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UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the Fiscal Year ended December 31, 2008 | ||
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to . |
Commission File Number:
001-33614
Ultra Petroleum Corp.
(Exact Name of Registrant as
Specified in Its Charter)
|
Yukon Territory, Canada
(Jurisdiction of Incorporation or Organization) |
N/A (I.R.S. Employer Identification No.) |
|
363 North Sam Houston Parkway East, Suite 1200
Houston, Texas (Address of Principal Executive Offices) |
77060 (Zip Code) |
281-876-0120
(Registrant’s Telephone
Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the
Act:
|
Title of Each Class
|
Name of Each Exchange on Which Registered
|
|
|
Common Shares, without par value
|
New York Stock Exchange |
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 registrant’s
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in
Rule 12b-2
of the Exchange Act. (Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company)
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 $15,086,678,210 as of June 30, 2008 (based on
the last reported sales price of $98.20 of such stock on the New
York Stock Exchange on such date).
As of February 13, 2009, there were 151,232,545 common
shares of the registrant outstanding.
Documents incorporated by reference: The definitive Proxy
Statement for the 2009 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission within
120 days after December 31, 2008, is incorporated by
reference in Part III of this
Form 10-K.
TABLE OF
CONTENTS
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Certain
Definitions
Terms
used to describe quantities of oil and natural gas and
marketing
| • | Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. | |
| • | Bcf — One billion cubic feet of natural gas. | |
| • | Bcfe — One billion cubic feet of natural gas equivalent. | |
| • | 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. | |
| • | BTU — British Thermal Unit. | |
| • | 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. | |
| • | MBbl — One thousand barrels. | |
| • | Mcf — One thousand cubic feet of natural gas. | |
| • | 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. | |
| • | MMBbl — One million barrels of oil or other liquid hydrocarbons. | |
| • | MMcf — One million cubic feet of natural gas. | |
| • | MBOE — One thousand BOE. | |
| • | MMBOE — One million BOE. | |
| • | MMBTU — One million British Thermal Units. |
Terms
used to describe the Company’s interests in wells and
acreage
| • | Gross oil and natural gas wells or acres — The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest. | |
| • | 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. | |
| • | Prospect — A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce. |
Terms
used to assign a present value to the Company’s
reserves
| • | 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 engineer’s 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 cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company’s proved reserves. | |
| • | 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 |
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| 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. |
Terms
used to classify the Company’s 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.
(a) 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.
(b) 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.
(c) 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.
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 Company’s oil
and natural gas properties
| • | 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. |
Terms
used to describe seismic operations
| • | 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 |
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| 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. |
| • | 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. | |
| • | 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
| Item 1. | Business. |
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
Company’s operations are primarily in the Green River Basin
of southwest Wyoming. The Company continually evaluates other
opportunities for the acquisition, exploration and development
of oil and natural gas properties.
Ultra’s current operations are focused on developing and
expanding its position in a tight gas sand trend located in the
Green River Basin in southwest Wyoming. As of December 31,
2008, Ultra owns interests in approximately 121,432 gross
(59,953 net) acres in Wyoming covering approximately
190 square miles. The Company owns an interest in
approximately 984 gross producing wells in this area and is
operator of approximately 50% of the 984 gross wells. The
Company also has an exploration effort underway in Pennsylvania.
Following the acquisition of Pendaries Petroleum Ltd. 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 in Bohai Bay, China. During the third
quarter of 2007, the Company made the decision to dispose of
Sino-American
Energy Corporation, which owned our Bohai Bay assets in China,
in order to focus on our legacy asset in the Pinedale Field in
southwest Wyoming. The reserve volumes sold represented all of
Ultra’s international assets and, previously, were the only
results included in our foreign operating segment. See
Note 11 for further discussion on the completion of the
sale.
The Company also owns interests in 287,745 gross (152,227
net) acres in Pennsylvania. The Company has drilled three deep
test wells in the Marshlands prospect area to date. During the
year ended December 31, 2008, the Company participated in
the drilling of 18 gross (9.63 net) wells on the
Pennsylvania properties. At year end 2008, there was
1.0 gross (0.5 net) exploratory well that commenced during
the year that was actively drilling and 17 gross (9.13 net)
wells that were suspended. After flowback testing, these wells
have been shut-in awaiting further development and pipeline
connection.
