, the Company
sold 1,603,360 barrels of its Chinese oil production at a
price based on the official ICP posting for Duri field crude,
less a discount for location and quality differences. The
majority of these sales were made to an affiliate of CNOOC at an
average price of $52.40 USD per barrel for the year ended
December 31, 2006. For the quarter ended December 31,
2006, the Company sold 396,430 barrels of its Chinese crude
for an average price of $39.53 USD per barrel. There can and
will be differences in timing between the sale of the
Companys crude oil cargos and the Companys pro-rata
share of production. As a result of these timing differences,
the Company may, from time to time, carry inventories or
imbalances of crude oil. As of February 16, 2007, the Duri
price was approximately $47.56 USD (before discount) per barrel.
The Company expects to sell at least one cargo of its Chinese
crude oil production approximately every two months during 2007.
The Company has the right to export and sell its crude at market
prices into the international markets. Other markets for the
Companys Chinese oil may potentially be developed in South
Korea, Japan, Singapore or other countries.
The Company has grown its natural gas and oil production
significantly over the past five years and management believes
it has the ability to continue growing production by drilling
already identified locations on its leases in Wyoming and by
bringing into production the already discovered oil fields in
China. The Company delivered 30% production growth on an Mcfe
basis during the quarter ended December 31, 2006 as
compared to the same quarter in 2005 and 24% production growth
for the year-ended December 31, 2006 compared to the same
period in 2005. Management expects to deliver additional
production growth during 2007 by drilling and bringing into
production additional wells in Wyoming and bringing into
production additional fields in China.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Production Bcfe
|
|
|
91.6
|
|
|
|
73.8
|
|
|
|
49.5
|
|
|
|
28.9
|
|
The Company conducts operations in both the United States and
China. Separate cost centers are maintained for each country in
which the Company has operations. Substantially all of the oil
and natural gas activities are conducted jointly with others
and, accordingly, amounts presented reflect only the
Companys proportionate interest in such activities.
Inflation has not had a material impact on the Companys
results of operations and is not expected to have a material
impact on the Companys results of operations in the future.
Critical
Accounting Policies
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. Generally Accepted Accounting Principles
(GAAP). In addition, application of GAAP requires
the use of estimates, judgments and assumptions that affect the
reported amounts of assets and liabilities as of the date of the
financial statements as well as the revenues and expenses
reported during the period. Changes in these estimates,
judgments and assumptions will occur as a result of future
events, and, accordingly, actual results could differ from
amounts estimated. Set forth below is a discussion of the
critical accounting policies used in the preparation of our
financial
36
statements which we believe involve the most complex or
subjective decisions or assessments. These policies relate to
estimates of volumes of oil and natural gas reserves used in
calculating depletion, the amount of standardized measure used
in computing the ceiling test limitations and the amount of
abandonment obligations used in such calculations. Assumptions,
judgments and estimates are also required in determining
impairments of undeveloped properties and the valuation of
deferred tax assets.
Oil and Gas Reserves. The term proved reserves
is defined by the SEC in
Rule 4-10(a)
of
Regulation S-X
under the Securities Act of 1933. In general, proved reserves
are the estimated quantities of natural gas, crude oil,
condensate and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty can be
recovered in future years from known reservoirs under existing
economic and operating conditions, i.e. prices and costs at the
date of the estimate. Prices include consideration of changes in
existing prices provided by contractual arrangements, but not
escalated based on future economic conditions.
Estimates of proved crude oil and natural gas reserves
significantly affect the Companys depreciation, depletion
and amortization (DD&A) expense. For example, if
estimates of proved reserves decline, the Companys
DD&A rate will increase, resulting in a decrease in net
income. A decline in estimates of proved reserves may result
from lower prices, evaluation of additional operating history,
mechanical problems on our wells and catastrophic events such as
explosions, hurricanes and floods. Lower prices also make it
uneconomical to drill wells or produce from fields with high
operating costs.
Our proved reserves are a function of many assumptions, all of
which could deviate materially from actual results. As a result,
our estimates of proved reserves could vary over time, and could
vary from actual results.
Full Cost Method of Accounting. The accounting
for and disclosure of oil and gas producing activities requires
that we choose between GAAP alternatives. The Company uses the
full cost method of accounting for its oil and natural gas
operations. Under this method, separate cost centers are
maintained for each country in which the Company incurs costs.
All costs incurred in the acquisition, exploration and
development of properties (including costs of surrendered and
abandoned leaseholds, delay lease rentals, dry holes and
overhead related to exploration and development activities) are
capitalized. The sum of net capitalized costs and estimated
future development costs of oil and natural gas properties for
each full cost center are depleted using the
units-of-production
method. Changes in estimates of proved reserves, future
development costs or asset retirement obligations are accounted
for prospectively in our depletion calculation.
Investments in unproved properties are not depleted pending the
determination of the existence of proved reserves. Unproved
properties are assessed periodically to ascertain whether
impairment has occurred. Unproved properties whose costs are
individually significant are assessed individually by
considering the primary lease terms of the properties, the
holding period of the properties, and geographic and geologic
data obtained relating to the properties. Where it is not
practicable to individually assess the amount of impairment of
properties for which costs are not individually significant,
such properties are grouped for purposes of assessing
impairment. The amount of impairment assessed is added to the
costs to be amortized in the appropriate full cost pool.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter on a
country-by-country
basis. The ceiling limits such pooled costs to the aggregate of
the after-tax, present value, discounted at 10%, of future net
revenues attributable to proved reserves, known as the
standardized measure, plus the lower of cost or market value of
unproved properties less any associated tax effects. If such
capitalized costs exceed the ceiling, the Company will record a
write-down to the extent of such excess as a non-cash charge to
earnings. Any such write-down will reduce earnings in the period
of occurrence and result in lower DD&A expense in future
periods. A write-down may not be reversed in future periods,
even though higher oil and natural gas prices may subsequently
increase the ceiling.
The Company did not have any write-downs related to the full
cost ceiling limitation in 2006, 2005, or 2004. As of
December 31, 2006, the ceiling limitation exceeded the
carrying value of the Companys oil and natural gas
properties. Estimates of standardized measure at
December 31, 2006 were based on realized natural gas prices
which averaged $4.50 per Mcf in Wyoming and $5.51 per
Mcf in Pennsylvania and on realized liquids prices which
averaged $59.95 per barrel in the U.S. In China,
estimates of discounted future net cash flows on crude oil were
based on a net realized price of $46.57 per barrel. A
reduction in oil and natural gas prices
and/or
estimated
37
quantities of oil and natural gas reserves would reduce the
ceiling limitation and could result in a ceiling test write-down.
Asset Retirement Obligation. The
Companys asset retirement obligations (ARO)
consist primarily of estimated costs of dismantlement, removal,
site reclamation and similar activities associated with its oil
and natural gas properties. Statement of Financial Accounting
Standard No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143) requires
that the discounted fair value of a liability for an ARO be
recognized in the period in which it is incurred with the
associated asset retirement cost capitalized as part of the
carrying cost of the oil and natural gas asset. The recognition
of an ARO requires that management make numerous estimates,
assumptions and judgments regarding such factors as the
existence of a legal obligation for an ARO, estimated
probabilities, amounts and timing of settlements; the
credit-adjusted, risk-free rate to be used; inflation rates, and
future advances in technology. In periods subsequent to initial
measurement of the ARO, the Company must recognize
period-to-period
changes in the liability resulting from the passage of time and
revisions to either the timing or the amount of the original
estimate of undiscounted cash flows. Increases in the ARO
liability due to passage of time impact net income as accretion
expense. The related capitalized cost, including revisions
thereto, is charged to expense through DD&A.
Entitlements Method of Accounting for Oil and Natural Gas
Sales. The Company generally sells natural gas,
condensate and crude oil under both long-term and short-term
agreements at prevailing market prices and under multi-year
contracts that provide for a fixed price of oil and natural gas.
The Company recognizes revenues when the oil and natural gas is
delivered, which occurs when the customer has taken title and
has assumed the risks and rewards of ownership, prices are fixed
or determinable and collectibility is reasonably assured. The
Company accounts for oil and natural gas sales using the
entitlements method. Under the entitlements method,
revenue is recorded based upon the Companys ownership
share of volumes sold, regardless of whether it has taken its
ownership share of such volumes. The Company records a
receivable or a liability to the extent it receives less or more
than its share of the volumes and related revenue.
Make-up
provisions and ultimate settlements of volume imbalances are
generally governed by agreements between the Company and its
partners with respect to specific properties or, in the absence
of such agreements, through negotiation. The value of volumes
over- or under-produced can change based on changes in commodity
prices. The Company prefers the entitlements method of
accounting for oil and natural gas sales because it allows for
recognition of revenue based on its actual share of jointly
owned production, results in better matching of revenue with
related operating expenses, and provides balance sheet
recognition of the estimated value of product imbalances.
Valuation of Deferred Tax Assets. The Company
uses the asset and liability method of accounting for income
taxes. Under this method, future income tax assets and
liabilities are determined based on differences between the
financial statement carrying values and their respective income
tax basis (temporary differences).
To assess the realization of deferred tax assets, management
considers whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon
the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities,
projected future taxable income and tax planning strategies in
making this assessment. As of December 31, 2006, the
Company had net deferred tax assets totaling $8.3 million
which management considers is more likely than not to be
realized.
Commodity Derivative Instruments and Hedging
Activities. The Company may, from time to time,
enter into commodity derivative contracts
and/or
fixed-price physical contracts to manage its exposure to oil and
natural gas price volatility. The Company has, in the past,
primarily utilized fixed price forward sales of physical gas
when it hedges some portion of its Wyoming natural gas
production. These transactions are generally placed with major
financial institutions or with counterparties of high credit
quality that present minimal credit risks to the Company. The
Company may also secure payments under these types of
transactions by requiring the counterparty to provide letter(s)
of credit. On a less frequent basis, the Company may enter into
commodity derivative contracts to manage price volatility. To
the extent that it does enter into such derivative transactions,
the Company expects that the oil and natural gas reference
prices of these commodity derivatives contracts will be based
upon crude oil
and/or
natural gas futures contracts which, when adjusted for location
basis differentials, will have a high degree of
38
historical correlation with actual prices the Company receives.
Under Statement of Financial Accounting Standard No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133), all
derivative instruments are recorded on the balance sheet at fair
value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. For qualifying cash flow hedges,
the gain or loss on the derivative is deferred in Accumulated
Other Comprehensive Income (Loss) to the extent the hedge is
effective. For qualifying fair value hedges, the gain or loss on
the derivative is offset by the related results of the hedged
item in the income statement. Gains and losses on hedging
instruments included in Accumulated Other Comprehensive Income
(Loss) on the balance sheet are reclassified to Oil and Natural
Gas Sales Revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for hedge
accounting treatment are recorded as derivative assets and
liabilities at market value in the consolidated balance sheet,
and the associated unrealized gains and losses are recorded as
current expense or income in the consolidated statement of
operations. The Company currently does not have any derivative
contracts related to the marketing of its natural gas or oil
production in effect, the last one having expired on
December 31, 2005.
Legal, Environmental and Other
Contingencies. A provision for legal,
environmental and other contingencies is charged to expense when
the loss is probable and the cost can be reasonably estimated.
Determining when expenses should be recorded for these
contingencies and the appropriate amounts for accrual is a
complex estimation process that includes the subjective judgment
of management. In many cases, managements judgment is
based on interpretation of laws and regulations, which can be
interpreted differently by regulators
and/or
courts of law. The Companys management closely monitors
known and potential legal, environmental and other contingencies
and periodically determines when the Company should record
losses for these items based on information available to the
Company.
Share-Based Payment Arrangements. On
January 1, 2006, the Company adopted Statement of Financial
Accounting Standards No. 123 (revised 2004),
Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors
including employee stock options based on estimated fair values.
SFAS No. 123R supersedes the Companys previous
accounting under Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to
Employees (APB No. 25) for periods
beginning in fiscal year 2006. In March 2005, the SEC issued
Staff Accounting Bulletin No. 107
(SAB 107) relating to SFAS No. 123R.
The Company has applied the provisions of SAB 107 in its
adoption of SFAS No. 123R.
The Company adopted SFAS No. 123R using the modified
prospective transition method, which requires the application of
the accounting standard as of January 1, 2006, the first
day of the Companys fiscal year 2006. The Companys
Consolidated Financial Statements as of and for the year-ended
December 31, 2006 reflect the impact of
SFAS No. 123R. In accordance with the modified
prospective transition method, the Companys Consolidated
Financial Statements for prior periods have not been restated to
reflect, and do not include, the impact of
SFAS No. 123R. Share-based compensation expense
recognized under SFAS No. 123R for the year-ended
December 31, 2006 was $1,156,767, which consisted of
stock-based compensation expense related to employee stock
options. There was no stock-based compensation expense related
to employee stock options recognized during the year-ended
December 31, 2005. (See Note 1(l) for additional
information.)
SFAS No. 123R requires companies to estimate the fair
value of share-based payment awards on the date of grant using
an option-pricing model. The value of the portion of the award
that is ultimately expected to vest is recognized as expense
over the requisite service periods in the Companys
Consolidated Statement of Operations. Prior to the adoption of
SFAS No. 123R, the Company accounted for stock-based
awards to employees and directors using the intrinsic value
method in accordance with APB No. 25 as allowed under
Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation
(SFAS No. 123). Under the intrinsic value
method, no stock-based compensation expense had been recognized
in the Companys Consolidated Statement of Operations
because the exercise price of the Companys stock options
granted to employees and directors equaled the fair market value
of the underlying stock at the date of grant.
Under SFAS No. 123R, share-based compensation expense
recognized during the period is based on the value of the
portion of share-based payment awards that is ultimately
expected to vest during the period. Share-based compensation
expense recognized in the Companys Consolidated Statement
of Operations for the year-ended
39
December 31, 2006 includes compensation expense for
share-based payment awards granted subsequent to January 1,
2006 based on the grant date fair value estimated in accordance
with the provisions of SFAS No. 123R. As of
December 31, 2005, all stock options granted to date had
fully vested. Compensation expense attributable to awards
granted subsequent to January 1, 2006 is recognized using
the straight-line method. As share-based compensation expense
recognized in the Consolidated Statements of Operations for the
year-ended December 31, 2006 is based on awards ultimately
expected to vest, it has been reduced for estimated forfeitures.
SFAS No. 123R requires forfeitures to be estimated at
the time of grant and revised, if necessary, in subsequent
periods if actual forfeitures differ from those estimates. In
the Companys pro forma information required under
SFAS No. 123 for the periods prior to January 1,
2006, the Company accounted for forfeitures as they occurred.
Under SFAS No. 123 (and APB No. 25), the Company
utilized a Black-Scholes option pricing model to measure the
fair value of stock options granted to employees. For additional
information, see Note 6. The Companys determination
of fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to, the Companys expected stock price
volatility over the term of the awards, and actual and projected
employee stock option exercise behaviors.
Option-pricing models were developed for use in estimating the
value of traded options that have no vesting or hedging
restrictions and are fully transferable. Because (1) the
Companys employee stock options have certain
characteristics that are significantly different from traded
options, and (2) changes in the subjective assumptions can
materially affect the estimated value, in managements
opinion, the existing valuation models may not provide an
accurate measure of the fair value of the Companys
employee stock options. Although the fair value of employee
stock options is determined in accordance with
SFAS No. 123R and SAB 107 using a Black-Scholes
option-pricing model, that value may not be indicative of the
fair value observed in a willing buyer/willing seller market
transaction. The Company is responsible for determining the
assumptions used in estimating the fair value of its share-based
payment awards.
Recently issued accounting pronouncements. As
of January 1, 2006, the Company adopted
SFAS No. 154, Accounting for Changes and Error
Corrections, a replacement of APB Opinion No. 20 and
SFAS No. 3 (SFAS No. 154).
SFAS No. 154 requires retrospective application of
voluntary changes in accounting principles, unless it is
impracticable. The adoption of this standard did not have a
material impact on consolidated results of operations, financial
position or liquidity.
In July 2006, the Financial Accounting Standards Board
(FASB) issued Interpretation No. 48
(FIN No. 48), Accounting for
Uncertainty in Income Taxes, an Interpretation of
SFAS No. 109, which clarifies the accounting for
uncertainty in income taxes in accordance with
SFAS No. 109, Accounting for Income Taxes.
FIN No. 48 prescribes a recognition threshold and
measurement attribute for the measurement and financial
statement recognition of a tax position taken or expected to be
taken in a tax return. The interpretation also provides guidance
on de-recognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition. Upon
adoption, FIN No. 48 will be applied to all tax
positions in those tax years for which the tax return statute of
limitations is open. The cumulative effect of the initial
application will be reported as an increase or decrease to
retained earnings as of the beginning of the period in which it
is adopted. For the Company, the provisions of
FIN No. 48 are effective January 1, 2007. The
Company has not completed its evaluation of the impact
FIN No. 48 will have when adopted. However, the
Company currently believes that its implementation will not have
a material impact on consolidated results of operations,
financial position or liquidity.
In September 2006, the SEC staff issued Staff Accounting
Bulletin 108, Financial Statements
Considering the Effects of Prior Year Misstatements When
Quantifying Misstatements in Current Year Financial
Statements (SAB 108). SAB 108
addresses how a registrant should quantify the effect of an
error on the financial statements and concludes that a dual
approach should be used to compute the amount of a misstatement.
Specifically, the amount should be computed using both the
rollover (current year income statement perspective)
and iron curtain (year-end balance sheet
perspective) methods. For the Company, the provisions of
SAB 108 were effective January 1, 2006. The
implementation of SAB 108 did not have a material impact on
the Companys consolidated results of operations, financial
position or liquidity.
40
Results
of Operations Year Ended December 31, 2006
Compared to Year Ended December 31, 2005
Oil and natural gas revenues increased 15% to
$592.7 million for the year ended December 31, 2006
from $516.5 million for the same period in 2005. This
increase was attributable to an increase in the Companys
production volumes and partially offset by lower prices
received. During 2006, the Companys production increased
to 78.4 Bcf of natural gas and 594.1 thousand barrels of
condensate in Wyoming and 1.6 million barrels of crude oil
in China, up from 2005 levels of 61.7 Bcf of natural gas
and 464.3 thousand barrels of condensate in Wyoming and
1.6 million barrels of crude oil in China. This 24%
increase on an Mcfe basis was attributable to the Companys
successful drilling activities during 2006 and 2005 in Wyoming
and in China. During the year ended December 31, 2006, the
average product prices received were $6.00 per Mcf
including the effects of hedging and $64.52 per barrel of
condensate in Wyoming and $52.40 per barrel for crude oil
in China, compared to $6.84 per Mcf and $57.37 per
barrel of condensate in Wyoming and $43.57 per barrel of
crude oil in China for the same period in 2005.