The Company’s 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 Company’s website at www.ultrapetroleum.com. To
access the Company’s SEC filings, select
“Financials” under the Investor Relations tab on the
Company’s 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 SEC’s 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 SEC’s website address is www.sec.gov.
Business
Strategy
Green
River Basin, Wyoming
During 2009, 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 in
southwest Wyoming. The Company expects that wells drilled during
2009 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
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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, most of the
Pinedale field is approved by the WOGCC for 16 wells per
160-acre
government quarter section
(10-acre
equivalent). Pilot areas approved for testing of well density of
32 wells per government quarter section
(5-acre
equivalent) continue to be evaluated with additional, newly
approved pilot areas added to the assessment and results
expected during 2009. Current spacing in the Jonah field is
eight 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). All of the Company’s 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.
Pennsylvania
During 2009, the Company plans to complete acquisition of a 3D
seismic survey in the Marshlands area, continue evaluation of
its acreage holding in the area, acquire additional acreage, and
participate in the drilling of additional exploratory wells.
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. The Company’s 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. With the first segment
of the Rockies Express Pipeline, LLC (“REX”)
operational during 2008 (as discussed below), a substantial
portion of the Company’s revenues are determined by market
prices in the midwestern and eastern regions of the United
States. Energy commodity prices in general, and the
Company’s 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 experienced
significant levels of volatility in the pricing for its natural
gas and condensate production during 2008. The Company cannot
predict the market prices for the sale of its natural gas,
condensate, or oil production.
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 use of financial swaps with
financial counterparties the Company believes to be
creditworthy. The Company may elect to hedge additional portions
of its forecasted natural gas production in the future, in much
the same manner as it has done previously. For a more detailed
description of the Company’s hedging activities, see
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk. The Company’s 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 or
greater 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 and prices
(daily, monthly and longer term). Historically, the
Company’s customers were 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. With the first segment of REX operational, the
Company’s customer base expanded to include customers in
the midwestern and eastern regions of the United States.
The sale of the Company’s 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 related to its sale of
natural gas. The Company does not have any outstanding,
uncollectible accounts for its natural gas sales at
December 31, 2008.
The Company has entered into various gathering and processing
agreements with several midstream service providers that gather,
compress and process natural gas owned or controlled by the
Company from its producing wells in the Pinedale Anticline and
Jonah fields in southwest Wyoming. Under these agreements, the
midstream
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service providers have routinely expanded their facility’s
capacities in southwest Wyoming to accommodate growing volumes
from wells in which the Company owns an interest. The Company
has, in recent years, been able to lower some of the gathering
and processing fees for such midstream services with its
midstream service providers, in exchange for committing to these
longer term arrangements. As a result of such negotiations, two
new, large cryogenic gas processing plants have been constructed
in southwest Wyoming. These facilities remove natural gas
liquids from the Company’s gas (and gas of others) making
it sufficient quality to be accepted into the natural gas
transmission pipelines serving the area. One of these facilities
was placed into service in the first quarter of 2007, and
another larger facility was completed and became fully
operational during 2008. The new facilities have added
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. The Company believes that
the capacity of the midstream infrastructure related to its
production will continue to be adequate to allow it to sell
essentially all of its available natural gas production.
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 are beyond the Company’s ability to control or to
predict. These factors include, among others, weather, natural
gas supplies, natural gas demand, and natural gas pipeline
capacity to export gas from the Rockies.
The Rocky Mountain region is typically a net exporter of natural
gas because local natural gas production typically exceeds local
demand for natural gas during non-winter months. As a result,
natural gas production in southwest Wyoming has historically
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” and are
reflective, to some extent, of the costs associated with
transporting the Company’s gas to markets in other regions
or states. The Company has seen significant basis differentials
for its Wyoming production versus the Henry Hub (“Henry
Hub”) NYMEX natural gas futures delivery or pricing
reference point in south Louisiana in the past. This trend
continued in 2008.
In years past, increases in pipeline capacity to transport
production from Rocky Mountain production areas to markets in
the West 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
entirely eliminated the basis differential for natural gas
prices in southwest Wyoming when compared to prices at the Henry
Hub pricing reference point.