In Wyoming, direct lease operating costs increased to
$15.1 million in 2006 from $9.0 million in 2005 due to
higher production volumes along with increased water disposal
costs. On a unit of production basis, LOE costs increased to
$0.18 per Mcfe for the year-ended December 31, 2006 as
compared to $0.14 per Mcfe during the same period in 2005.
Production taxes in Wyoming during the year-ended
December 31, 2006 were $57.9 million compared to
$52.7 million in 2005, or $0.71 per Mcfe in 2006,
compared to $0.82 per Mcfe in 2005. Production taxes in
Wyoming are calculated based on a percentage of revenue from
production. Therefore, lower prices received decreased
production taxes on a per unit basis. Gathering fees in Wyoming
for the year ended December 31, 2006 increased to
$19.7 million in 2006 from $17.1 million in 2005
largely as a result of increased production volumes partially
offset by revised gathering and processing agreements. The per
unit gathering fees decreased to $0.24 per Mcfe in 2006 as
compared to $0.27 per Mcfe in 2005 as a result of increased
production volumes during 2006 as well as reduced fees as a
result of revised gathering and processing agreements during
2006.
In the United States, DD&A expenses increased to
$79.7 million during the year ended December 31, 2006
from $48.5 million for the same period in 2005. This
increase was attributable to increased production volumes and a
higher depletion rate due to forecasted increased future
development costs. On a unit basis, DD&A expense in the
United States increased to $0.97 per Mcfe in 2006 from
$0.75 per Mcfe in 2005.
In China, production costs were $8.9 million in 2006, or
$0.93 per Mcfe or $5.58 per BOE, compared with
$7.4 million in 2005, or $0.79 per Mcfe or $4.74 per
BOE. The increase in production costs was attributable to
increased production during 2006 along with one-time costs
associated with new fields coming on production. Severance taxes
in China during the year ended December 31, 2006 were
$8.4 million compared to $3.4 million in 2005, or
$0.87 per Mcfe ($5.22 per BOE) in 2006 compared to
$0.36 per Mcfe ($2.18 per BOE) in 2005. The increase
in severance taxes was largely attributable to $3.6 million
related to the Petroleum Special Profits Tax levied by the
Chinese government beginning in March 2006. In addition, in
November 2006, the Chinese government introduced an export levy
on produced volumes exported out of the country. The Company
incurred $0.5 million during the year ended
December 31, 2006 relating to the export levy.
In China, DD&A expense was $13.8 million or
$1.44 per Mcfe ($8.64 per BOE) in 2006 compared to
$9.6 million, or $1.03 per Mcfe ($6.20 per BOE)
in 2005. The increase in DD&A was primarily attributable to
higher DD&A rates as a result of costs being allocated from
unevaluated properties to the full cost pool as well as
increased production volumes.
General and administrative expenses increased slightly to
$14.9 million during the twelve months ended
December 31, 2006 as compared to $14.3 million during
the same period in 2005. On a per unit basis, general and
administrative expenses decreased to $0.16 per Mcfe during
the year-ended December 31, 2006 as compared to
$0.19 per Mcfe for the same period in 2005.
Interest expense increased to $3.9 million in 2006 from
$3.3 million in 2005. This increase was largely
attributable to the increase in borrowings under the senior
credit facility during 2006.
The income tax provision increased to $141.1 million in
2006 from $123.5 million in 2005. This increase was
primarily attributable to increased earnings as well as the
withholding tax paid in association with our share repurchase
program (see Note 8). The Company recognized
$35.4 million in current tax expense during 2006, of which,
$18.9 million was payable to the Chinese taxing
authorities. The Company incurred a liability for current
41
payment of income taxes of $3.6 million for the period
ending December 31, 2005. During the year-ended
December 31, 2006, the Company incurred $10.4 million
in withholding tax attributable to the Companys share
repurchase program. In conjunction with the share repurchase
program, a stock distribution to Ultra Petroleum from Ultra
Resources is treated as a dividend for U.S. tax purposes to
the extent of earnings and profits of UP Energy and Ultra
Resources. U.S. tax rules, including rules under the
U.S.-Canada
Income Tax Treaty, require a 5% withholding tax when a
U.S. corporation distributes a dividend to its sole
corporate Canadian shareholder.
The following table provides a detail of the income tax
provision for the years ended December 31, 2006 and 2005.
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|
For the Year-Ended December 31,
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|
2006
|
|
|
2005
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|
|
|
$
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|
|
Rate
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|
|
$
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|
|
Rate
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|
|
Current:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
China
|
|
$
|
18,941,127
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|
|
|
5.1
|
%
|
|
$
|
3,564,990
|
|
|
|
1.0
|
%
|
United States
|
|
|
16,543,461
|
|
|
|
4.4
|
%
|
|
$
|
50,636,118
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|
|
|
14.4
|
%
|
Withholding taxes
stock distribution
|
|
|
10,400,543
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|
|
|
2.8
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%
|
|
|
|
|
|
|
0.0
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%
|
Deferred tax expense
|
|
|
95,178,288
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|
|
|
25.6
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%
|
|
|
69,270,977
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|
|
|
19.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Tax Provision
|
|
$
|
141,063,419
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|
|
|
37.9
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%
|
|
$
|
123,472,085
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|
|
|
35.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred taxes payable
|
|
$
|
(95,178,288
|
)
|
|
|
(25.6
|
)%
|
|
$
|
(69,270,977
|
)
|
|
|
(19.7
|
)%
|
Stock option benefits
|
|
|
(10,502,522
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)
|
|
|
(2.8
|
)%
|
|
|
(50,636,118
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)
|
|
|
(14.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current net cash tax liability
|
|
$
|
35,382,609
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|
|
|
9.5
|
%
|
|
$
|
3,564,990
|
|
|
|
1.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations Year Ended December 31, 2005
Compared to Year Ended December 31, 2004
Oil and natural gas revenues increased to $516.5 million
for the year ended December 31, 2005 from
$259.0 million for the same period in 2004. This increase
was attributable to an increase in both the Companys
production volumes and prices received for that production
coupled with a full years production from the China asset.
During 2005, the Companys production increased to
61.7 Bcf of natural gas and 464.3 thousand barrels of
condensate in Wyoming and 1.6 million barrels of crude oil
in China, up from 2004 levels of 43.7 Bcf of natural gas
and 349.7 thousand barrels of condensate in Wyoming and 624.6
thousand barrels of crude oil in China. This 49% increase on an
Mcfe basis was attributable to the Companys successful
drilling activities during 2005 and 2004 in Wyoming and
initiation of production in China during July 2004. During the
year ended December 31, 2005, the average product prices
received were $6.84 per Mcf and $57.37 per barrel of
condensate in Wyoming and $43.54 per barrel for crude oil
in China, compared to $5.13 per Mcf and $41.92 per barrel
of condensate in Wyoming and $32.31 per barrel of crude oil
in China for the same period in 2004.
In Wyoming, direct lease operating costs increased to
$9.0 million in 2005 from $6.3 million in 2004 due
largely to higher production volumes. On a unit of production
basis, LOE costs were flat at $0.14 per Mcfe in 2005 when
compared to 2004. Production taxes in Wyoming during the year
ended December 31, 2005 were $52.7 million compared to
$28.2 million in 2004, or $0.82 per Mcfe in 2005,
compared to $0.62 per Mcfe in 2004. Production taxes in
Wyoming are calculated based on a percentage of revenue from
production. Therefore, higher prices received increased
production taxes on a per unit basis. Gathering fees in Wyoming
for the year ended December 31, 2005 increased to
$17.1 million, or $0.27 per Mcfe in 2005 from
$13.1 million, or $0.29 per Mcfe, in 2004 as a result
of higher production volumes.
In Wyoming, DD&A expenses increased to $48.5 million
during the year ended December 31, 2005 from
$27.3 million for the same period in 2004, attributable to
increased production volumes and a higher depletion rate due to
forecasted increased future development costs. On a unit basis,
DD&A expense in Wyoming increased to $0.75 per Mcfe in
2005 from $0.60 per Mcfe in 2004.
In China, production costs were $7.4 million in 2005, or
$0.79 per Mcfe or $4.72 per BOE, compared with
$2.3 million in 2004, or $0.61 per Mcfe or
$3.66 per BOE. Severance taxes in China during the year
ended December 31, 2005 were $3.4 million compared to
$1.0 million in 2004, or $0.36 per Mcfe
($2.18 per BOE) in 2005
42
compared to $0.27 per Mcfe ($1.62 per BOE) in 2004.
The increase in severance taxes relates to a full year of
production during 2005 compared to half year in 2004. In China,
DD&A expense was $9.6 million or $1.03 per Mcfe or
$6.20 per BOE, in 2005 compared to $2.9 million, or
$0.77 per Mcfe or $4.65 per BOE in 2004. Production
commenced in China during July 2004.
Interest expense decreased to $3.3 million in 2005 from
$3.8 million in 2004. This decrease was largely
attributable to the decrease in borrowings under the senior
credit facility and was partially offset by increased interest
rates during 2005.
Income tax expense increased to $123.5 million in 2005 from
$58.0 million in 2004. This increase was primarily
attributable to an increase in net income from continuing
operations combined with an increase in the tax rate. Income
taxes were booked at the rate of 35.1% for the year ended
December 31, 2005 as compared to a rate of 34.7% in 2004.
The Company was not liable for current payment of any material
amount of income taxes for the period ending December 31,
2005.
Liquidity
and Capital Resources
During the year-ended December 31, 2006, the Company relied
on cash provided by operations and borrowings under its senior
credit facility to finance its capital expenditures. The Company
participated in the drilling of 170 wells in Wyoming and
continued to participate in the development process in the China
Blocks, including the ongoing drilling of development wells. For
the year-ended December 31, 2006 net capital
expenditures were $503.9 million. At December 31,
2006, the Company reported a cash position of $14.7 million
compared to $44.4 million at December 31, 2005.
Working capital at December 31, 2006 was
($41.4) million as compared to $42.7 million at
December 31, 2005. As of December 31, 2006, the
Company had $165.0 million in outstanding bank indebtedness
and other long-term obligations of $26.6 million comprised
of items payable in more than one year, primarily related to
production taxes.
The Companys cash provided by operating activities, along
with availability under its senior credit facility, are
projected to be sufficient to fund the Companys budgeted
capital expenditures for 2007, which are currently projected to
be $600.0 million. Of the $600.0 million budget, the
Company plans to allocate approximately 93% to Wyoming, 4% to
Pennsylvania and 3% to China. With the budget allocated for
Wyoming, the Company plans to drill or participate in an
estimated 185 gross wells in 2007, of which approximately
25% will be for exploration wells and the remaining will be for
development wells. Of the allocation for China, approximately
33% will be for exploratory/appraisal activity and the balance
will be for development activity. The Company currently has no
budget for acquisitions in 2007.
The Company (through its subsidiary) participates in a revolving
credit facility with a group of banks led by JP Morgan Chase
Bank, N.A. The agreement specifies a maximum loan amount of
$500 million, an aggregate borrowing base of
$1.1 billion and a commitment amount of $200 million
at December 31, 2006. The commitment amount may be
increased up to the lesser of the borrowing base amount or
$500 million at any time at the request of the Company.
Each bank shall have the right, but not the obligation, to
increase the amount of their commitment as requested by the
Company. In the event that the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to bring additional banks
into the facility. At December 31, 2006, the Company had
$165.0 million outstanding and $35.0 million unused
and available under the current committed amount.
The credit facility matures on May 1, 2010. The note
bears interest at either (A) the banks prime rate
plus a variable margin ranging from zero percent (0.00%) to
three-quarters of one percent (0.75%) based on the percentage of
available credit drawn or at (B) LIBOR plus a variable
margin ranging from one percent (1.00%) to one and
three-quarters of one percent (1.75%) based on the percentage of
available credit drawn. For purposes of calculating interest,
the available credit is equal to the borrowing base. An average
annual commitment fee of 0.25% to 0.375%, depending on the
percentage of available credit drawn, is charged quarterly for
any unused portion of the commitment amount. The Companys
total commitment fees were $377,173, $354,017 and $374,096 for
the years ended December 31, 2006, 2005 and 2004,
respectively.
43
The borrowing base is subject to periodic (at least semi-annual)
review and re-determination by the banks and may be decreased or
increased depending on a number of factors, including the
Companys proved reserves and the banks forecast of
future oil and natural gas prices. If the borrowing base is
reduced to an amount less than the balance outstanding, the
Company has sixty days from the date of written notice of the
reduction in the borrowing base to pay the difference.
Additionally, the Company is subject to quarterly reviews of
compliance with the covenants under the bank facility including
minimum coverage ratios relating to interest, working capital
and advances to
Sino-American
Energy Corporation. In the event of a default under the
covenants, the Company may not be able to access funds otherwise
available under the facility. As of December 31, 2006, the
Company was in compliance with required covenants of the bank
facility.
Any debt outstanding under the credit facility is secured by a
majority of the Companys proved domestic oil and natural
gas properties.
During the year-ended December 31, 2006, net cash provided
by operating activities was $435.9 million, a 5% increase
over the $414.4 million for the same period in 2005. The
increase in net cash provided by operating activities was
largely attributable to the increase in production during the
year-ended December 31, 2006.
During the year-ended December 31, 2006, net cash used in
investing activities was $454.8 million as compared to
$306.5 million for the same period in 2005. The increase in
net cash used in investing activities is largely due to
increased capital expenditures associated with the
Companys drilling activities.
During the year-ended December 31, 2006, net cash used in
financing activities was $10.7 million as compared to
$80.3 million for the same period in 2005. The change in
net financing activities is primarily attributable to borrowings
under the Companys senior credit facility during 2006
offset by the repurchase of shares under the Companys
share repurchase program during the year-ended December 31,
2006 (See Note 8).
Off-Balance
Sheet Arrangements
The company did not have any off-balance sheet arrangements as
of December 31, 2006.
Contractual
Obligations
The following table summarizes our contractual obligations as of
December 31, 2006:
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|
|
|
|
|
Payments Due by Period:
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
Total
|
|
|
One Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Long-term debt
|
|
$
|
165,000,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
165,000,000
|
|
|
$
|
|
|
Drilling contracts
|
|
|
136,990,625
|
|
|
|
74,848,535
|
|
|
|
62,142,090
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
799,026
|
|
|
|
799,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office space lease
|
|
|
636,157
|
|
|
|
408,347
|
|
|
|
227,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
303,425,808
|
|
|
$
|
76,055,908
|
|
|
$
|
62,369,900
|
|
|
$
|
165,000,000
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, the Company had committed to
drilling obligations with certain rig contractors that will
continue into 2009. The mentioned drilling rigs were contracted
to fulfill the
2006-2009
drilling program initiatives in Wyoming.
On October 16, 2003 the operator of the Companys
properties in China, Kerr-McGee (now Anadarko Petroleum), signed
a 15 year contract, which provides for up to an additional
10 years, to lease the FPSO. The Company ratified the
contract for its net share which is 8.91%. The FPSO service
agreement calls for a day rate lease payment and a sliding scale
per barrel processing fee that decreases based on cumulative
barrels processed. The lease contains a cancellation fee for the
Company based on a sliding time-scale (cancellation fee
decreases with time) which as of December 31, 2006 was
$2.7 million, net to the Companys interest. The
Company considers it very unlikely that a lease cancellation
situation will occur. Due to the terms of the lease, the Company
cannot estimate with any degree of accuracy the costs it may
incur during the life of the lease. The Companys net share
for the costs of the FPSO in 2006 was approximately
$3.2 million.
44
In May 2003, the Company amended its prior office lease in
Englewood, Colorado, which it has committed to through June
2008. The Companys total remaining commitment for this
lease is $504,769 at December 31, 2006 ($333,359 in 2007
and $171,410 in 2008). In December 2003, the Company signed a
lease for office space in Houston, Texas, which it has committed
to through April 2007 for a total remaining commitment at
December 31, 2006 of $33,948. At December 31, 2006,
the remaining commitment on the Companys Pinedale office
is $97,440 ($41,040 in 2007, $33,840 in 2008 and $22,560 in
2009). The total remaining commitment for all offices is
$636,157.
On December 19, 2005, the Company signed two Precedent
Agreements (Precedent Agreements) with Rockies
Express Pipeline, LLC (REX) and Entrega Gas
Pipeline, LLC governing how the parties will proceed through the
design, regulatory process and construction of the pipeline
facilities and, subject to certain conditions precedent, the
Company will take firm transportation service if and when the
pipeline facilities are constructed. Commencing upon completion
of the pipeline facilities, the Companys commitment
involves capacity of 200,000 MMBtu per day of natural gas
for a term of 10 years, and the Company will be obligated
to pay to REX certain demand charges related to its rights to
hold this firm transportation capacity as an anchor shipper.
Based on current assumptions, current projections regarding the
cost of the expansion and the participation of other shippers in
the expansion (noting specifically that these assumptions are
likely to change materially), the Company currently projects
that annual demand charges due may be approximately
$70.0 million per year for the term of the contract,
exclusive of fuel and surcharges. The Companys Board of
Directors approved the Precedent Agreements on February 6,
2006 and Kinder Morgan, as the managing member of REX advised
the Company of their final approval of the Precedent Agreements,
and their intent to proceed with the construction of the Rockies
Express Pipeline on February 28, 2006.
The pipeline facilities are currently anticipated to be
completed in stages between 2008 and 2009. REX filed its
application for a Certificate of Public Convenience and
Necessity for the Rockies Express West Project
(REX-West) with the FERC on May 31, 2006. The
REX-West portion of the project is 713 miles of pipeline
commencing at Cheyenne Hub (Weld County, CO) and terminating in
Audrain County, Missouri. FERC issued a Preliminary
Determination on Non-Environmental Issues related to the
REX-West application on September 21, 2006, stating that,
subject to certain conditions, the REXs proposals are in
the public interest. This order did not consider or evaluate any
environmental issues, which will be addressed in a subsequent
FERC order, which is expected during 2007. FERC also issued a
Draft Environmental Impact Statement on REX-West, on
November 3, 2006. REX has indicated to the Company that,
upon receipt of the final FERC order on environmental issues,
construction of the REX-West portion of the project will
commence. This is expected to occur early in the second quarter
of 2007. The REX partners have indicated that they will file the
application for a Certificate of Public Convenience and
Necessity for the Rockies Express East segment (Missouri to
Ohio) of the proposed project following receipt of the order
approving the REX-West Certificate of Public Convenience and
Necessity.
Additionally, in maintaining its acreage base that is not held
by production, the Company incurs certain expenses, including
delay rental costs. From year to year, the Companys
acreage base varies, sometimes dramatically, rendering it
impossible to forecast with any accuracy what the amount of
these delay rental costs will be. In 2006, delay rental costs
for all of the Companys leases not held by production were
$319,977.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
The Companys major market risk exposure is in the pricing
applicable to its natural gas and oil production. Realized
pricing is currently driven primarily by the prevailing price
for the Companys Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable. Pricing volatility is expected
to continue. Natural gas price realizations ranged from a
monthly low of $4.50 per Mcf to a monthly high of
$8.26 per Mcf during 2006. Realized natural gas prices are
derived from the financial statements which include the effects
of hedging and natural gas balancing.
The Company primarily relies on fixed price forward natural gas
sales to manage its commodity price exposure. See
Managements Discussion and Analysis of Financial Condition
and Results of Operations Commodity Derivative
Instruments and Hedging.
45
The Company had the following fixed price physical delivery
contracts in place on behalf of its interest and those of other
parties at December 31, 2006. (The Companys
approximate average net interest in physical gas sales
is 80%.)
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
Average
|
|
Contract Period
|
|
MMbtu/Day
|
|
|
Price/MMbtu
|
|
|
April 2007 - October 2007
|
|
|
40,000
|
|
|
$
|
6.20
|
|
Subsequent to December 31, 2006 and through
February 26, 2007, the Company has entered into the
following fixed price physical delivery contracts on behalf of
its interest and those of other parties:
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
Average
|
|
Contract Period
|
|
MMbtu/Day
|
|
|
Price/MMbtu
|
|
|
Calendar 2008
|
|
|
60,000
|
|
|
$
|
6.63
|
|
46
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for the preparation
and integrity of all information contained in this Annual
Report. The accompanying financial statements have been prepared
in conformity with accounting principles generally accepted in
the United States of America. The financial statements include
amounts that are managements best estimates and judgments.
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term
is defined in Exchange Act
Rules 13a-15(f).
Under the supervision and with the participation of our
management, including our chief executive officer and chief
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, our management concluded that our internal
control over financial reporting was effective as of
December 31, 2006.
Managements assessment of the effectiveness of the
Companys internal controls over financial reporting as of
December 31, 2006 has been fully audited by
Ernst & Young LLP, an independent registered public
accounting firm, as stated in their report which is included
herein.
Michael D. Watford
Chief Executive Officer
February 26, 2007
47
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Ultra Petroleum Corp.
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control over
Financial Reporting, that Ultra Petroleum Corp. 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
(the COSO criteria). Ultra Petroleum Corp.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 an opinion on managements assessment and an
opinion on the effectiveness of the companys internal
control over financial reporting based on our audit.
We conducted our audit 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. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys 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 companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) 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 (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys 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.
In our opinion, managements assessment that Ultra
Petroleum Corp. maintained effective internal control over
financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on the COSO criteria.
Also, in our opinion, Ultra Petroleum Corp. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2006, based on the COSO
criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of Ultra Petroleum Corp. as of
December 31, 2006 and the related consolidated statements
of operations and retained earnings, shareholders equity,
and cash flow for the year ended December 31, 2006 of Ultra
Petroleum Corp. and our report dated February 26, 2007
expressed an unqualified opinion thereon.
Houston, Texas
February 26, 2007
48
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Ultra Petroleum Corp.:
We have audited the accompanying consolidated balance sheet of
Ultra Petroleum Corp. and subsidiaries as of December 31,
2005 and the related consolidated statements of operations and
retained earnings, shareholders equity, and cash flow for
each of the years in the two-year period ended December 31,
2005. These consolidated financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Ultra Petroleum Corp. and subsidiaries as of
December 31, 2005, and the results of their operations and
their cash flows for each of the years in the two-year period
ended December 31, 2005, in accordance with
U.S. generally accepted accounting principles.
Denver, Colorado
March 30, 2006
49
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Ultra Petroleum Corp.
We have audited the accompanying consolidated balance sheet of
Ultra Petroleum Corp. as of December 31, 2006 and the
related consolidated statement of operations and retained
earnings, shareholders equity, and cash flow for the year
ended December 31, 2006. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit 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 includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Ultra Petroleum Corp. at December 31,
2006 and the consolidated results of their operations and their
cash flows for year ended December 31, 2006, in conformity
with U.S. generally accepted accounting principles.
As discussed in Notes 1 and 6 to the consolidated financial
statements, Ultra Petroleum Corp. changed its method of
accounting for Share-Based Payments in accordance with Statement
of Financial Accounting Standards No. 123 (revised
2004) on January 1, 2006.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Ultra Petroleum Corp.s 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 and our report dated February 26, 2007
expressed an unqualified opinion thereon.
Houston, Texas
February 26, 2007
50
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Expressed in U.S. dollars)
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
14,706,855
|
|
|
$
|
44,394,775
|
|
Restricted cash
|
|
|
667,332
|
|
|
|
213,899
|
|
Accounts receivable
|
|
|
90,098,871
|
|
|
|
75,656,031
|
|
Deferred tax asset
|
|
|
8,266,499
|
|
|
|
|
|
Inventory
|
|
|
19,337,214
|
|
|
|
22,062,585
|
|
Prepaid drilling costs and other
current assets
|
|
|
3,493,731
|
|
|
|
128,044
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
136,570,502
|
|
|
|
142,455,334
|
|
Oil and gas properties, using the
full cost method of accounting
Proved
|
|
|
1,048,307,743
|
|
|
|
612,960,790
|
|
Unproved
|
|
|
71,060,353
|
|
|
|
89,702,465
|
|
Capital assets
|
|
|
1,830,039
|
|
|
|
2,147,528
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
1,257,768,637
|
|
|
$
|
847,266,117
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued
liabilities
|
|
$
|
76,290,552
|
|
|
$
|
49,297,861
|
|
Current taxes payable
|
|
|
6,842,057
|
|
|
|
3,564,990
|
|
Capital cost accrual
|
|
|
94,866,741
|
|
|
|
46,879,289
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
177,999,350
|
|
|
|
99,742,140
|
|
Long-term debt
|
|
|
165,000,000
|
|
|
|
|
|
Deferred income tax liability
|
|
|
259,191,252
|
|
|
|
155,746,465
|
|
Other long-term obligations
|
|
|
26,573,220
|
|
|
|
20,576,574
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Common stock no par
value; authorized unlimited; issued and
outstanding 151,795,633 and 155,075,864 at
December 31, 2006 and 2005, respectively
|
|
|
5,414,421
|
|
|
|
178,806,030
|
|
Treasury stock
|
|
|
(1,193,650
|
)
|
|
|
(1,193,650
|
)
|
Retained earnings
|
|
|
624,784,044
|
|
|
|
393,588,558
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
629,004,815
|
|
|
|
571,200,938
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies
(Note 12)
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
SHAREHOLDERS EQUITY
|
|
$
|
1,257,768,637
|
|
|
$
|
847,266,117
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
Approved on behalf of the Board:
|
|
|
/s/ Michael D. Watford,
Chairman
of the Board, Chief Executive Officer
and President
|
|
/s/ Stephen J.
McDaniel, Director
|
51
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Expressed in U.S. Dollars)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
470,324,244
|
|
|
$
|
422,091,034
|
|
|
$
|
224,207,694
|
|
Oil sales
|
|
|
122,343,339
|
|
|
|
94,401,967
|
|
|
|
34,838,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
592,667,583
|
|
|
|
516,493,001
|
|
|
|
259,046,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses and taxes,
excluding depreciation and amortization
|
|
|
110,008,894
|
|
|
|
89,601,686
|
|
|
|
50,869,283
|
|
Depletion, depreciation and
amortization
|
|
|
93,498,556
|
|
|
|
58,102,871
|
|
|
|
30,249,061
|
|
General and administrative,
excluding depreciation and amortization
|
|
|
14,935,103
|
|
|
|
14,342,178
|
|
|
|
7,075,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218,442,553
|
|
|
|
162,046,735
|
|
|
|
88,194,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
374,225,030
|
|
|
|
354,446,266
|
|
|
|
170,852,383
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
1,943,121
|
|
|
|
612,153
|
|
|
|
90,760
|
|
Interest expense
|
|
|
(3,909,246
|
)
|
|
|
(3,286,087
|
)
|
|
|
(3,783,070
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,966,125
|
)
|
|
|
(2,673,934
|
)
|
|
|
(3,692,310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
372,258,905
|
|
|
|
351,772,332
|
|
|
|
167,160,073
|
|
Income tax provision
|
|
|
141,063,419
|
|
|
|
123,472,085
|
|
|
|
58,010,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
231,195,486
|
|
|
|
228,300,247
|
|
|
|
109,149,795
|
|
RETAINED EARNINGS, beginning of
year
|
|
|
393,588,558
|
|
|
|
165,288,311
|
|
|
|
56,138,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RETAINED EARNINGS, end of year
|
|
$
|
624,784,044
|
|
|
$
|
393,588,558
|
|
|
$
|
165,288,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER COMMON
SHARE BASIC
|
|
$
|
1.50
|
|
|
$
|
1.49
|
|
|
$
|
0.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER COMMON
SHARE DILUTED
|
|
$
|
1.43
|
|
|
$
|
1.41
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding basic
|
|
|
153,878,715
|
|
|
|
153,100,067
|
|
|
|
149,735,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding diluted
|
|
|
161,614,570
|
|
|
|
161,943,400
|
|
|
|
161,205,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
52
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
|
|
|
|
|
|
Total
|
|
|
|
Shares
|
|
|
Common
|
|
|
Retained
|
|
|
Income
|
|
|
Treasury
|
|
|
Shareholders
|
|
|
|
Issued
|
|
|
Stock
|
|
|
Earnings
|
|
|
(Loss)
|
|
|
Stock
|
|
|
Equity
|
|
|
Balances at December 31, 2003
|
|
|
149,095,336
|
|
|
|
97,448,221
|
|
|
|
56,138,516
|
|
|
|
(2,940,357
|
)
|
|
|
(1,193,650
|
)
|
|
|
149,452,730
|
|
Stock options exercised
|
|
|
1,106,600
|
|
|
|
1,770,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,770,099
|
|
Employee stock plan grants
|
|
|
33,000
|
|
|
|
560,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
560,175
|
|
Fair value of non-employee stock
option grants
|
|
|
|
|
|
|
100,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,550
|
|
Tax benefit of stock options
exercised
|
|
|
|
|
|
|
6,634,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,634,807
|
|
Comprehensive earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
109,149,795
|
|
|
|
|
|
|
|
|
|
|
|
109,149,795
|
|
Change in derivative instruments
fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
323,590
|
|
|
|
|
|
|
|
323,590
|
|
Total comprehensive earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,473,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2004
|
|
|
150,234,936
|
|
|
|
106,513,852
|
|
|
|
165,288,311
|
|
|
|
(2,616,767
|
)
|
|
|
(1,193,650
|
)
|
|
|
267,991,746
|
|
Stock options exercised
|
|
|
4,793,700
|
|
|
|
20,266,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,266,680
|
|
Employee stock plan grants
|
|
|
47,228
|
|
|
|
1,389,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,389,380
|
|
Tax benefit of stock options
exercised
|
|
|
|
|
|
|
50,636,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,636,118
|
|
Comprehensive earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
228,300,247
|
|
|
|
|
|
|
|
|
|
|
|
228,300,247
|
|
Change in derivative instruments
fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,616,767
|
|
|
|
|
|
|
|
2,616,767
|
|
Total comprehensive earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
230,917,014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2005
|
|
|
155,075,864
|
|
|
|
178,806,030
|
|
|
|
393,588,558
|
|
|
|
|
|
|
|
(1,193,650
|
)
|
|
|
571,200,938
|
|
Stock options exercised
|
|
|
655,900
|
|
|
|
9,202,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,202,730
|
|
Employee stock plan grants
|
|
|
33,401
|
|
|
|
2,141,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,141,003
|
|
Shares repurchased and retired
|
|
|
(3,969,532
|
)
|
|
|
(197,551,398
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(197,551,398
|
)
|
Fair value of employee stock option
grants
|
|
|
|
|
|
|
2,313,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,313,534
|
|
Tax benefit of stock options
exercised
|
|
|
|
|
|
|
10,502,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,502,522
|
|
Comprehensive earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
231,195,486
|
|
|
|
|
|
|
|
|
|
|
|
231,195,486
|
|
Total comprehensive earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
231,195,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2006
|
|
|
151,795,633
|
|
|
$
|
5,414,421
|
|
|
$
|
624,784,044
|
|
|
$
|
|
|
|
$
|
(1,193,650
|
)
|
|
$
|
629,004,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
53
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
231,195,486
|
|
|
$
|
228,300,247
|
|
|
$
|
109,149,795
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
amortization
|
|
|
93,498,556
|
|
|
|
58,102,871
|
|
|
|
30,249,061
|
|
Deferred and current non-cash
income taxes
|
|
|
105,680,810
|
|
|
|
69,270,977
|
|
|
|
57,748,452
|
|
Tax benefit of stock options
exercised
|
|
|
|
|
|
|
50,636,118
|
|
|
|
|
|
Stock compensation
|
|
|
1,556,767
|
|
|
|
2,858,515
|
|
|
|
923,623
|
|
Excess tax benefit from stock
based compensation
|
|
|
(10,502,522
|
)
|
|
|
|
|
|
|
|
|
Net changes in working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(453,433
|
)
|
|
|
(1,938
|
)
|
|
|
(1,292
|
)
|
Accounts receivable
|
|
|
(14,442,840
|
)
|
|
|
(39,906,744
|
)
|
|
|
(16,400,426
|
)
|
Inventory
|
|
|
664,409
|
|
|
|
(518,576
|
)
|
|
|
(275,424
|
)
|
Prepaid expenses and other current
assets
|
|
|
(3,365,687
|
)
|
|
|
1,597,799
|
|
|
|
(14,106
|
)
|
Accounts payable and accrued
liabilities
|
|
|
26,592,691
|
|
|
|
32,518,107
|
|
|
|
(10,169,082
|
)
|
Other long-term obligations
|
|
|
2,155,923
|
|
|
|
7,931,130
|
|
|
|
3,870,179
|
|
Taxation payable
|
|
|
3,277,067
|
|
|
|
3,564,990
|
|
|
|
261,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
435,857,227
|
|
|
|
414,353,496
|
|
|
|
175,342,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas property expenditures
|
|
|
(503,881,901
|
)
|
|
|
(282,668,055
|
)
|
|
|
(195,598,484
|
)
|
Change in capital costs accrual
|
|
|
47,987,452
|
|
|
|
(6,239,096
|
)
|
|
|
22,501,473
|
|
Inventory
|
|
|
1,677,260
|
|
|
|
(16,054,472
|
)
|
|
|
9,037,557
|
|
Purchase of capital assets
|
|
|
(622,815
|
)
|
|
|
(1,585,819
|
)
|
|
|
(954,702
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) investing
activities
|
|
|
(454,840,004
|
)
|
|
|
(306,547,442
|
)
|
|
|
(165,014,156
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt, gross
|
|
|
165,000,000
|
|
|
|
22,000,000
|
|
|
|
44,000,000
|
|
Payments on long-term debt, gross
|
|
|
|
|
|
|
(124,000,000
|
)
|
|
|
(41,000,000
|
)
|
Repurchased shares
|
|
|
(197,551,398
|
)
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common
stock
|
|
|
9,202,730
|
|
|
|
20,266,680
|
|
|
|
1,770,099
|
|
Excess tax benefit from stock
based compensation
|
|
|
10,502,522
|
|
|
|
|
|
|
|
|
|
Stock issued for compensation
|
|
|
2,141,003
|
|
|
|
1,389,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by
financing activities
|
|
|
(10,705,143
|
)
|
|
|
(80,343,940
|
)
|
|
|
4,770,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease)/increase in cash
and cash equivalents
|
|
|
(29,687,920
|
)
|
|
|
27,462,114
|
|
|
|
15,098,549
|
|
Cash and cash equivalents,
beginning of year
|
|
|
44,394,775
|
|
|
|
16,932,661
|
|
|
|
1,834,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of
year
|
|
$
|
14,706,855
|
|
|
$
|
44,394,775
|
|
|
$
|
16,932,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
1,912,949
|
|
|
$
|
3,393,279
|
|
|
$
|
3,783,070
|
|
Income taxes
|
|
$
|
21,379,990
|
|
|
$
|
326,502
|
|
|
$
|
153,905
|
|
Non-cash tax benefit of stock
options exercised
|
|
|
|
|
|
$
|
50,636,118
|
|
|
$
|
6,634,807
|
|
See accompanying notes to consolidated financial statements.
54
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in U.S. dollars unless otherwise noted)
Years ended December 31, 2006, 2005 and 2004
DESCRIPTION
OF THE BUSINESS
Ultra Petroleum Corp. (the Company) is an
independent oil and natural gas company engaged in the
acquisition, exploration, development, and production of oil and
natural gas properties. The Company is incorporated under the
laws of the Yukon Territory, Canada. The Companys
principal business activities are in the Green River Basin of
southwest Wyoming and Bohai Bay, China.
|
|
1.
|
SIGNIFICANT
ACCOUNTING POLICIES:
|
(a) Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries UP Energy Corporation, Ultra Resources, Inc.
and
Sino-American
Energy Corporation. The Company presents its financial
statements in accordance with U.S. Generally Accepted
Accounting Principles (GAAP). All material
inter-company transactions and balances have been eliminated
upon consolidation.
(b) Accounting principles: The
consolidated financial statements are prepared in accordance
with accounting principles generally accepted in the United
States.
(c) Cash and cash equivalents: We
consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents.
(d) Restricted cash: Restricted cash
represents cash received by the Company from production sold
where the final division of ownership of the production is
unknown or in dispute. Wyoming law requires that these funds be
held in a federally insured bank in Wyoming.
(e) Capital assets: Capital assets are
recorded at cost and depreciated using the declining-balance
method based on a seven-year useful life.
(f) Oil and natural gas properties: The
Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and
Exchange Commission (SEC). Separate cost centers are
maintained for each country in which the Company incurs costs.
Under this method of accounting, the costs of unsuccessful, as
well as successful, exploration and development activities are
capitalized as properties and equipment. This includes any
internal costs that are directly related to exploration and
development activities but does not include any costs related to
production, general corporate overhead or similar activities.
Effective with the adoption of Statement of Financial Accounting
Standard (SFAS) No. 143, Accounting for
Asset Retirement Obligations (SFAS
No. 143) in 2003, the carrying amount of oil and
natural gas properties also includes estimated asset retirement
costs recorded based on the fair value of the asset retirement
obligation when incurred. Gain or loss on the sale or other
disposition of oil and natural gas properties is not recognized,
unless the gain or loss would significantly alter the
relationship between capitalized costs and proved reserves of
oil and natural gas attributable to a country.