This trend of smaller basis differentials and improved wellhead
prices in Wyoming following significant pipeline expansions has
continued with the initiation of service on the REX West
pipeline in early 2008. The prices for the Company’s
Wyoming natural gas production were substantially improved on
both a relative (locational basis adjusted) and real (net price)
basis during the first half of 2008. However, unprecedented
growth in natural gas production from the Rockies and other
fields and basins in North Texas, Louisiana, Oklahoma, and
Arkansas during 2008, coupled with a high utilization of
existing natural gas pipeline export capacity, resulted in
natural gas prices in the Rocky Mountain region at significantly
lower levels during the second half of 2008 as compared to the
first half of 2008. A contraction in industrial demand for
natural gas during this time also contributed to a drop in
prices.
Unplanned hydrostatic testing on a 26 mile segment of the
REX Pipeline in Kansas during September 2008 reduced the export
capacity of the natural gas pipeline grid in Wyoming by
200 MMCFD. The impact to the supply/demand balance of
natural gas in Wyoming as a result of the reduction in pipeline
export capacity (and as a result, spot natural gas prices) was
both immediate and severe. In response to this change in the
supply/demand balance, the Company made voluntary reductions of
100 MMCFD to its gas sales and physically shut-in some
volumes during September and part of October 2008.
The Company has previously and continues to take action to
assure that the pipeline infrastructure to move its natural gas
supplies away from southwest Wyoming is expanded to provide
sufficient capacity to transport its natural gas production and
to provide for reasonable prices for its natural gas in the
future. Previously, the Company agreed to become an anchor
shipper on REX, sponsored by subsidiaries of Kinder Morgan,
Conoco Phillips, and Sempra Energy. The Rockies Express Pipeline
begins at the Opal Processing Plant in southwest Wyoming and
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traverses Wyoming and several other states to an ultimate
terminus in eastern Ohio. This pipeline is ultimately projected
to cover more than 1,800 miles and is designed as a
large-diameter (42”), high-pressure natural gas pipeline.
The Rockies Express Pipeline is an interstate pipeline and is
subject to the jurisdiction of the United States Federal Energy
Regulatory Commission (“FERC”). Commencing upon
completion of the pipeline facilities, the Company’s
commitment involves a capacity of 200 MMBtu per day of
natural gas for a term of 10 years, and the Company is
obligated to pay REX certain demand charges related to its
rights to hold this firm transportation capacity as an anchor
shipper.
The pipeline is being built in two phases: REX — West
(Wyoming to Missouri — in service) and REX —
East (Missouri to Ohio — under construction). The REX
partners have recently updated guidance on the timing for
completion of various portions of REX — East. As of
January 2009, REX has announced that it expects approximately
275 miles of 42” pipeline and five new pipeline
interconnections in eastern Illinois and western Indiana to be
placed into service on or about April 1, 2009. As part of
that same announcement, Kinder Morgan has also indicated that
approximately an additional 169 miles of pipeline and an
additional nine pipeline interconnections in Indiana and western
Ohio will be placed into service on or around June 15,
2009. Kinder Morgan further advised that the balance of the
REX — East pipeline will be available to be placed
into service by November 1, 2009, with an expanded capacity
of 1.8 Bcf per day. The increase in capacity from
1.5 Bcf per day to 1.8 Bcf per day that coincides with
this completion is due to the installation of additional
compressor units at two compressor stations on REX —
West, one of which is located in Wyoming and the other in
Nebraska.
As the REX — East project is completed as contemplated
above, the Company expects that the price that it receives for
its gas which is sold off of the REX — East project
will be sold at prices that will reflect an improvement relative
to the prices that it currently receives for its gas sales at
REX — West, Rockies and Wyoming sales points.
Oil
Marketing
The Company markets its Wyoming condensate (which is an oil-like
product that is produced coincident to its natural gas
production from gas wells located in the Pinedale Anticline and
Jonah Fields in Sublette County, Wyoming), to various
purchasers. The pricing of the Company’s condensate
production varied significantly during 2008 and is based on
NYMEX crude futures daily settlement prices, less a negotiated
location and transportation discount or differential. All of the
Company’s condensate sales are denominated in
U.S. dollars per barrel and are paid for on a monthly
basis. The Company’s condensate production is gathered from
its Wyoming well locations by tanker trucks and is then shipped
to other locations for injection into crude oil pipelines or
other facilities. The Company routinely maintains only operating
inventories of condensate production and sells its product on an
“as produced” basis.