The sum of net capitalized costs and estimated future
development costs of oil and natural gas properties are
amortized using the
units-of-production
method based on the proven reserves as determined by independent
petroleum engineers. Oil and natural gas reserves and production
are converted into equivalent units based on relative energy
content. Operating fees received related to the properties in
which the Company owns an interest are netted against expenses.
Fees received in excess of costs incurred are recorded as a
reduction to the full cost pool. Effective with the adoption of
SFAS No. 143, asset retirement obligations are
included in the base costs for calculating depletion.
Oil and natural gas properties include costs that are excluded
from capitalized costs being amortized. These amounts represent
investments in unproved properties and major development
projects. The Company excludes these costs on a
country-by-country
basis until proved reserves are found or until it is determined
that the costs are
55
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
impaired. All costs excluded are reviewed, at least quarterly,
to determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized (the depreciation, depletion and amortization
(DD&A) pool) or a charge is made against
earnings for those international operations where a reserve base
has not yet been established. For international operations where
a reserve base has not yet been established, an impairment
requiring a charge to earnings may be indicated through
evaluation of drilling results, relinquishing drilling rights or
other information.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly on a
country-by-country
basis. The ceiling limits such pooled costs to the aggregate of
the present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
result in lower DD&A expense in future periods. A write-down
may not be reversed in future periods, even though higher oil
and natural gas prices may subsequently increase the ceiling.
The effect of implementing SFAS No. 143 had no effect
on the ceiling test calculation as the future cash outflows
associated with settling asset retirement obligations are
excluded from this calculation.
(g) Inventories: Crude oil products and
materials and supplies inventories are carried at the lower of
current market value or cost. Inventory costs include
expenditures and other charges directly and indirectly incurred
in bringing the inventory to its existing condition and location
and the Company uses the weighted average method of recording
its inventory. Selling expenses and general and administrative
expenses are reported as period costs and excluded from
inventory cost. Inventories of materials and supplies are valued
at cost or less. Crude oil product inventory at
December 31, 2006 and 2005 includes depletion and lease
operating expenses (LOE) of $408,300 and $1,456,400,
respectively, associated with the Companys crude oil
production in China. At December 31, 2006, drilling and
completion supplies inventory of $18.9 million primarily
includes the cost of pipe that will be utilized during the 2007
drilling program.
(h) Derivative transactions: From time to
time, the Company has entered into commodity price risk
management transactions to manage its exposure to natural gas
price volatility. These transactions are in the form of fixed
price forward natural gas sales contracts with financial
institutions and other creditworthy counterparties. These
transactions have been designated by the Company as cash flow
hedges. As such, unrealized gains and losses related to the
change in fair market value of the derivative contracts are
recorded in other comprehensive income in the balance sheet to
the extent the hedges are effective.
(i) Income taxes: Income taxes are
accounted for under the asset and liability method. Deferred tax
assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities
and their respective tax basis and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in
the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date.
(j) Earnings per share: Basic earnings
per share is computed by dividing net earnings attributable to
common stock by the weighted average number of common shares
outstanding during each period. Diluted earnings per share is
computed by adjusting the average number of common shares
outstanding for the dilutive effect, if any, of common stock
equivalents. The Company uses the treasury stock method to
determine the dilutive effect.
56
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table provides a reconciliation of the components
of basic and diluted net income per common share for the years
ended December 31, 2006, 2005 and 2004: (The earnings per
share information (Basic income per common share and Diluted
income per common share) have been updated to reflect the 2 for
1 stock split on May 10, 2005).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Net income
|
|
$
|
231,195,486
|
|
|
$
|
228,300,247
|
|
|
$
|
109,149,795
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding during the period
|
|
|
153,878,715
|
|
|
|
153,100,067
|
|
|
|
149,735,666
|
|
Effect of dilutive instruments
|
|
|
7,735,855
|
|
|
|
8,843,333
|
|
|
|
11,469,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding during the period including the effects of dilutive
instruments
|
|
|
161,614,570
|
|
|
|
161,943,400
|
|
|
|
161,205,534
|
|
Basic earnings per share
|
|
$
|
1.50
|
|
|
$
|
1.49
|
|
|
$
|
0.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
1.43
|
|
|
$
|
1.41
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of shares not included in
dilutive earnings per share that would have been anti-dilutive
because the exercise price was greater than the average market
price of the common shares
|
|
|
239,966
|
|
|
|
540,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(k) Use of estimates: Preparation of
consolidated financial statements in accordance with accounting
principles generally accepted in the United States requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
(l) Accounting for share-based
compensation: On January 1, 2006, the
Company adopted Statement of Financial Accounting Standards
No. 123 (revised 2004), Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors
including employee stock options based on estimated fair values.
SFAS No. 123R supersedes the Companys previous
accounting under Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to
Employees (APB No. 25) for periods
beginning in fiscal year 2006. In March 2005, the SEC issued
Staff Accounting Bulletin No. 107
(SAB 107) relating to SFAS No. 123R.
The Company has applied the provisions of SAB 107 in its
adoption of SFAS No. 123R.
The Company adopted SFAS No. 123R using the modified
prospective transition method, which requires the application of
the accounting standard as of January 1, 2006, the first
day of the Companys fiscal year 2006. The Companys
Consolidated Financial Statements as of and for the year-ended
December 31, 2006 reflect the impact of
SFAS No. 123R. In accordance with the modified
prospective transition method, the Companys Consolidated
Financial Statements for prior periods have not been restated to
reflect, and do not include, the impact of
SFAS No. 123R. Share-based compensation expense
recognized under SFAS No. 123R for the year- ended
December 31, 2006 was $1,156,767, which consisted of
stock-based compensation expense related to employee stock
options. There was no stock-based compensation expense related
to employee stock options recognized during the year-ended
December 31, 2005.
SFAS No. 123R requires companies to estimate the fair
value of share-based payment awards on the date of grant using
an option-pricing model. The value of the portion of the award
that is ultimately expected to vest is recognized as expense
over the requisite service periods in the Companys
Consolidated Statement of Operations.
57
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Under SFAS No. 123R, share-based compensation expense
recognized during the period is based on the value of the
portion of share-based payment awards that is ultimately
expected to vest during the period. Share-based compensation
expense recognized in the Companys Consolidated Statement
of Operations for the year-ended December 31, 2006 includes
compensation expense for share-based payment awards granted
subsequent to January 1, 2006 based on the grant date fair
value estimated in accordance with the provisions of
SFAS No. 123R. As of December 31, 2005, all stock
options granted to date had fully vested. Compensation expense
attributable to awards granted subsequent to January 1,
2006 is recognized using the straight-line method. As
share-based compensation expense recognized in the Consolidated
Statement of Operations for the year-ended December 31,
2006 is based on awards ultimately expected to vest, it has been
reduced for estimated forfeitures. SFAS No. 123R
requires forfeitures to be estimated at the time of grant and
revised, if necessary, in subsequent periods if actual
forfeitures differ from those estimates. In the Companys
pro forma information required under SFAS No. 123 for
the periods prior to January 1, 2006, the Company accounted
for forfeitures as they occurred.
Under SFAS No. 123 (and APB No. 25), the Company
utilized a Black-Scholes option pricing model to measure the
fair value of stock options granted to employees. For additional
information, see Note 6. The Companys determination
of fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to, the Companys expected stock price
volatility over the term of the awards, and actual and projected
employee stock option exercise behaviors.
Option-pricing models were developed for use in estimating the
value of traded options that have no vesting or hedging
restrictions and are fully transferable. Because (1) the
Companys employee stock options have certain
characteristics that are significantly different from traded
options, and (2) changes in the subjective assumptions can
materially affect the estimated value, in managements
opinion, the existing valuation models may not provide an
accurate measure of the fair value of the Companys
employee stock options. Although the fair value of employee
stock options is determined in accordance with
SFAS No. 123R and SAB 107 using a Black-Scholes
option-pricing model, that value may not be indicative of the
fair value observed in a willing buyer/willing seller market
transaction. The Company is responsible for determining the
assumptions used in estimating the fair value of its share-based
payment awards.
Prior to adopting of SFAS No. 123R on January 1,
2006, the Company followed Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123) which
allowed for the continued measurement of compensation cost for
such plans using the intrinsic value based method prescribed by
APB Opinion No. 25 provided that pro forma results of
operations were disclosed for those options granted.
Accordingly, the Company accounted for stock options granted to
employees and directors of the Company under the intrinsic value
method. Had the Company reported compensation costs as
determined by the fair value method of accounting for option
grants to employees and directors, net income and net income per
common share would approximate the following pro forma amounts:
(The earnings per share amounts have been adjusted to reflect
the 2 for 1 stock split on May 10, 2005).
58
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
228,300,247
|
|
|
$
|
109,149,795
|
|
Deduct: Fair value of stock
options issued, net of tax
|
|
|
(13,511,140
|
)
|
|
|
(17,714,486
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma
|
|
$
|
214,789,107
|
|
|
$
|
91,435,309
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
1.49
|
|
|
$
|
0.73
|
|
Pro forma
|
|
$
|
1.40
|
|
|
$
|
0.61
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
1.41
|
|
|
$
|
0.68
|
|
Pro forma
|
|
$
|
1.33
|
|
|
$
|
0.57
|
|
For purposes of pro forma disclosures, the estimated fair value
of options is amortized to expense over the options
vesting period. The weighted-average fair value of each option
granted is estimated on the date of grant using the
Black-Scholes option pricing model with the following
assumptions:
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
|
2005
|
|
|
2004
|
|
|
Expected volatility
|
|
|
34.8 - 44.9
|
%
|
|
|
38.4
|
%
|
Expected dividends
|
|
|
0.0
|
%
|
|
|
0.0
|
%
|
Expected term (in years)
|
|
|
1.9
|
|
|
|
6.50
|
|
Risk free rate
|
|
|
4.18% - 4.41
|
%
|
|
|
3.71
|
%
|
Expected forfeiture rate
|
|
|
Actual forfeitures
|
|
|
|
Actual forfeitures
|
|
(m) Revenue Recognition. Within the
Companys United States segment, natural gas revenues are
recorded on the entitlement method. Under the entitlement
method, revenue is recorded when title passes based on the
Companys net interest. The Company records its entitled
share of revenues based on estimated production volumes.
Subsequently, these estimated volumes are adjusted to reflect
actual volumes that are supported by third party pipeline
statements or cash receipts. Since there is a ready market for
natural gas, the Company sells the majority of its products soon
after production at various locations at which time title and
risk of loss pass to the buyer. Natural gas imbalances occur
when the Company sells more or less than its entitled ownership
percentage of total natural gas production. Any amount received
in excess of the Companys share is treated as a liability.
If the Company receives less than its entitled share, the
underproduction is recorded as a receivable. At
December 31, 2006 the Company had a net natural gas
imbalance liability of $1.7 million and at
December 31, 2005, the Company had a net natural gas
imbalance liability of $0.5 million.
In China, revenues are recognized when production is sold to a
purchaser at a fixed or determinable price, when delivery has
occurred and title is transferred.
(n) Accumulated Other Comprehensive Earnings
(Loss): Other comprehensive earnings (loss) is a
term used to define revenues, expenses, gains and losses that
under generally accepted accounting principles are reported as
separate components of Shareholders Equity instead of net
earnings (loss).
59
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Net income
|
|
$
|
231,195,486
|
|
|
$
|
228,300,247
|
|
|
$
|
109,149,795
|
|
Unrealized loss on derivative
instruments, net of tax
|
|
|
|
|
|
|
|
|
|
|
(2,616,767
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma , including the effect
of dilutive instruments
|
|
$
|
231,195,486
|
|
|
$
|
228,300,247
|
|
|
$
|
106,533,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(o) Impact of recently issued accounting
pronouncements: As of January 1, 2006, the
Company adopted SFAS No. 154, Accounting for
Changes and Error Corrections, a replacement of APB Opinion
No. 20 and SFAS No. 3
(SFAS No. 154). SFAS No. 154
requires retrospective application of voluntary changes in
accounting principles, unless it is impracticable. The adoption
of this standard did not have a material impact on consolidated
results of operations, financial position or liquidity.
In July 2006, the Financial Accounting Standards Board
(FASB) issued Interpretation No. 48
(FIN No. 48), Accounting for
Uncertainty in Income Taxes, an Interpretation of
SFAS No. 109, which clarifies the accounting for
uncertainty in income taxes in accordance with
SFAS No. 109, Accounting for Income Taxes.
FIN No. 48 prescribes a recognition threshold and
measurement attribute for the measurement and financial
statement recognition of a tax position taken or expected to be
taken in a tax return. The interpretation also provides guidance
on de-recognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition. Upon
adoption, FIN No. 48 will be applied to all tax
positions in those tax years for which the tax return statute of
limitations is open. The cumulative effect of the initial
application will be reported as an increase or decrease to
retained earnings as of the beginning of the period in which it
is adopted. For the Company, the provisions of
FIN No. 48 are effective January 1, 2007. The
Company has not completed its evaluation of the impact
FIN No. 48 will have when adopted. However, the
Company currently believes that its implementation will not have
a material impact on consolidated results of operations,
financial position or liquidity.
In September 2006, the SEC staff issued Staff Accounting
Bulletin 108, Financial Statements
Considering the Effects of Prior Year Misstatements When
Quantifying Misstatements in Current Year Financial
Statements (SAB 108). SAB 108
addresses how a registrant should quantify the effect of an
error on the financial statements and concludes that a dual
approach should be used to compute the amount of a misstatement.
Specifically, the amount should be computed using both the
rollover (current year income statement perspective)
and iron curtain (year-end balance sheet
perspective) methods. For the Company, the provisions of
SAB 108 were effective January 1, 2006. The
implementation of SAB 108 did not have a material impact on
the Companys consolidated results of operations, financial
position or liquidity.
|
|
2.
|
ASSET
RETIREMENT OBLIGATIONS:
|
In June 2001, the FASB issued SFAS No. 143,
Accounting for Asset Retirement Obligations
(SFAS No. 143). SFAS No. 143
requires the Company to record the fair value of an asset
retirement obligation as a liability in the period in which it
incurs a legal obligation associated with the retirement of
tangible long-lived assets that result from the acquisition,
construction, development
and/or
normal use of the assets. As of December 31, 2006, the
Company has recorded a liability of $7,442,071 ($6,130,672 U.S.
and $1,311,399 China) to account for future obligations
associated with its assets in both the United States and China.
As of December 31, 2005, the liability was $3,601,348
($2,845,724 U.S. and $755,624 China).
60
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the activities for the
Companys asset retirement obligations for the year ended
December 31, 2006:
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
Asset retirement obligations at
beginning of period
|
|
$
|
3,601,348
|
|
Accretion expense
|
|
|
280,725
|
|
Liabilities incurred
|
|
|
1,681,865
|
|
Liabilities settled
|
|
|
|
|
Revisions of estimated liabilities
|
|
|
1,878,133
|
|
|
|
|
|
|
Asset retirement obligations at
end of period
|
|
|
7,442,071
|
|
Less: current asset retirement
obligations
|
|
|
|
|
|
|
|
|
|
Long-term asset retirement
obligations
|
|
$
|
7,442,071
|
|
|
|
|
|
|
|
|
3.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment,
exploration, drilling and environmental costs
Domestic
|
|
$
|
1,174,683,088
|
|
|
$
|
700,425,880
|
|
Acquisition, equipment,
exploration, drilling and environmental costs China
|
|
|
96,873,985
|
|
|
|
43,890,413
|
|
Less accumulated depletion,
depreciation and amortization Domestic
|
|
|
(196,683,521
|
)
|
|
|
(118,172,467
|
)
|
Less accumulated depletion,
depreciation and amortization China
|
|
|
(26,565,809
|
)
|
|
|
(13,183,036
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,048,307,743
|
|
|
|
612,960,790
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration
costs Domestic
|
|
|
28,997,935
|
|
|
|
17,647,300
|
|
Acquisition and exploration
costs China
|
|
|
42,062,418
|
|
|
|
72,055,165
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,119,368,096
|
|
|
$
|
702,663,255
|
|
|
|
|
|
|
|
|
|
|
61
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company holds interests in projects located in both the
United States and in China. Costs related to these interests of
$71.1 million ($29.0 million in the U.S. and
$42.1 million in China) are not being depleted pending
determination of existence of estimated proved reserves. The
Companys share of exploration on its China properties
accounts for the majority of this balance. The properties in
China began producing in July 2004 and development of additional
fields continues along with exploration of future fields. The
Company will continue to assess and allocate the unproven
properties over the next several years as proved reserves are
established and as exploration dictates whether or not future
areas will be developed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Prior
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
$
|
31,386,056
|
|
|
$
|
12,779,651
|
|
|
$
|
1,818,954
|
|
|
$
|
222,685
|
|
|
$
|
16,564,766
|
|
Exploration costs
|
|
|
7,629,315
|
|
|
|
151,428
|
|
|
|
545,602
|
|
|
|
1,082,804
|
|
|
|
5,849,481
|
|
Less transfers to proved
|
|
|
(10,017,436
|
)
|
|
|
(1,580,444
|
)
|
|
|
(1,627,266
|
)
|
|
|
|
|
|
|
(6,809,726
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,997,935
|
|
|
|
11,350,635
|
|
|
|
737,290
|
|
|
|
1,305,489
|
|
|
|
15,604,521
|
|
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
|
44,857,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,857,346
|
|
Exploration costs
|
|
|
74,826,615
|
|
|
|
6,915,587
|
|
|
|
19,167,259
|
|
|
|
29,390,964
|
|
|
|
19,352,805
|
|
Less transfers to proved
|
|
|
(77,621,543
|
)
|
|
|
(36,908,334
|
)
|
|
|
(19,041,544
|
)
|
|
|
(21,671,665
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,062,418
|
|
|
|
(29,992,747
|
)
|
|
|
125,715
|
|
|
|
7,719,299
|
|
|
|
64,210,151
|
|
Total
|
|
$
|
71,060,353
|
|
|
$
|
(18,642,112
|
)
|
|
$
|
863,005
|
|
|
$
|
9,024,788
|
|
|
$
|
79,814,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2006
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
Accumulated
|
|
|
2006
|
|
|
2005
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Net Book Value
|
|
|
Net Book Value
|
|
|
Computer equipment
|
|
$
|
1,293,655
|
|
|
$
|
(826,760
|
)
|
|
$
|
466,895
|
|
|
$
|
311,884
|
|
Office equipment
|
|
|
329,266
|
|
|
|
(206,086
|
)
|
|
|
123,180
|
|
|
|
88,385
|
|
Field equipment
|
|
|
1,782,387
|
|
|
|
(841,318
|
)
|
|
|
941,069
|
|
|
|
1,025,915
|
|
Other
|
|
|
2,482,916
|
|
|
|
(2,184,021
|
)
|
|
|
298,895
|
|
|
|
721,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,888,224
|
|
|
$
|
(4,058,185
|
)
|
|
$
|
1,830,039
|
|
|
$
|
2,147,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Bank indebtedness
|
|
$
|
165,000,000
|
|
|
$
|
|
|
Other long-term obligations
|
|
|
26,573,220
|
|
|
|
20,576,574
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
191,573,220
|
|
|
$
|
20,576,574
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its
subsidiary) participates in a revolving credit facility with a
group of banks led by JP Morgan Chase Bank, N.A. The agreement
specifies a maximum loan amount of $500.0 million, an
aggregate borrowing base of $1.1 billion and a commitment
amount of $200.0 million at December 31, 2006. The
commitment amount may be increased up to the lesser of the
borrowing base amount or $500.0 million at any time at the
request of the Company. Each bank shall have the right, but not
the obligation, to
62
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
increase the amount of their commitment as requested by the
Company. In the event that the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to bring additional banks
into the facility. At December 31, 2006, the Company had
$165.0 million outstanding and $35.0 million unused
and available under the current committed amount.