Environmental
Matters
The U.S. Bureau of Land Management (“BLM”)
initiates preparation of an Environmental Impact Statement
(“EIS”) relating to potential natural gas development
on federal lands in the Pinedale Anticline area in the Green
River Basin of Wyoming. An EIS is required under the National
Environmental Policy Act (“NEPA”) for major federal
actions significantly affecting the quality of the human
environment and entails consideration of environmental
consequences of a proposed action and its alternatives. Although
the Company 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, the area north of the Jonah field, including
the Pinedale Anticline, which the EIS addresses, is where most
of the Company’s exploration and development is taking
place. The BLM issues a Record of Decision (“ROD”)
with respect to a final EIS, which allows for surface
disturbances for drilling and production activities within the
area covered by the EIS, but does not authorize the drilling of
particular wells. Ultra, therefore, must submit applications to
the BLM’s Pinedale field manager for permits and other
required authorizations, such as rights-of-way for each specific
well or particular pipeline location. In making its
determination on whether to approve specific drilling or
development activities, the BLM applies the requirements of the
ROD.
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The ROD imposes limits on drilling and completion activity and
proposes mitigation guidelines, standard practices for industry
activities and best management practices for sensitive areas.
The Company cannot predict if or how these adjustments may
affect permitting, development and compliance under the ROD. The
BLM’s 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.
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 Company’s future costs of
complying with these regulations may continue to be significant.
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.
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 prepared 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 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.
During the period from 2003 through year end 2008, Ultra and
other operators in the Pinedale field received approval from the
WOGCC to drill increased density and pilot project wells in
several areas in the Lance Pool across the Pinedale field. At
the end of 2007, there were over a dozen different infill
density and pilot project orders granted by the WOGCC and
currently in place on the Pinedale field. While a very minor
portion of the Pinedale field still provides for one well per
40 acres, a succession of WOGGC approvals through yearend
2007 now provide for and range from two wells per 40 acres
(20-acre
density) up to a 32 well per
160-acre
pilot project
(5-acre
density). The northern portion of the Pinedale field is operated
by Questar Exploration and Production Company
(“Questar”) in which the Company is a working interest
partner and owns a working interest in the majority of
Questar’s acreage. Questar’s most recent infill
density application, approved in July 2007, provided for the
drilling of 16 wells per quarter section
(10-acre
density). With respect to the central portion of the Pinedale
field, approval was granted for development on a two wells per
40-acre
density in November 2005. Ultra operates the majority of the
acreage covered by this approval. Within this two wells per
40-acre
density area and in an additional area in the southern portion
of the Pinedale field, in July 2007, Ultra and other operators
received approval from the WOGCC to provide for the drilling of
16 wells per quarter section
(10-acre
density). Finally, in December 2007, approximately 2%
(640 gross acres) of the productive area of the Pinedale
field in which Company owns a working interest has now been
approved by the WOGCC for drilling at the equivalent of
5-acre
density; an additional 73% (26,888 gross acres) has been
approved for drilling at equivalent
10-acre
density; an additional 18% (6,687 gross acres) has been
approved for drilling at equivalent
20-acre
density, with 7% (2,400 gross acres) still under the state
wide 40-acre
well density rules. Further drilling and testing within the
areas approved for increased density
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continues, the results of which are being evaluated to determine
the overall development strategy for the Pinedale field and the
ultimate need for future increases in development density.
Ultra, Shell and Questar (“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 included assessment of alternative
considerations and mitigation requirements that were considered
as alternatives, or in addition, to those included in the
proposal. The proposal included commitments to reduce surface
disturbance by utilizing fewer overall pads and drilling more
directional wells than called for in the 2000 Pinedale Anticline
Project Area (“PAPA”) ROD.