The credit facility matures on May 1, 2010. The note
bears interest at either (A) the banks prime rate
plus a variable margin ranging from zero percent (0.00%) to
three-quarters of one percent (0.75%) based on the percentage of
available credit drawn or at (B) LIBOR plus a variable
margin ranging from one percent (1.00%) to one and
three-quarters of one percent (1.75%) based on the percentage of
available credit drawn. For purposes of calculating interest,
the available credit is equal to the borrowing base. An average
annual commitment fee of 0.25% to 0.375%, depending on the
percentage of available credit drawn, is charged quarterly for
any unused portion of the commitment amount. The Companys
total commitment fees were $377,173, $354,017 and $374,096 for
the years ended December 31, 2006, 2005 and 2004,
respectively.
The borrowing base is subject to periodic (at least semi-annual)
review and re-determination by the banks and may be decreased or
increased depending on a number of factors, including the
Companys proved reserves and the banks forecast of
future oil and natural gas prices. If the borrowing base is
reduced to an amount less than the balance outstanding, the
Company has sixty days from the date of written notice of the
reduction in the borrowing base to pay the difference.
Additionally, the Company is subject to quarterly reviews of
compliance with the covenants under the bank facility including
minimum coverage ratios relating to interest, working capital
and advances to
Sino-American
Energy Corporation. In the event of a default under the
covenants, the Company may not be able to access funds otherwise
available under the facility. As of December 31, 2006, the
Company was in compliance with required covenants of the bank
facility.
Any debt outstanding under the credit facility is secured by a
majority of the Companys proved domestic oil and natural
gas properties.
Other long-term obligations: These costs
relate to the long-term portion of production taxes payable, a
liability associated with imbalanced production, our asset
retirement obligations mentioned in Note 2 and the
long-term portion of the Companys incentive compensation
plan.
|
|
6.
|
SHARE
BASED COMPENSATION:
|
The Companys Stock Incentive Plans are administered by the
Compensation Committee of the Board of Directors (the Plan
Administrator). The Plan Administrator may make awards of
stock options to employees, directors, officers and consultants
of the Company as long as the aggregate number of common shares
issuable to any one person pursuant to incentives does not
exceed 5% of the number of common shares outstanding at the time
of the award. In addition, no participant may receive during any
fiscal year of the Companys awards of incentives covering
an aggregate of more than 500,000 common shares. The Plan
Administrator determines the vesting requirements and any
vesting restrictions or forfeitures that occur in certain
circumstances. Incentives may not have an exercise period longer
than 10 years. The exercise price of the stock may not be
less than the fair market value of the common shares at the time
of award, where fair market value means the average
high and low trading price of the common shares on the date of
the award.
On April 29, 2005, the shareholders approved the adoption
of the 2005 Stock Incentive Plan (the 2005 Stock Incentive
Plan). The 2005 Stock Incentive Plan authorizes the Plan
Administrator to award incentives from the effective date of the
2005 Stock Incentive Plan. The 2005 Stock Incentive Plan is in
addition to the Companys existing stock option plans (the
2000 Option Plan and the 1998 Stock
Plan). The 2000 Option Plan and the 1998 Stock Plan remain
effective and the Company will make grants under each of the
existing plans.
The purpose of the 2005 Stock Incentive Plan is to foster and
promote the long-term financial success of the Company and to
increase shareholder value by attracting, motivating and
retaining key employees, consultants and directors and providing
such participants in the 2005 Stock Incentive Plan with a
program for obtaining an
63
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
ownership interest in the Company that links and aligns their
personal interests with those of the Companys
shareholders, thus enabling such participants to share in the
long-term growth and success of the Company. To accomplish these
goals, the 2005 Stock Incentive Plan permits the granting of
incentive stock options, non-statutory stock options, stock
appreciation rights, restricted stock, and other stock-based
awards, some of which may require the satisfaction of
performance-based criteria in order to be payable to
participants. The 2005 Stock Incentive Plan is an important
component of the total compensation package offered to employees
and directors, reflecting the importance that the Company places
on motivating and rewarding superior results with long-term,
performance-based incentives.
The purposes of the 2000 Option Plan and the 1998 Stock Plan
are: (i) to associate the interests of management of the
Company and its subsidiaries and affiliates closely with the
stockholders to generate an increased incentive to contribute to
the Companys future success and prosperity, thus enhancing
the value of the Company for the benefit of its stockholders;
(ii) to maintain competitive compensation levels thereby
attracting and retaining highly competent and talented
directors, employees and consultants; and (iii) to provide
an incentive to such management for continuous employment with
the Company.
Accounting
for share-based compensation
In December 2004, the FASB issued
SFAS No. 123R. SFAS No. 123R is a
revision of SFAS No. 123 and supersedes APB
No. 25. Among other items, SFAS No. 123R
eliminates the use of APB No. 25 and the intrinsic value
method of accounting, and requires companies to recognize the
cost of employee services received in exchange for awards of
equity instruments, based on the grant date fair value of those
awards, in the financial statements. Pro forma disclosure is no
longer an alternative under the new standard. Accordingly, the
Company adopted SFAS No. 123R as of January 1,
2006.
SFAS No. 123R provides specific guidance on income tax
accounting and clarifies how SFAS No. 109,
Accounting for Income Taxes, should be applied to
stock-based compensation. For example, the expense for certain
types of option grants is only deductible for tax purposes at
the time that the taxable event takes place, which could cause
variability in the Companys effective tax rates recorded
throughout the year. SFAS No. 123R does not allow
companies to predict when these taxable events will
take place. Furthermore, it requires that the benefits
associated with the tax deductions in excess of recognized
compensation cost be reported as a financing cash flow, rather
than as an operating cash flow as required under
SFAS No. 123. These future amounts cannot be
estimated, because they depend on, among other things, when
employees exercise stock options.
64
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Valuation
and Expense Information under SFAS 123R
The following table summarizes share-based compensation expense
related to employee stock options under SFAS 123R for the
year ended December 31, 2006 which was allocated as follows:
|
|
|
|
|
|
|
Year-Ended
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
Total cost of share-based payment
plans
|
|
$
|
2,313,534
|
|
Amounts capitalized in inventory
and oil and gas properties
|
|
|
1,156,767
|
|
Amounts recognized in income for
amounts previously capitalized in inventory and fixed assets
|
|
|
|
|
Amounts charged against income,
before income tax benefit
|
|
$
|
1,156,767
|
|
Amount of related income tax
benefit recognized in income
|
|
$
|
406,025
|
|
Impact from adoption of
SFAS No. 123R on:
|
|
|
|
|
Income from continuing operations
|
|
$
|
1,156,767
|
|
Income before income taxes
|
|
$
|
1,156,767
|
|
Net income
|
|
$
|
750,742
|
|
Cash flow from operations
|
|
$
|
(10,502,522
|
)
|
Cash flow from financing activities
|
|
$
|
10,502,522
|
|
Basic earnings per share
|
|
|
|
|
Diluted earnings per share
|
|
|
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model based on
assumptions noted in the following table. The Companys
employee stock options have various restrictions including
vesting provisions and restrictions on transfers and hedging,
among others, and are often exercised prior to their contractual
maturity. Expected volatilities used in the fair value estimate
are based on historical volatility of the Companys stock.
The Company uses historical data to estimate share option
exercises, expected term and employee departure behavior used in
the Black-Scholes pricing model. Groups of employees (executives
and non-executives) that have similar historical behavior are
considered separately for purposes of determining the expected
term used to estimate fair value. The assumptions utilized
result from differing pre- and post-vesting behaviors among
executive and non-executive groups. The risk-free rate for
periods within the contractual term of the share option is based
on the U.S. Treasury yield curve in effect at the time of
grant.
|
|
|
|
|
|
|
|
|
|
|
Non-Executives
|
|
|
Executives
|
|
|
Expected volatility
|
|
|
43.7-45.8
|
%
|
|
|
43.5-47.4
|
%
|
Expected dividends
|
|
|
0
|
%
|
|
|
0
|
%
|
Expected term (in years)
|
|
|
2.75-4.71
|
|
|
|
3.58-5.55
|
|
Risk free rate
|
|
|
4.51-5.03
|
%
|
|
|
4.76-4.84
|
%
|
Expected forfeiture rate
|
|
|
20.0
|
%
|
|
|
20.0
|
%
|
65
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Securities
Authorized for Issuance Under Equity Compensation
Plans
As of December 31, 2006, the Company had the following
securities issuable pursuant to outstanding award agreements or
reserved for issuance under the Companys previously
approved stock incentive plans. (Upon exercise, shares issued
will be newly issued shares).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities to
|
|
|
|
|
|
Number of Securities
|
|
|
|
Be Issued
|
|
|
|
|
|
Remaining Available for
|
|
|
|
Upon
|
|
|
Weighted-
|
|
|
Future Issuance Under
|
|
|
|
Exercise
|
|
|
Average
|
|
|
Equity Compensation
|
|
|
|
of
|
|
|
Exercise Price of
|
|
|
Plans (Excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Securities Reflected in
|
|
Plan Category
|
|
Options
|
|
|
Options
|
|
|
the First Column)
|
|
|
Equity compensation plans approved
by security holders
|
|
|
9,082,756
|
|
|
$
|
10.62
|
|
|
|
10,739,034
|
|
Equity compensation plans not
approved by security holders
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
9,082,756
|
|
|
$
|
10.62
|
|
|
|
10,739,034
|
|
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the three-year period ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted Average
|
|
|
|
Options
|
|
|
Exercise Price (US$)
|
|
|
Balance, December 31, 2003
|
|
|
11,805,000
|
|
|
$
|
0.26 to $7.10
|
|
Granted
|
|
|
2,005,000
|
|
|
$
|
11.69 to $24.31
|
|
Exercised
|
|
|
(1,106,600
|
)
|
|
$
|
0.38 to $7.10
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
12,703,400
|
|
|
$
|
0.26 to $24.31
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
1,529,000
|
|
|
$
|
23.90 to $58.71
|
|
Exercised
|
|
|
(4,793,700
|
)
|
|
$
|
0.32 to $25.68
|
|
Cancelled
|
|
|
(50,000
|
)
|
|
$
|
25.68 to $25.68
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
9,388,700
|
|
|
$
|
0.26 to $58.71
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
379,966
|
|
|
$
|
46.05 to $67.73
|
|
Exercised
|
|
|
(655,900
|
)
|
|
$
|
0.46 to $40.00
|
|
Cancelled
|
|
|
(30,010
|
)
|
|
$
|
16.97 to $63.05
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
9,082,756
|
|
|
$
|
0.26 to $67.73
|
|
|
|
|
|
|
|
|
|
|
66
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables summarize information about the stock
options outstanding at December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Number
|
|
|
Remaining
|
|
|
Exercise Price
|
|
|
Intrinsic Value
|
|
Range of Exercise Price ($US)
|
|
Outstanding
|
|
|
Contractual Life
|
|
|
($US)
|
|
|
($US)
|
|
|
$0.38 - 0.46
|
|
|
2,577,500
|
|
|
|
2.08
|
|
|
$
|
0.46
|
|
|
$
|
121,864,398
|
|
$0.25 - 0.57
|
|
|
760,000
|
|
|
|
3.29
|
|
|
$
|
0.34
|
|
|
$
|
36,025,200
|
|
$1.49 - 2.61
|
|
|
1,355,000
|
|
|
|
4.21
|
|
|
$
|
1.90
|
|
|
$
|
62,109,550
|
|
$3.91 - 4.43
|
|
|
657,500
|
|
|
|
5.36
|
|
|
$
|
4.40
|
|
|
$
|
28,498,425
|
|
$4.83 - 7.10
|
|
|
856,600
|
|
|
|
6.36
|
|
|
$
|
5.05
|
|
|
$
|
36,569,320
|
|
$11.68 - 24.21
|
|
|
1,298,500
|
|
|
|
7.31
|
|
|
$
|
15.89
|
|
|
$
|
41,361,355
|
|
$23.90 - 58.71
|
|
|
1,199,700
|
|
|
|
8.49
|
|
|
$
|
35.93
|
|
|
$
|
15,181,956
|
|
$46.05 - 67.73
|
|
|
377,956
|
|
|
|
9.53
|
|
|
$
|
56.76
|
|
|
$
|
44,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Number
|
|
|
Remaining
|
|
|
Exercise Price
|
|
|
Intrinsic Value
|
|
Range of Exercise Price ($US)
|
|
Exercisable
|
|
|
Contractual Life
|
|
|
($US)
|
|
|
($US)
|
|
|
$0.38 - 0.46
|
|
|
2,577,500
|
|
|
|
2.08
|
|
|
$
|
0.46
|
|
|
$
|
121,864,398
|
|
$0.25 - 0.57
|
|
|
760,000
|
|
|
|
3.29
|
|
|
$
|
0.34
|
|
|
$
|
36,025,200
|
|
$1.49 - 2.61
|
|
|
1,355,000
|
|
|
|
4.21
|
|
|
$
|
1.90
|
|
|
$
|
62,109,550
|
|
$3.91 - 4.43
|
|
|
657,500
|
|
|
|
5.36
|
|
|
$
|
4.40
|
|
|
$
|
28,498,425
|
|
$4.83 - 7.10
|
|
|
856,600
|
|
|
|
6.36
|
|
|
$
|
5.05
|
|
|
$
|
36,569,320
|
|
$11.68 - 24.21
|
|
|
1,298,500
|
|
|
|
7.31
|
|
|
$
|
15.89
|
|
|
$
|
41,361,355
|
|
$23.90 - 58.71
|
|
|
1,199,700
|
|
|
|
8.49
|
|
|
$
|
35.93
|
|
|
$
|
15,181,956
|
|
$46.05 - 67.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value in the preceding tables represents
the total pre-tax intrinsic value, based on the Companys
closing stock price of $47.74 on December 31, 2006, which
would have been received by the option holders had all option
holders exercised their options as of that date. The total
number of
in-the-money
options exercisable as of December 31, 2006 was 8,494,800.
The weighted-average grant-date fair value of share options
granted during the year ended December 31, 2006 was
$23.65 per share. The total intrinsic value of share
options exercised during the year ended December 31, 2006
was $28.7 million.
At December 31, 2006, there was $4,875,767 of total
unrecognized compensation cost related to non-vested share-based
compensation arrangements granted under the Stock Incentive
Plans. That cost is expected to be recognized over a weighted
average period of 2.4 years.
PERFORMANCE
SHARE PLANS:
Long-Term
Incentive Plan
In 2005, the Company adopted a Long-Term Incentive Plan
(LTIP) in order to further align the interests of
key employees with shareholders and give key employees the
opportunity to share in the long-term performance of the Company
by achieving specific corporate financial and operational goals.
Under the LTIP, the Compensation Committee establishes certain
performance measures at the beginning of each three-year
overlapping performance period. Performance measures may vary
for performance periods. In the event of a change of control of
the
67
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company all outstanding awards are paid at maximum levels in
cash. The event of a change of control is not currently probable.
Each participant in the LTIP is assigned threshold, target and
maximum award levels that are expressed as a percentage of his
or her base salary. Selected officers, managers and other key
employees are eligible to participate in the LTIP. Participants
are recommended by the CEO and approved by the Compensation
Committee and are assigned to a specific eligibility level. The
participation levels are as follows (the respective percentage
award is calculated based upon the participants base
salary at the beginning of the award period), (i) if
threshold performance objectives are attained, the incentive
award opportunities range from 6% to 38%; (ii) if target
performance objectives are attained, the incentive award
opportunities range from 20% to 125%; and (iii) if maximum
performance objectives are attained, the incentive award
opportunities range from 30% to 188%. The threshold award level
is not the minimum award, but is the award at the threshold
performance level. Awards are expressed as dollar targets and
become payable in common shares issued under the Companys
stock incentive plans at the end of each three-year performance
period based on the overall performance of the Company during
such period. A new three-year period begins each January,
beginning January 1, 2005. Participants must be employed by
the Company at payment date in order to receive an award.
Employees joining the Company after January 1, 2005 will
participate on a pro rata basis based on their length of
employment during the performance period.
The Compensation Committee has established the following
performance measures for the 2005 LTIP and 2006 LTIP: return on
equity, reserve replacement ratio, and production growth. At the
discretion of the Compensation Committee, additional metrics may
be added to individual participants.
For the twelve months ended December 31, 2006, the Company
recognized $736,486 and $747,908 associated with the 2005 LTIP
and 2006 LTIP, respectively. Of the total, $405,068 and $373,951
was recognized in pre-tax compensation expense related to the
2005 LTIP and 2006 LTIP, respectively. The remaining $331,418
and $373,957 associated with the 2005 LTIP and 2006 LTIP,
respectively, was capitalized in Oil and Gas Properties. The
amounts recognized during 2006 assume that maximum performance
objectives are attained. If the Company ultimately attains
maximum performance objectives, the associated total
compensation expense, estimated at December 31, 2006, for
the three year performance periods would be approximately
$2.1 million and $2.2 million (before taxes) related
to the 2005 LTIP and 2006 LTIP, respectively.
Best
in Class
In 2005, the Company also established a Best in Class program
for all full-time employees of the Company, including executive
officers. The purpose of the program is to recognize and
financially reward the collective efforts of all the
Companys employees in achieving sustained industry leading
performance and the enhancement of shareholder value. In the
event of a change of control of the Company all outstanding
awards become 150% vested. The event of a change of control is
not currently probable.
Under the Best in Class program, on January 1, 2005 or the
employment date if subsequent to January 1, 2005, all
employees of the Company received a contingent award of stock
units equal to $50,000 worth of the Companys common stock
based on the average of the high and low share price on the date
of grant. Employees joining the Company after January 1,
2005 will participate on a pro rata basis based on their length
of employment during the performance period. The number of units
that will vest and become payable is based on the Companys
performance relative to the industry during a three-year
performance period beginning January 1, 2005 and ending
December 31, 2007 and are set at threshold (50%), target
(100%) and maximum (150%) levels. For each vested unit, the
participant will receive one share of common stock.
The emphasis of this plan is to recognize and reward the
Companys employees for performance that is recognized in
the industry as clearly outstanding. Performance metrics will be
developed and measured by an accepted third party research
organization. The total vested award will be the sum of the
vesting percentage for each
68
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
metric. The maximum units that may be vested is 150% of the
original award. Performance results will be determined after the
end of the performance period and publication of the applicable
industry reports. A participant must be employed when payments
are made in order to receive an award.
For the year ended December 31, 2006, the Company
recognized $544,168 associated with the Best in
Class Incentive Compensation Program. Of the total,
$290,489 was recognized as pre-tax compensation expense while
the remaining $253,679 was capitalized in Oil and Gas
Properties. The amount recognized during 2006 assumes that
target performance levels are achieved. If the Company
ultimately attains the target performance level, the associated
total compensation expense, estimated at December 31, 2006,
for the entire three year performance period would be
approximately $2.1 million before income taxes.
|
|
7.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
The Companys major market risk exposure is in the pricing
applicable to its natural gas and oil production. Realized
pricing is currently driven primarily by the prevailing price
for the Companys Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable. Pricing volatility is expected
to continue. Natural gas price realizations ranged from a
monthly low of $4.50 per Mcf to a monthly high of
$8.26 per Mcf during 2006. Realized natural gas prices are
derived from the financial statements which include the effects
of hedging and natural gas balancing.
The Company primarily relies on fixed price forward natural gas
sales to manage its commodity price exposure. These fixed price
forward natural gas sales are considered normal sales. The
Company may, from time to time and to a lesser extent, use
derivative instruments as one way to manage its exposure to
commodity prices. The Company has periodically entered into
fixed price to index price swap agreements in order to hedge a
portion of its production. The oil and natural gas reference
prices of these commodity derivatives contracts are based upon
crude oil and natural gas futures, which have a high degree of
historical correlation with actual prices the Company receives.
Under Statement of Financial Accounting Standard No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133), all
derivative instruments are recorded on the balance sheet at fair
value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. For qualifying cash flow hedges,
the gain or loss on the derivative is deferred in accumulated
other comprehensive income (loss) to the extent the hedge is
effective. For qualifying fair value hedges, the gain or loss on
the derivative is offset by related results of the hedged item
in the income statement. Gains and losses on hedging instruments
included in accumulated other comprehensive income (loss) are
reclassified to oil and natural gas sales revenue in the period
that the related production is delivered. Derivative contracts
that do not qualify for hedge accounting treatment are recorded
as derivative assets and liabilities at market value in the
consolidated balance sheet, and the associated unrealized gains
and losses are recorded as current expense or income in the
consolidated statement of operations. The Company currently does
not have any derivative contracts in place that do not qualify
as a cash flow hedge.
The Company to a larger extent utilizes fixed price forward
natural gas sales contracts at southwest Wyoming delivery points
to manage its commodity exposure. At December 31, 2006, the
Company had no open derivative contracts to manage price risk on
its natural gas production. The Company had the following fixed
price physical delivery contracts in place on behalf of its
interest and those of other parties at December 31, 2006.
(The Companys approximate average net interest in physical
gas sales is 80%.)
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
Average
|
|
Contract Period
|
|
MMbtu/Day
|
|
|
Price/MMbtu
|
|
|
April 2007 October 2007
|
|
|
40,000
|
|
|
$
|
6.20
|
|
69
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Subsequent to December 31, 2006 and through
February 26, 2007, the Company has entered into the
following fixed price physical delivery contracts on behalf of
its interest and those of other parties:
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
|
Average
|
|
Contract Period
|
|
MMbtu/Day
|
|
|
Price/MMbtu
|
|
|
Calendar 2008
|
|
|
60,000
|
|
|
$
|
6.63
|
|
|
|
8.
|
SHARE
REPURCHASE PROGRAM:
|
On May 17, 2006, the Company announced that its Board of
Directors authorized a share repurchase program for up to an
aggregate $1 billion of the Companys outstanding
common stock which has been and will be funded by cash on hand
and the Companys senior credit facility. Pursuant to this
authorization, the Company has commenced an initial program to
purchase up to $250.0 million of the Companys
outstanding shares through open market transactions or privately
negotiated transactions.
Ultra Petroleum Corp. (Ultra Petroleum) owns 100% of UP
Energy Corporation (UP Energy), which in turn owns 100% of Ultra
Resources, Inc. (Ultra Resources). Ultra Resources may, from
time to time, repurchase Ultra Petroleum publicly traded stock.
On settlement, the repurchased stock will be transferred to
Ultra Resources. The stock repurchase will be funded with cash
held in an Ultra Resources bank account or the Companys
senior credit facility.
At December 31, 2006, the Company had repurchased
3,969,532 shares of its common stock for an aggregate
$197.6 million at a weighted average price of
$49.77 per share.
Income before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
United States
|
|
$
|
320,034,244
|
|
|
$
|
304,943,491
|
|
|
$
|
153,553,816
|
|
Foreign
|
|
|
52,224,661
|
|
|
|
46,828,841
|
|
|
|
13,606,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
372,258,905
|
|
|
$
|
351,772,332
|
|
|
$
|
167,160,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The consolidated income tax provision is comprised of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal & state
|
|
$
|
26,944,004
|
|
|
$
|
50,636,118
|
|
|
$
|
261,826
|
|
Foreign
|
|
|
18,941,127
|
|
|
|
3,564,990
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal & state
|
|
|
95,178,288
|
|
|
|
57,228,294
|
|
|
|
53,144,257
|
|
Foreign
|
|
|
|
|
|
|
12,042,683
|
|
|
|
4,604,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision
|
|
$
|
141,063,419
|
|
|
$
|
123,472,085
|
|
|
$
|
58,010,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2006 and 2005, the Company realized tax benefits of
$10.5 million and $50.6 million, respectively,
attributable to tax deductions associated with the exercise of
stock options. These benefits reduce the amount of the
Companys U.S. federal and state cash tax payments and
are recorded as a reduction of current taxes payable and as an
increase in shareholders equity.
70
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The income tax provision differs from the amount that would be
computed by applying the U.S. federal income tax rate of
35% to pretax income as a result of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income tax provision computed at
the U.S. statutory rate
|
|
$
|
130,290,617
|
|
|
$
|
123,120,316
|
|
|
$
|
58,506,026
|
|
State income tax provision net of
federal benefit
|
|
|
150,248
|
|
|
|
297,319
|
|
|
|
159,628
|
|
Withholding tax on share
repurchase transactions
|
|
|
10,400,543
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
222,011
|
|
|
|
54,450
|
|
|
|
(655,376
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
141,063,419
|
|
|
$
|
123,472,085
|
|
|
$
|
58,010,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2006, the Company incurred U.S. withholding taxes
totaling $10.4 million in connection with the repurchase of
3,969,532 shares of its common stock. (See Note 8).
The tax effects of temporary differences that give rise to
significant components of the Companys deferred tax assets
and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
U.S. federal tax credit
carryforwards
|
|
$
|
7,101,181
|
|
|
$
|
|
|
Canadian net operating loss
carryforwards
|
|
|
1,474,648
|
|
|
|
1,976,930
|
|
Other, net
|
|
|
1,165,318
|
|
|
|
4,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,741,147
|
|
|
|
1,981,399
|
|
Valuation allowance
|
|
|
(1,474,648
|
)
|
|
|
(1,976,930
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
8,266,499
|
|
|
|
4,469
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(259,191,252
|
)
|
|
|
(155,750,934
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset (liability)
|
|
$
|
(250,924,753
|
)
|
|
$
|
(155,746,465
|
)
|
|
|
|
|
|
|
|
|
|
In assessing the realizability of the deferred tax assets,
management considers whether it is more likely than not that
some or all of the deferred tax assets will not be realized. The
ultimate realization of the deferred tax assets is dependent
upon the generation of future taxable income during the periods
in which the temporary differences become deductible. Among
other items, management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income and
available tax planning strategies.
As of December 31, 2006, the Company had approximately
$6.0 million and $1.1 million of U.S. federal
alternative minimum tax credit and foreign tax carryforwards,
respectively (Tax Credits). The Tax Credits are
available to offset future U.S. income taxes. None of the
Tax Credits expire prior to 2017. The Company has not recorded
any valuation allowance attributable to its Tax Credits as
management estimates that it is more likely than not that the
Tax Credits will be fully utilized before they expire.
As of December 31, 2004, the Company had U.S. federal
regular tax net operating loss carryforwards
(NOLs) of approximately $16.7 million
which were available to offset future U.S. taxable income.
The Company did not record any valuation allowance attributable
to its U.S. NOLs as management estimated that it was
more likely than not that the U.S. NOLs would be
fully utilized before they expired. These U.S. NOLs
were fully utilized to offset U.S. taxable income in 2005.
71
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has Canadian non-capital tax loss carryforwards of
approximately $4.2 million and $5.6 million as of
December 31, 2006 and December 31, 2005, respectively.
The benefit of the Canadian loss carryforwards can only be
utilized to the extent the Company generates future taxable
income in Canada. If not utilized, the Canadian loss
carryforward will expire between 2007 and 2016.
The undistributed earnings of the Companys U.S.
subsidiaries are considered to be indefinitely invested outside
of Canada. Accordingly, no provision for Canadian income taxes
and/or withholding taxes has been provided thereon.
Since the Company currently has no income producing operations
in Canada, management estimates that it is more likely than not
that the Canadian loss carryforwards will not be utilized. A
valuation allowance has been recorded at December 31, 2006
and December 31, 2005 attributable to this deferred tax
asset.
The Company periodically uses derivative instruments designated
as cash flow hedges as a method of managing its exposure to
commodity price fluctuations. To the extent these hedges are
effective, changes in the fair value of these derivative
instruments are recorded in Other Comprehensive Income, net of
income tax. As of December 31, 2006 and December 31,
2005, the Company had no open derivative contracts; and,
therefore, no recorded tax benefit attributable to unrecognized
loss on derivative instruments. A tax benefit attributable to
unrecognized loss on derivative instruments of $1,440,236 was
allocated directly to Other Comprehensive Income as of
December 31, 2004.
The Company sponsors a qualified, tax-deferred savings plan in
accordance with provisions of Section 401(k) of the
Internal Revenue Code for its employees. Employees may defer up
to 15% of their compensation, subject to certain limitations.
The Company matches the employee contributions up to 5% of
employee compensation along with a profit sharing contribution
of 8%. The plan operates on a calendar year basis and began in
February 1998. The expense associated with the Companys
contribution was $709,570, $507,306 and $396,684 for the years
ended December 31, 2006, 2005 and 2004, respectively.
72
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has two reportable operating segments, one domestic
and one foreign, which are in the business of natural gas and
crude oil exploration and production. The accounting policies of
the segments are the same as those described in the summary of
significant accounting policies. The Company evaluates
performance based on profit or loss from oil and natural gas
operations before price-risk management and other, general and
administrative expenses and interest expense. The Companys
reportable operating segments are managed separately based on
their geographic locations. Financial information by operating
segment is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
China
|
|
|
Total
|
|
|
Year-ended December 31,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
508,659,524
|
|
|
$
|
84,008,059
|
|
|
$
|
592,667,583
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
amortization
|
|
|
79,676,165
|
|
|
|
13,822,391
|
|
|
|
93,498,556
|
|
Lease operating expenses
|
|
|
15,067,413
|
|
|
|
8,922,400
|
|
|
|
23,989,813
|
|
Production taxes
|
|
|
57,899,339
|
|
|
|
8,398,473
|
|
|
|
66,297,812
|
|
Gathering
|
|
|
19,721,269
|
|
|
|
|
|
|
|
19,721,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
336,295,338
|
|
|
$
|
52,864,795
|
|
|
$
|
389,160,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
14,935,103
|
|
Other expense, net
|
|
|
|
|
|
|
|
|
|
|
1,966,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
$
|
372,258,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
481,390,936
|
|
|
$
|
22,490,965
|
|
|
$
|
503,881,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
1,006,997,502
|
|
|
$
|
112,370,594
|
|
|
$
|
1,119,368,096
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
China
|
|
|
Total
|
|
|
Year-ended December 31,
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
448,730,965
|
|
|
$
|
67,762,036
|
|
|
$
|
516,493,001
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
amortization
|
|
|
48,455,070
|
|
|
|
9,647,801
|
|
|
|
58,102,871
|
|
Lease operating expenses
|
|
|
9,047,390
|
|
|
|
7,352,000
|
|
|
|
16,399,390
|
|
Production taxes
|
|
|
52,689,060
|
|
|
|
3,388,089
|
|
|
|
56,077,149
|
|
Gathering
|
|
|
17,125,147
|
|
|
|
|
|
|
|
17,125,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
321,414,298
|
|
|
$
|
47,374,146
|
|
|
$
|
368,788,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
14,342,178
|
|
Other expense, net
|
|
|
|
|
|
|
|
|
|
|
2,673,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
$
|
351,772,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
263,486,693
|
|
|
$
|
19,181,362
|
|
|
$
|
282,668,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
599,900,713
|
|
|
$
|
102,762,542
|
|
|
$
|
702,663,255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
China
|
|
|
Total
|
|
|
Year-ended December 31,
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
238,866,913
|
|
|
$
|
20,179,534
|
|
|
$
|
259,046,447
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
amortization
|
|
|
27,346,061
|
|
|
|
2,903,000
|
|
|
|
30,249,061
|
|
Lease operating expenses
|
|
|
6,286,715
|
|
|
|
2,286,000
|
|
|
|
8,572,715
|
|
Production taxes
|
|
|
28,151,661
|
|
|
|
1,009,098
|
|
|
|
29,160,759
|
|
Gathering
|
|
|
13,135,809
|
|
|
|
|
|
|
|
13,135,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
163,946,667
|
|
|
$
|
13,981,436
|
|
|
$
|
177,928,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
7,075,720
|
|
Other expense, net
|
|
|
|
|
|
|
|
|
|
|
3,692,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
$
|
167,160,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
179,592,969
|
|
|
$
|
16,005,515
|
|
|
$
|
195,598,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
381,408,507
|
|
|
$
|
93,225,879
|
|
|
$
|
474,634,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.
|
COMMITMENTS
AND CONTINGENCIES:
|
On October 16, 2003 the operator of the Companys
properties in China, Kerr-McGee, signed a 15 year contract,
which provides for up to an additional 10 years, to lease a
floating production storage offloading unit (FPSO).
The Company ratified the contract for its net share which is
8.91%. The FPSO service agreement calls for a day rate lease
payment and a sliding scale per barrel processing fee that
decreases based on cumulative barrels processed. The lease
contains a cancellation fee based on a sliding time-scale
(cancellation fee decreases with time), which as of
December 31, 2006 was $2.7 million, net to the
Companys interest. The Company considers it very unlikely
that a lease cancellation situation will occur. Due to the terms
of the lease, the Company cannot estimate with any degree of
accuracy the costs it may incur during the life of the lease.
The Companys net share for the costs of the FPSO in 2006
was approximately $3.2 million.
In May 2003, the Company amended its prior office lease in
Englewood, Colorado, which it has committed to through June
2008. The Companys total remaining commitment of this
lease is $504,769 at December 31, 2006 ($333,359 in 2007
and $171,410 in 2008). In December 2003, the Company signed a
lease for office space in Houston, Texas, which it has committed
to through April 2007 for a total remaining commitment at
December 31, 2006 of $33,948. At December 31, 2006,
the remaining commitment on the Companys Pinedale office
is $97,440 ($41,040 in 2007, $33,840 in 2008 and $22,560 in
2009). The total remaining commitment for all offices is
$636,157.
As of December 31, 2006, the Company had committed to
drilling obligations with certain rig contractors totaling
$136,990,625 ($74,848,535 due in 2007 and the remaining
$62,142,090 due in one to three years). The commitments expire
in 2009 and were entered into to fulfill the Companys
2006-2009
drilling program initiatives in Wyoming.
During 2006, the Company took a major step toward assuring that
the pipeline infrastructure to move its natural gas supplies
away from southwest Wyoming will be expanded to provide
sufficient capacity to transport its natural gas production and
to provide for reasonable basis differentials for its natural
gas in the future. The Company agreed to become an anchor
shipper on the proposed Rockies Express Pipeline project,
sponsored by subsidiaries of Kinder Morgan, Conoco Phillips, and
Sempra Energy. The Rockies Express Pipeline, if built as
proposed, would be the largest natural gas transmission pipeline
project of its type built in the United States in more than
20 years, beginning at the Opal Processing Plant in
southwest Wyoming and traversing Wyoming and several
74
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
other states to an ultimate terminus in eastern Ohio. This
pipeline is projected to cover more than 1,800 miles and is
contemplated to be a large-diameter (42), high-pressure
natural gas pipeline. The Rockies Express Pipeline, if built,
will be an interstate pipeline and would therefore be subject to
the jurisdiction of the United States Federal Energy Regulatory
Commission (FERC).
On December 19, 2005, the Company entered into two
Precedent Agreements (Precedent Agreements) with
Rockies Express Pipeline, LLC (REX) and Entrega Gas
Pipeline, LLC. The Precedent Agreements govern the parties
through the design, regulatory process and construction of the
pipeline facilities and, subject to certain conditions
precedent, the Company will take firm transportation service, if
and when the pipeline facilities are constructed. Commencing
upon completion of the pipeline facilities, the Companys
commitment involves capacity of 200,000 MMBtu per day of
natural gas for a term of 10 years, and the Company will be
obligated to pay to REX certain demand charges related to its
rights to hold this firm transportation capacity as an anchor
shipper. Based on current assumptions, current projections
regarding the cost of the expansion and the participation of
other shippers in the expansion (noting specifically that these
assumptions are likely to change materially), the Company
currently projects that annual demand charges due may be
approximately $70.0 million per year for the term of the
contract, exclusive of fuel and surcharges. The Companys
Board of Directors approved the Precedent Agreements on
February 6, 2006 and Kinder Morgan, as the managing member
of REX advised the Company of their final approval of the
Precedent Agreements, and their intent to proceed with the
construction of the Rockies Express Pipeline on
February 28, 2006.