The final ROD was granted on September 9, 2008. The 2008
SEIS ROD allows, among other things, for full field development
from no more than 600 well pads field-wide, as well as
year-round development and delineation activity within big game
(pronghorn and mule deer) and greater sage-grouse seasonal use
areas. Further, the Proponents agreed to implement numerous
individual mitigation components. These commitments include
i) the use of a full-field liquids gathering system,
ii) the use of advanced rig engine emission reduction
technology by at least 80% of the Company’s 2005 rig
emission levels, iii) a mitigation and monitoring fund to
address mitigation efforts to minimize impacts from energy
development, and iv) additional funding for ground water
monitoring on the PAPA. Additionally, ten-year planning and
annual meetings with BLM and appropriate state agencies will
allow for proper community planning.
Also as part of the 2008 SEIS ROD, Ultra has offered to suspend
additional activity for at least five years from the signing of
the SEIS ROD on certain leases. After the five-year period,
leases under federal suspension
and/or term
no surface occupancy will be considered for conversion to
“available for development” when a comparable acreage
in the core area of the PAPA has been returned to a functioning
habitat.
In 2007 and 2008 Ultra entered five groundwater supply wells
into the Wyoming Department of Environmental Quality Voluntary
Remediation Program (“VRP”). These wells exceeded the
Department of Environmental Quality’s (“DEQ”)
minimum
clean-up
levels (“MCL”). Four of the five wells are now
non-detect or below the MCL. The remaining well has a very low
levels of contaminates and a remediation plan has been submitted
to the DEQ for this well. Ultra encountered another water well
that exceeded the MCL. This well was remediated and the
contaminate levels were non-detect before it was entered into
the VRP.
Regulation
Oil
and Gas Regulation
The availability of a ready market for oil and natural gas
production depends upon numerous factors beyond the
Company’s 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
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 operated by other companies
that provide midstream services to the Company are also subject
to the jurisdiction of various federal, state and local agencies.
The Company’s 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
11
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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 FERC’s
pricing policy and current regulatory framework to improve the
efficiency of the market and further enhance competition in
natural gas markets. The FERC has also issued several other
generally pro-competitive policy statements and initiatives
affecting rates and other aspects of pipeline transportation of
natural gas. On May 31, 2005, the FERC generally reaffirmed
its policy allowing interstate pipelines to selectively discount
their rates in order to meet competition from other interstate
pipelines. On June 15, 2006, the FERC issued an order in
which it declined to establish uniform standards for natural gas
quality and interchangeability, opting instead for a
pipeline-by-pipeline
approach. On June 19, 2006, in order to facilitate
development of new storage capacity, the FERC established
criteria to allow providers to charge market-based (i.e.
negotiated) rates for storage services. On June 19, 2008,
the FERC removed the rate ceiling on short-term releases by
shippers of interstate pipeline transportation capacity.
The Company’s 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
corporation’s 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 Company’s equity
interests may be citizens of foreign countries, which could
be determined to be citizens of a non-reciprocal country under
the Mineral Act.
Environmental
Regulations
General. The Company’s 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 federal, state and local laws
and regulations governing environmental quality, including those
relating to oil spills and pollution control. Although such laws
and regulations can increase the cost of planning, designing,
installing and operating such facilities, 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
Company’s operations, capital expenditures, earnings or
competitive position.
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
12
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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. Under current and evolving law, it is possible the Company
could be required to remediate property, including ground water,
containing or impacted by previously disposed wastes including
performing remedial plugging operations to prevent future, or
mitigate existing contamination.
Although oil and gas wastes generally are exempt from regulation
as hazardous wastes (“Hazardous Wastes”), the federal
Resource Conservation and Recovery Act (“RCRA”) and
comparable state statutes, it is possible some wastes the
Company generates presently or in the future may be subject to
regulation under RCRA and state analogs. The Environmental
Protection Agency (“EPA”) and various state agencies
have limited the disposal options for certain wastes, including
hazardous wastes and is considering adopting stricter disposal
standards for non-hazardous wastes. Furthermore, certain wastes
generated by the Company’s 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, liability, generally is joint and several, 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
CERCLA’s 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, as a past or present owner or
operator or as an arranger. 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 PRP’s related to
their ownership or operation of such property.