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, management, after consultation with legal counsel, is
of the opinion that the final resolution of all such currently
pending or threatened litigation is not likely to have a
material adverse effect on the consolidated financial position,
results of operations or cash flows of the Company.
|
|
13.
|
FAIR
VALUE OF FINANCIAL INSTRUMENTS:
|
For certain of the Companys financial instruments,
including accounts receivable, notes receivable, accounts
payable and accrued liabilities, the carrying amounts
approximate fair value due to the immediate or short-term
maturity of these financial instruments. The Companys long
term debt is comprised of senior bank debt which bears interest
at floating rates. Accordingly, the carrying value of the
Companys senior bank debt approximated fair value at
December 31, 2006.
|
|
14.
|
SIGNIFICANT
CUSTOMERS:
|
The Companys revenues are derived principally from
uncollateralized sales to customers in the natural gas and oil
industry. The concentration of credit risk in a single industry
affects the Companys overall exposure to credit risk
because customers may be similarly affected by changes in
economic and other conditions. In 2006, the Company had one
significant customer for its CFD Chinese crude oil
CNOOC, and three significant customers for its natural gas
production Southern California Gas Company, J. Aron
(Goldman Sachs), and Sempra Energy Trading. A significant
customer is defined as one that individually accounts for 10% or
more of the Companys total natural gas or oil sales during
2006.
75
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
15.
|
SUMMARIZED
QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before
|
|
|
Income
|
|
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
Income Tax
|
|
|
Tax
|
|
|
Net
|
|
|
Earnings
|
|
|
Earnings
|
|
|
|
Revenues
|
|
|
Expenses
|
|
|
Provision
|
|
|
Provision
|
|
|
Income
|
|
|
per Share
|
|
|
per Share
|
|
|
|
(In thousands, except for per share data)
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
151,250
|
|
|
$
|
47,284
|
|
|
$
|
103,966
|
|
|
$
|
36,492
|
|
|
$
|
67,474
|
|
|
$
|
0.43
|
|
|
$
|
0.41
|
|
Second Quarter
|
|
$
|
129,892
|
|
|
$
|
45,959
|
|
|
$
|
83,933
|
|
|
$
|
33,258
|
|
|
$
|
50,675
|
|
|
$
|
0.33
|
|
|
$
|
0.31
|
|
Third Quarter
|
|
$
|
145,366
|
|
|
$
|
56,561
|
|
|
$
|
88,805
|
|
|
$
|
36,330
|
|
|
$
|
52,475
|
|
|
$
|
0.34
|
|
|
$
|
0.33
|
|
Fourth Quarter
|
|
$
|
166,160
|
|
|
$
|
70,605
|
|
|
$
|
95,555
|
|
|
$
|
34,983
|
|
|
$
|
60,571
|
|
|
$
|
0.40
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
592,668
|
|
|
$
|
220,409
|
|
|
$
|
372,259
|
|
|
$
|
141,063
|
|
|
$
|
231,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
89,364
|
|
|
$
|
31,857
|
|
|
$
|
57,507
|
|
|
$
|
20,185
|
|
|
$
|
37,322
|
|
|
$
|
0.25
|
|
|
$
|
0.23
|
|
Second Quarter
|
|
$
|
110,635
|
|
|
$
|
36,848
|
|
|
$
|
73,787
|
|
|
$
|
25,899
|
|
|
$
|
47,888
|
|
|
$
|
0.31
|
|
|
$
|
0.30
|
|
Third Quarter
|
|
$
|
134,378
|
|
|
$
|
40,618
|
|
|
$
|
93,760
|
|
|
$
|
32,910
|
|
|
$
|
60,850
|
|
|
$
|
0.40
|
|
|
$
|
0.38
|
|
Fourth Quarter
|
|
$
|
182,116
|
|
|
$
|
55,398
|
|
|
$
|
126,718
|
|
|
$
|
44,478
|
|
|
$
|
82,240
|
|
|
$
|
0.53
|
|
|
$
|
0.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
516,493
|
|
|
$
|
164,721
|
|
|
$
|
351,772
|
|
|
$
|
123,472
|
|
|
$
|
228,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16.
|
DISCLOSURE
ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
|
The following information about the Companys oil and
natural gas producing activities is presented in accordance with
Financial Accounting Standards Board Statement No. 69,
Disclosure About Oil and Gas Producing Activities:
A. OIL
AND GAS RESERVES:
The determination of oil and natural gas reserves is complex and
highly interpretive. Assumptions used to estimate reserve
information may significantly increase or decrease such reserves
in future periods. The estimates of reserves are subject to
continuing changes and, therefore, an accurate determination of
reserves may not be possible for many years because of the time
needed for development, drilling, testing, and studies of
reservoirs. The following unaudited tables as of
December 31, 2006, 2005 and 2004 are based upon estimates
prepared by Netherland, Sewell & Associates, Inc. and
Ryder Scott Company. The estimates for properties in the United
States were prepared by Netherland, Sewell &
Associates, Inc. in reports dated January 30, 2007,
January 27, 2006 and January 24, 2005, respectively.
The estimates for properties in China were prepared by Ryder
Scott Company in reports dated January 30, 2007,
January 31, 2006, and February 11, 2005. These are
estimated quantities of proved oil and natural gas reserves for
the Company and the changes in total proved reserves as of
December 31, 2006, 2005 and 2004. All such reserves are
located in the Green River Basin, Wyoming, Pennsylvania and
Bohai Bay, China.
76
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
B. ANALYSES
OF CHANGES IN PROVEN RESERVES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
China
|
|
|
Total
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural Gas
|
|
|
|
Oil (Bbls)
|
|
|
(Mcf)
|
|
|
Oil (Bbls)
|
|
|
Gas (Mcf)
|
|
|
Oil (Bbls)
|
|
|
(Mcf)
|
|
|
Reserves, December 31, 2003
|
|
|
8,342,500
|
|
|
|
1,023,367,300
|
|
|
|
|
|
|
|
|
|
|
|
8,342,500
|
|
|
|
1,023,367,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and
additions
|
|
|
4,520,000
|
|
|
|
562,548,000
|
|
|
|
8,180,900
|
|
|
|
|
|
|
|
12,700,900
|
|
|
|
562,548,000
|
|
Production
|
|
|
(349,700
|
)
|
|
|
(43,667,400
|
)
|
|
|
(624,560
|
)
|
|
|
|
|
|
|
(943,000
|
)
|
|
|
(43,667,400
|
)
|
Revisions
|
|
|
(1,123,700
|
)(1)
|
|
|
(128,247,300
|
)(2)
|
|
|
31,228
|
|
|
|
|
|
|
|
(1,123,700
|
)
|
|
|
(128,247,300
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2004
|
|
|
11,389,100
|
|
|
|
1,414,000,600
|
|
|
|
7,587,600
|
|
|
|
|
|
|
|
18,976,700
|
|
|
|
1,414,000,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and
additions
|
|
|
5,516,300
|
|
|
|
680,671,500
|
|
|
|
370,600
|
|
|
|
|
|
|
|
5,886,900
|
|
|
|
680,671,500
|
|
Production
|
|
|
(464,300
|
)
|
|
|
(61,722,300
|
)
|
|
|
(1,556,300
|
)
|
|
|
|
|
|
|
(2,020,600
|
)
|
|
|
(61,722,300
|
)
|
Revisions
|
|
|
(1,236,400
|
)(3)
|
|
|
(132,727,000
|
)(4)
|
|
|
(1,341,000
|
)
|
|
|
|
|
|
|
(2,577,400
|
)
|
|
|
(132,727,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2005
|
|
|
15,204,700
|
|
|
|
1,900,222,800
|
|
|
|
5,060,900
|
|
|
|
|
|
|
|
20,265,600
|
|
|
|
1,900,222,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and
additions
|
|
|
3,962,000
|
|
|
|
505,773,000
|
|
|
|
|
|
|
|
|
|
|
|
3,962,000
|
|
|
|
505,773,000
|
|
Production
|
|
|
(594,100
|
)
|
|
|
(78,395,500
|
)
|
|
|
(1,603,400
|
)
|
|
|
|
|
|
|
(2,197,500
|
)
|
|
|
(78,395,500
|
)
|
Revisions
|
|
|
(730,000
|
)(5)
|
|
|
(69,499,600
|
)(6)
|
|
|
529,200
|
|
|
|
|
|
|
|
(200,800
|
)
|
|
|
(69,499,600
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2006
|
|
|
17,842,600
|
|
|
|
2,258,100,700
|
|
|
|
3,986,700
|
|
|
|
|
|
|
|
21,829,300
|
|
|
|
2,258,100,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2003
|
|
|
3,028,000
|
|
|
|
359,072,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
359,072,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004
|
|
|
4,195,000
|
|
|
|
514,686,000
|
|
|
|
4,356,000
|
|
|
|
|
|
|
|
8,551,000
|
|
|
|
514,686,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
5,087,000
|
|
|
|
635,591,000
|
|
|
|
2,484,000
|
|
|
|
|
|
|
|
7,571,000
|
|
|
|
635,591,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
6,522,000
|
|
|
|
842,969,000
|
|
|
|
2,686,000
|
|
|
|
|
|
|
|
9,208,000
|
|
|
|
842,969,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revision amount of 936,500 attributable to 40 wells dropped
from PUD category replaced by more attractive wells. |
|
(2) |
|
Revision amount of 117,064,000 associated with above 40
mentioned wells. |
|
(3) |
|
Revision amount of 412,500 attributable to 26 wells dropped
from PUD category replaced by more attractive wells. |
|
(4) |
|
Revision amount of 51,560,000 associated with above mentioned
26 wells. |
|
(5) |
|
Revision amount of 460,000 attributable to 28 wells dropped
from PUD category replaced by more attractive wells. |
|
(6) |
|
Revision amount of 57,489,000 associated with above mentioned
28 wells. |
77
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
C. STANDARDIZED
MEASURE (US$000):
The following table sets forth a standardized measure of the
estimated discounted future net cash flows attributable to the
Companys proved natural gas reserves. Natural gas prices
have fluctuated widely in recent years. The calculated weighted
average sales prices utilized for the purposes of estimating the
Companys proved reserves and future net revenues were
$4.50, $8.00, and $5.46 per Mcf of natural gas at
December 31, 2006, 2005 and 2004, respectively. The
calculated weighted average oil price at December 31, 2006,
2005, and 2004 for Wyoming was $59.95, $60.81 and $42.80,
respectively and $5.51 per Mcf at December 31, 2006 in
Pennsylvania. The calculated weighted average crude oil price at
December 31, 2006, 2005 and 2004 for China was a Duri price
of $46.57, $48.74 and $29.46, respectively. The future
production and development costs represent the estimated future
expenditures to be incurred in developing and producing the
proved reserves, assuming continuation of existing economic
conditions. Future income tax expense was computed by applying
statutory income tax rates to the difference between pretax net
cash flows relating to the Companys proved reserves and
the tax basis of proved properties and available operating loss
carryovers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
China
|
|
|
Total
|
|
|
As of December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
8,213,061
|
|
|
$
|
223,531
|
|
|
$
|
8,436,592
|
|
Future production costs
|
|
|
(1,699,891
|
)
|
|
|
(67,387
|
)
|
|
|
(1,767,278
|
)
|
Future development costs
|
|
|
(623,539
|
)
|
|
|
(18,382
|
)
|
|
|
(641,921
|
)
|
Future income taxes
|
|
|
(1,988,387
|
)
|
|
|
(21,436
|
)
|
|
|
(2,009,823
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
3,901,244
|
|
|
|
116,326
|
|
|
|
4,017,570
|
|
Discounted at 10%
|
|
|
(2,285,779
|
)
|
|
|
(62,455
|
)
|
|
|
(2,348,234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
1,615,465
|
|
|
$
|
53,871
|
|
|
$
|
1,669,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
16,124,248
|
|
|
$
|
246,666
|
|
|
$
|
16,370,914
|
|
Future production costs
|
|
|
(2,943,364
|
)
|
|
|
(72,920
|
)
|
|
|
(3,016,284
|
)
|
Future development costs
|
|
|
(1,113,618
|
)
|
|
|
(6,815
|
)
|
|
|
(1,120,433
|
)
|
Future income taxes
|
|
|
(4,110,554
|
)
|
|
|
(30,235
|
)
|
|
|
(4,140,789
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
7,956,712
|
|
|
|
136,696
|
|
|
|
8,093,408
|
|
Discounted at 10%
|
|
|
(4,454,628
|
)
|
|
|
(62,286
|
)
|
|
|
(4,516,914
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
3,502,084
|
|
|
$
|
74,410
|
|
|
$
|
3,576,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
11,239,526
|
|
|
$
|
185,659
|
|
|
$
|
11,425,185
|
|
Future production costs
|
|
|
(2,974,427
|
)
|
|
|
(67,750
|
)
|
|
|
(3,042,177
|
)
|
Future development costs
|
|
|
(1,674,893
|
)
|
|
|
(5,915
|
)
|
|
|
(1,680,808
|
)
|
Future income taxes
|
|
|
(2,217,709
|
)
|
|
|
(6,710
|
)
|
|
|
(2,224,419
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
4,372,497
|
|
|
|
105,284
|
|
|
|
4,477,781
|
|
Discounted at 10%
|
|
|
(2,587,417
|
)
|
|
|
(18,811
|
)
|
|
|
(2,606,228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
1,785,080
|
|
|
$
|
86,473
|
|
|
$
|
1,871,553
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimate of future income taxes is based on the future net
cash flows from proved reserves adjusted for the tax basis of
the oil and gas properties but without consideration of general
and administrative and interest expenses.
78
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
D.
|
SUMMARY
OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS (US$000):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Standardized measure, beginning
|
|
$
|
3,576,494
|
|
|
$
|
1,669,336
|
|
|
$
|
1,135,513
|
|
Net revisions
|
|
|
(185,419
|
)
|
|
|
(436,425
|
)
|
|
|
(245,950
|
)
|
Extensions, discoveries and other
changes
|
|
|
755,149
|
|
|
|
2,306,982
|
|
|
|
1,062,236
|
|
Changes in future development costs
|
|
|
(193,004
|
)
|
|
|
(130,727
|
)
|
|
|
(123,051
|
)
|
Sales of oil and gas, net of
production costs
|
|
|
(482,659
|
)
|
|
|
(426,891
|
)
|
|
|
(216,670
|
)
|
Net change in prices and
production costs
|
|
|
(2,915,081
|
)
|
|
|
1,992,707
|
|
|
|
2,645
|
|
Development costs incurred during
the period that reduce future development costs
|
|
|
243,933
|
|
|
|
172,962
|
|
|
|
96,220
|
|
Accretion of discount
|
|
|
544,558
|
|
|
|
254,236
|
|
|
|
178,431
|
|
Net changes in production rates
and other
|
|
|
(395,071
|
)
|
|
|
|
|
|
|
|
|
Net change in income taxes
|
|
|
922,653
|
|
|
|
(1,825,686
|
)
|
|
|
(220,038
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, ending
|
|
$
|
1,871,553
|
|
|
$
|
3,576,494
|
|
|
$
|
1,669,336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There are numerous uncertainties inherent in estimating
quantities of proved reserves and projected future rates of
production and timing of development expenditures, including
many factors beyond the control of the Company. The reserve data
and standardized measures set forth herein represent only
estimates. Reserve engineering is a subjective process of
estimating underground accumulations of oil and natural gas that
cannot be measured in an exact way and the accuracy of any
reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers often vary. In
addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such
estimates. Accordingly, reserve estimates are often different
from the quantities of oil and natural gas that are ultimately
recovered. Further, the estimated future net revenues from
proved reserves and the present value thereof are based upon
certain assumptions, including geologic success, prices, future
production levels and costs that may not prove correct over
time. Predictions of future production levels are subject to
great uncertainty, and the meaningfulness of such estimates is
highly dependent upon the accuracy of the assumptions upon which
they are based. Historically, oil and natural gas prices have
fluctuated widely.
|
|
E.
|
COSTS
INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES
(US$000):
|
UNITED
STATES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Acquisition costs
unproved properties
|
|
$
|
11,351
|
|
|
$
|
775
|
|
|
$
|
1,268
|
|
Exploration
|
|
|
152,922
|
|
|
|
56,894
|
|
|
|
97,068
|
|
Development
|
|
|
317,118
|
|
|
|
208,173
|
|
|
|
82,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
481,391
|
|
|
$
|
265,842
|
|
|
$
|
180,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
CHINA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Acquisition costs
unproved properties
|
|
$
|
7,152
|
|
|
$
|
2,876
|
|
|
$
|
2,351
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
15,339
|
|
|
|
16,465
|
|
|
|
12,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
22,491
|
|
|
$
|
19,341
|
|
|
$
|
15,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Acquisition costs
unproved properties
|
|
$
|
18,503
|
|
|
$
|
3,651
|
|
|
$
|
3,619
|
|
Exploration
|
|
|
152,922
|
|
|
|
56,894
|
|
|
|
97,068
|
|
Development
|
|
|
332,457
|
|
|
|
224,638
|
|
|
|
95,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
503,882
|
|
|
$
|
285,183
|
|
|
$
|
195,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F. RESULTS
OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
(US$000):
UNITED
STATES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Oil and gas revenue
|
|
$
|
508,660
|
|
|
$
|
448,731
|
|
|
$
|
238,867
|
|
Production expenses and taxes
|
|
|
(92,688
|
)
|
|
|
(78,861
|
)
|
|
|
(47,574
|
)
|
Depletion and depreciation
|
|
|
(79,676
|
)
|
|
|
(48,456
|
)
|
|
|
(27,346
|
)
|
Income taxes
|
|
|
(111,722
|
)
|
|
|
(107,916
|
)
|
|
|
(53,406
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
224,574
|
|
|
$
|
213,498
|
|
|
$
|
110,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHINA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Oil and gas revenue
|
|
$
|
84,008
|
|
|
$
|
67,762
|
|
|
$
|
20,180
|
|
Production expenses and taxes
|
|
|
(17,321
|
)
|
|
|
(10,740
|
)
|
|
|
(3,295
|
)
|
Depletion and depreciation
|
|
|
(13,822
|
)
|
|
|
(9,648
|
)
|
|
|
(2,903
|
)
|
Income taxes
|
|
|
(18,941
|
)
|
|
|
(15,556
|
)
|
|
|
(4,604
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
33,924
|
|
|
$
|
31,818
|
|
|
$
|
9,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80
ULTRA
PETROLEUM CORP
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
TOTAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Oil and gas revenue
|
|
$
|
592,668
|
|
|
$
|
516,493
|
|
|
$
|
259,047
|
|
Production expenses and taxes
|
|
|
(110,009
|
)
|
|
|
(89,601
|
)
|
|
|
(50,869
|
)
|
Depletion and depreciation
|
|
|
(93,498
|
)
|
|
|
(58,104
|
)
|
|
|
(30,249
|
)
|
Income taxes
|
|
|
(130,663
|
)
|
|
|
(123,472
|
)
|
|
|
(58,010
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
258,498
|
|
|
$
|
245,316
|
|
|
$
|
119,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G. CAPITALIZED
COSTS RELATING TO OIL AND GAS PRODUCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment,
exploration, drilling and environmental costs
Domestic
|
|
$
|
1,174,683,088
|
|
|
$
|
700,425,880
|
|
Acquisition, equipment,
exploration, drilling and environmental costs China
|
|
|
96,873,985
|
|
|
|
43,890,413
|
|
Less accumulated depletion,
depreciation and amortization Domestic
|
|
|
(196,683,521
|
)
|
|
|
(118,172,467
|
)
|
Less accumulated depletion,
depreciation and amortization China
|
|
|
(26,565,809
|
)
|
|
|
(13,183,036
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,048,307,743
|
|
|
|
612,960,790
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration
costs Domestic
|
|
|
28,997,935
|
|
|
|
17,647,300
|
|
Acquisition and exploration
costs China
|
|
|
42,062,418
|
|
|
|
72,055,165
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,119,368,096
|
|
|
$
|
702,663,255
|
|
|
|
|
|
|
|
|
|
|
81
|
|
Item 9.
|
Change
in and Disagreements with Accountants on Accounting and
Financial Disclosures.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Managements
Report on Assessment of Internal Control Over Financial
Reporting
Management is responsible for establishing and maintaining
adequate internal control over financial reporting for the
Company as such term is defined in
Rules 13a-15(f)
and
15d-15(f)
promulgated under the Securities Exchange Act of 1934, as
amended (the Exchange Act). In order to evaluate the
effectiveness of internal control over financial reporting, as
required by Section 404 of the Sarbanes-Oxley Act,
management has conducted an assessment of the effectiveness of
the Companys internal control over financial reporting as
of December 31, 2006, using the criteria in Internal
Control Integrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO). 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.
Based on the results of this assessment, management (including
our chief executive officer and our chief financial officer) has
concluded that, as of December 31, 2006, our internal
control over financial reporting was effective.
Managements assessment of the effectiveness of the
Companys internal control over financial reporting as of
December 31, 2006 has been audited by Ernst &
Young, an independent registered public accounting firm, as
stated in their report which appears herein.
Remediation
of Material Weakness
In connection with the preparation of the Companys Annual
Report on
Form 10-K
for the year ended December 31, 2005 (2005
10-K),
an evaluation was performed under the supervision and with the
participation of the Companys management, including the
chief executive officer and the chief financial officer, of the
effectiveness of the design and operation of the Companys
disclosure controls and procedures. The Company concluded that
control deficiencies in its internal control over financial
reporting as of December 31, 2005, constituted material
weaknesses within the meaning of the Public Company Accounting
Oversight Boards Auditing Standard No. 2 as follows:
|
|
|
|
|
The Company did not maintain effective company level controls.
Specifically, (i) certain of its accounting personnel in
key roles did not possess an appropriate level of technical
expertise, and (ii) the Companys monitoring of the
internal audit function was not sufficient to provide management
a basis to assess the quality of the Companys internal
control performance over time. These deficiencies resulted in
more than a remote likelihood that a material misstatement of
the Companys annual or interim financial statements would
not be prevented or detected.
|
|
|
|
The Company did not have adequate policies and procedures
regarding supervisory review of account reconciliations and
account and transaction analyses. This deficiency resulted in
material errors (as reported in the 2005
10-K) which
were corrected prior to the issuance of the Companys 2005
consolidated financial statements.
|
|
|
|
The Company did not have adequate policies and procedures to
ensure that accurate and reliable interim and annual
consolidated financial statements were prepared and reviewed on
a timely basis. Specifically, the Company did not have
sufficient personnel with the skills and experience in the
application of U.S. generally accepted accounting
principles and policies and procedures regarding the preparation
and management review of footnote disclosures accompanying the
Companys financial statements. As a result of these
deficiencies, material errors were identified in the footnotes
to the Companys preliminary 2005 consolidated financial
statements. These errors were corrected by management prior to
the issuance of the Companys 2005 consolidated financial
statements.
|
82
For additional information relating to the control deficiencies
that resulted in the material weakness described above, please
see the discussion under Item 9A. Controls and
Procedures Managements Report on Internal
Control Over Financial Reporting contained in the 2005
10-K and
Item 4. Controls and Procedures contained in
our reports on
Form 10-Q
for the periods ended March 30, June 30, and
September 30, 2006, respectively.
During 2006, we implemented a number of remediation measures to
address the material weakness described above. As described in
our 2005
10-K, the
Companys remediation plans included:
|
|
|
|
|
increasing training for the Companys current accounting
personnel, hiring additional accounting personnel and engaging
outside consultants with technical accounting expertise, as
needed, and reorganizing the accounting department to ensure
that accounting personnel have adequate experience, skills and
knowledge relating to the accounting and internal audit
functions assigned to them; and
|
|
|
|
establishing additional and refining current policies and
procedures to more effectively reconcile the Companys
accounting entries along with better documentation procedures to
meet the standards established by COSO.
|
In order to remediate the material weaknesses described in the
2005 10-K,
during 2006 the Company:
|
|
|
|
|
implemented an internal review and assessment process regarding
its financial reporting and internal audit functions;
|
|
|
|
engaged Protiviti to (1) review and assess current
Sarbanes-Oxley processes and control documentation and
compliance plans, (2) recommend remediation and project
plans for 2006, and (3) assist management with
Sarbanes-Oxley compliance requirements during 2006;
|
|
|
|
engaged Grant Thornton LLP to assist in identifying and
recommending any necessary organization and procedural changes
for improving the Companys controls for the purposes of
complying with Sarbanes-Oxley;
|
|
|
|
increased training and hired additional accounting personnel;
|
|
|
|
acted on the recommendations of Protiviti and Grant Thornton LLP;
|
|
|
|
effected a reorganization and alignment of the Companys
financial reporting and internal audit functions;
|
|
|
|
established additional policies and procedures for monitoring
and reconciling the Companys accounting entries; and
|
|
|
|
established better documentation procedures to more fully comply
with the standards established by COSO.
|
Changes
in Internal Control Over Financial Reporting
While the planned remediation steps were designed and in place
by the end of the 3rd quarter of 2006, management continued
to evaluate the operating effectiveness through the end of
fiscal year 2006 when it was concluded that the Companys
internal control over financial reporting was sufficiently
mature to support an assessment that the controls were
effective. There were no changes in our internal control over
financial reporting during the quarter ended December 31,
2006 that materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
Evaluation
of Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our
management, including our chief executive officer and our chief
financial officer, we evaluated the effectiveness of our
disclosure controls and procedures, as such term is defined
under
Rule 13a-15(e)
and
Rule 15d-15(e)
promulgated under the Exchange Act. Based on that evaluation,
our chief executive officer and our chief financial officer
concluded that our disclosure controls and procedures were
effective as of December 31, 2006. The evaluation
considered the procedures designed to ensure that information
required to be disclosed by us in the reports filed or submitted
by us under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified in the SECs
rules and forms and communicated to our management as
appropriate to allow timely decisions regarding required
disclosure.
83
|
|
Item 9B.
|
Other
Information.
|
None.
Part III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2006.
The Company has adopted a code of ethics that applies to the
Companys Chief Executive Officer, Chief Financial Officer
and Chief Accounting Officer. The full text of such code of
ethics is posted on the Companys website at
www.ultrapetroleum.com, and is available free of charge in print
to any shareholder who requests it. Requests for copies should
be addressed to the Secretary at 363 North Sam Houston Parkway
East, Suite 1200, Houston, Texas 77060.
|
|
Item 11.
|
Executive
Compensation.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2006.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
The information required by Item 403 of
Regulation S-K
will be included in the Companys definitive proxy
statement, which will be filed not later than 120 days
after December 31, 2006 and is incorporated herein by
reference.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2006.
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2006.
Part IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules.
|
The following documents are filed as part of this report:
1. Financial Statements: See Item 8.
2. Financial Statement Schedules: None.
3. Exhibits. The following Exhibits are
filed herewith pursuant to Rule 601 of the
Regulation S-K
or are incorporated by reference to previous filings.
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.1
of the Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.2 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
84
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
4
|
.1
|
|
Specimen Common Share Certificate
(incorporated by reference to Exhibit 4.1 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
|
10
|
.1
|
|
Fourth Amendment to Second Amended
and Restated Credit Agreement, dated as of November 14,
2005 and effective as of November 18, 2005, by and among
Ultra Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of
California N.A., Hibernia National Bank, Guaranty Bank FSB,
Compass Bank, Bank of Scotland and Bank of America, N.A.
(incorporated by reference to Exhibit 10.1 of the
Companys Report on
Form 8-K
filed on November 23, 2005).
|
|
10
|
.2
|
|
Third Amendment to Second Amended
and Restated Credit Agreement dated May 5, 2005 among Ultra
Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of
California N.A., Hibernia National Bank, Guaranty Bank FSB,
Compass Bank, Bank of Scotland and Bank of America, N.A.
(incorporated by reference to Exhibit 10.1 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2005).
|
|
10
|
.3
|
|
Second Amendment to Second Amended
and Restated Credit Agreement dated November 1, 2004 among
Ultra Resources, Inc., Bank One, NA, Union Bank of California,
N.A., Hibernia National Bank, Guaranty Bank, FSB, Compass Bank,
Bank of Scotland and Fleet National Bank. (incorporated by
reference to Exhibit 10.1 of the Companys Report on
Form 10-K
for the year ended December 31, 2004).
|
|
10
|
.4
|
|
First Amendment to Second Amended
and Restated Credit Agreement dated August 10, 2004 among
Ultra Resources, Inc., Bank One, NA, Union Bank of California,
N.A., Hibernia National Bank, Guaranty Bank, FSB, Compass Bank,
Bank of Scotland and Fleet National Bank. (incorporated by
reference to Exhibit 10.2 of the Companys Report on
Form 10-K
for the year ended December 31, 2004).
|
|
10
|
.5
|
|
Second Amended and Restated Credit
Agreement dated June 9, 2004 among Ultra Resources, Inc.,
Bank One, NA, Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and
Fleet National Bank (incorporated by reference to
Exhibit 10.1 of the Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2004).
|
|
10
|
.6
|
|
Precedent Agreement between
Rockies Express Pipeline LLC and Ultra Resources, Inc. dated
December 19, 2005 (incorporated by reference to
Exhibit 10.1 of the Companys Report of
Form 8-K
filed on February 9, 2006).
|
|
10
|
.7
|
|
Precedent Agreement between
Rockies Express Pipeline LLC, Entrega Gas Pipeline LLC and Ultra
Resources, Inc. dated December 19, 2005 (incorporated by
reference to Exhibit 10.2 of the Companys Report on
Form 8-K
filed on February 9, 2006).
|
|
10
|
.8
|
|
Ultra Petroleum Corp. 2005 Stock
Incentive Plan (incorporated by reference to Exhibit 99.1
of the Companys Registration Statement on
Form S-8
(Reg.
No. 333-132443),
filed with the SEC on March 15, 2006).
|
|
10
|
.9
|
|
Ultra Petroleum Corp. 2000 Stock
Incentive Plan (incorporated by reference to Exhibit 99.1
of the Companys Registration Statement on
Form S-8
(Reg.
No. 333-13278),
filed with the SEC on March 15, 2001).
|
|
10
|
.10
|
|
Ultra Petroleum Corp. 1998 Stock
Option Plan (incorporated by reference to Exhibit 99.1 of
the Companys Registration Statement on
Form S-8
(Reg.
No. 333-13342)
filed with the SEC on April 2, 2001).
|
|
10
|
.11
|
|
Employment Agreement between Ultra
Petroleum Corp. and Michael D. Watford dated February 1,
2004 (incorporated by reference from Exhibit 10.11 of the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2005).
|
|
14
|
.1
|
|
Code of Ethics for Chief Executive
Officer and Senior Financial Officers of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.3 of the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
*21
|
.1
|
|
Subsidiaries of the Company.
|
|
*23
|
.1
|
|
Consent of Netherland,
Sewell & Associates, Inc.
|
|
*23
|
.2
|
|
Consent of Ryder Scott Company.
|
|
*23
|
.3
|
|
Consent of Ernst & Young
LLP.
|
|
*23
|
.4
|
|
Consent of KPMG LLP.
|
85
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
*31
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
*31
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
*32
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
*32
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
86
SIGNATURES
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.
ULTRA PETROLEUM CORP.
|
|
|
|
By:
|
/s/ Michael
D. Watford
|
Name: Michael D. Watford
|
|
|
|
Title:
|
Chairman of the Board,
|
Chief Executive Officer, and President
Date: February 26, 2007
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 and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/ Michael
D. Watford
Michael
D. Watford
|
|
Chairman of the Board, Chief
Executive Officer, and President
(principal executive officer)
|
|
February 26, 2007
|
|
|
|
|
|
/s/ Marshall
D. Smith
Marshall
D. Smith
|
|
Chief Financial Officer
(principal financial officer)
|
|
February 26, 2007
|
|
|
|
|
|
/s/ Garland
R. Shaw
Garland
R. Shaw
|
|
Corporate Controller
(principal accounting officer)
|
|
February 26, 2007
|
|
|
|
|
|
/s/ W.
Charles Helton
W.
Charles Helton
|
|
Director
|
|
February 26, 2007
|
|
|
|
|
|
/s/ Stephen
J. McDaniel
Stephen
J. McDaniel
|
|
Director
|
|
February 26, 2007
|
|
|
|
|
|
/s/ Robert
E. Rigney
Robert
E. Rigney
|
|
Director
|
|
February 26, 2007
|
|
|
|
|
|
/s/ James
C. Roe
James
C. Roe
|
|
Director
|
|
February 26, 2007
|
87
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.1
of the Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.2 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
|
4
|
.1
|
|
Specimen Common Share Certificate
(incorporated by reference to Exhibit 4.1 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2001).
|
|
10
|
.1
|
|
Fourth Amendment to Second Amended
and Restated Credit Agreement, dated as of November 14,
2005 and effective as of November 18, 2005, by and among
Ultra Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of
California N.A., Hibernia National Bank, Guaranty Bank FSB,
Compass Bank, Bank of Scotland and Bank of America, N.A.
(incorporated by reference to Exhibit 10.1 of the
Companys Report on
Form 8-K
filed on November 23, 2005).
|
|
10
|
.2
|
|
Third Amendment to Second Amended
and Restated Credit Agreement dated May 5, 2005 among Ultra
Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of
California N.A., Hibernia National Bank, Guaranty Bank FSB,
Compass Bank, Bank of Scotland and Bank of America, N.A.
(incorporated by reference to Exhibit 10.1 of the
Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2005).
|
|
10
|
.3
|
|
Second Amendment to Second Amended
and Restated Credit Agreement dated November 1, 2004 among
Ultra Resources, Inc., Bank One, NA, Union Bank of California,
N.A., Hibernia National Bank, Guaranty Bank, FSB, Compass Bank,
Bank of Scotland and Fleet National Bank. (incorporated by
reference to Exhibit 10.1 of the Companys Report on
Form 10-K
for the year ended December 31, 2004).
|
|
10
|
.4
|
|
First Amendment to Second Amended
and Restated Credit Agreement dated August 10, 2004 among
Ultra Resources, Inc., Bank One, NA, Union Bank of California,
N.A., Hibernia National Bank, Guaranty Bank, FSB, Compass Bank,
Bank of Scotland and Fleet National Bank. (incorporated by
reference to Exhibit 10.2 of the Companys Report on
Form 10-K
for the year ended December 31, 2004).
|
|
10
|
.5
|
|
Second Amended and Restated Credit
Agreement dated June 9, 2004 among Ultra Resources, Inc.,
Bank One, NA, Union Bank of California, N.A., Hibernia National
Bank, Guaranty Bank, FSB, Compass Bank, Bank of Scotland and
Fleet National Bank (incorporated by reference to
Exhibit 10.1 of the Companys Quarterly Report on
Form 10-Q
for the period ended June 30, 2004).
|
|
10
|
.6
|
|
Precedent Agreement between
Rockies Express Pipeline LLC and Ultra Resources, Inc. dated
December 19, 2005 (incorporated by reference to
Exhibit 10.1 of the Companys Report of
Form 8-K
filed on February 9, 2006).
|
|
10
|
.7
|
|
Precedent Agreement between
Rockies Express Pipeline LLC, Entrega Gas Pipeline LLC and Ultra
Resources, Inc. dated December 19, 2005 (incorporated by
reference to Exhibit 10.2 of the Companys Report on
Form 8-K
filed on February 9, 2006).
|
|
10
|
.8
|
|
Ultra Petroleum Corp. 2005 Stock
Incentive Plan (incorporated by reference to Exhibit 99.1
of the Companys Registration Statement on
Form S-8
(Reg.
No. 333-132443),
filed with the SEC on March 15, 2006).
|
|
10
|
.9
|
|
Ultra Petroleum Corp. 2000 Stock
Incentive Plan (incorporated by reference to Exhibit 99.1
of the Companys Registration Statement on
Form S-8
(Reg.
No. 333-13278),
filed with the SEC on March 15, 2001).
|
|
10
|
.10
|
|
Ultra Petroleum Corp. 1998 Stock
Option Plan (incorporated by reference to Exhibit 99.1 of
the Companys Registration Statement on
Form S-8
(Reg.
No. 333-13342)
filed with the SEC on April 2, 2001).
|
|
10
|
.11
|
|
Employment Agreement between Ultra
Petroleum Corp. and Michael D. Watford dated February 1,
2004 (incorporated by reference from Exhibit 10.11 of the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2005).
|
|
14
|
.1
|
|
Code of Ethics for Chief Executive
Officer and Senior Financial Officers of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.3 of the
Companys Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
*21
|
.1
|
|
Subsidiaries of the Company.
|
88
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
*23
|
.1
|
|
Consent of Netherland,
Sewell & Associates, Inc.
|
|
*23
|
.2
|
|
Consent of Ryder Scott Company.
|
|
*23
|
.3
|
|
Consent of Ernst & Young
LLP.
|
|
*23
|
.4
|
|
Consent of KPMG LLP.
|
|
*31
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
*31
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
|
|
*32
|
.1
|
|
Certification of Chief Executive
Officer pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|
*32
|
.2
|
|
Certification of Chief Financial
Officer pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
89