National Environmental Policy Act. As noted,
the federal National Environmental Policy Act provides that, for
major federal actions significantly affecting the quality of the
human environment, the federal agency taking such action must
prepare an EIS. In the EIS, the agency is required to evaluate
alternatives to the proposed action and the environmental
impacts of the proposed action and of such alternatives. Actions
of the Company, such as drilling on federal lands, to the extent
the drilling requires federal approval, may trigger the
requirements of the National Environmental Policy Act, including
the requirement that an EIS be prepared. 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 company’s activities.
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 liability, which generally is joint and several, 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.
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Air Emissions. The Company’s operations
are subject to local, state and federal regulations for the
control of emissions from sources of air pollution. Federal and
state laws generally require new and modified sources of air
pollutants to obtain permits prior to commencing construction,
which may require, among other things, stringent, technical
controls. 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 through
administrative, civil or criminal enforcement actions, resulting
in fines, injunctive relief and imprisonment.
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. Under the Clean Water Act, permits must be
obtained for the routine discharge pollutants into waters of the
United States. The CWA provides for administrative, civil and
criminal penalties for unauthorized discharges, both routine and
accidental, 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.
Endangered Species Act. The Endangered Species
Act (“ESA”) was established to protect endangered and
threatened species. Pursuant to that act, if a species is listed
as threatened or endangered, restrictions may be imposed on
activities adversely affecting that species’ habitat.
Similar protections are offered to migratory birds under the
Migratory Bird Treaty Act. 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. 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.
Climate Change Legislation. More stringent
laws and regulations relating to climate change and greenhouse
gases (“GHGs”) may be adopted in the future and could
cause the Company to incur material expenses in complying with
them. The U.S. Congress last session considered climate
change-related legislation to regulate GHG emissions that could
affect our operations and our regulatory costs, as well as the
value of oil and natural gas generally. Although that
legislation did not pass, expectations are that Congress will
continue to consider some type of climate change legislation and
that the EPA may consider climate change-related regulatory
initiatives. As a result, there is a great deal of uncertainty
as to how and when federal regulation of GHGs might take place.
In addition to possible federal regulation, a number of states,
individually and regionally, also are considering or have
implemented GHG regulatory programs. These potential federal and
state initiatives may result in so-called
cap-and-trade
programs, under which overall GHG emissions are limited and GHG
emissions are then allocated and sold, and possibly other
regulatory requirements, that could result in our incurring
material expenses to comply, e.g., by being required to purchase
or to surrender allowances for GHGs resulting from our
operations. These regulatory initiatives also could adversely
affect the marketability of the oil and natural gas we produce.
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.
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Employees
As of December 31, 2008, the Company had 86 full-time
employees, including officers.
| Item 1A. | Risk Factors. |
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:
| • | our access to the capital necessary to drill wells and acquire properties; | |
| • | our ability to acquire and analyze seismic, geological and other information relating to a property; |
15
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| • | our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; and | |
| • | our ability to access pipelines, and the locations of facilities used to produce and transport oil and natural gas production. |
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:
| • | the extent of domestic production and imports of oil and natural gas; | |
| • | the availability of pipeline capacity; | |
| • | the proximity of natural gas production to those natural gas pipelines; | |
| • | the effects of inclement weather; | |
| • | the demand for oil and natural gas by utilities and other end users; | |
| • | the availability of alternative fuel sources; | |
| • | state and federal regulations of oil and natural gas marketing; and | |
| • | federal regulation of natural gas sold or transported in interstate commerce. |
Because of these factors, we may be unable to market all of our
oil and natural gas that we produce. 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 revenues. In 2008, we had
two significant customers for our natural gas production. Sales
to Nicor Enerchange were $115.7 million and sales to
Tenaska were $117.9 million, which accounted for 10.7% and
10.9% of the Company’s total 2008 revenues, respectively.
To the extent these or any other significant customer reduces
the volume of its natural gas purchases from us, we could,
theoretically, experience a temporary interruption in sales of,
or a lower price for, our natural gas. The Company has numerous
other customers that would likely compensate for the loss of one
or more of our significant customers by increasing their
purchases of our natural gas production.
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.
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 Company’s revenues,
profitability and cash flows from operations.
The Company’s average price realization for natural gas,
excluding gains and losses on commodity derivatives, was $4.81
per Mcf during the quarter ended December 31, 2008 as
compared to $8.80 per Mcf for the quarter ended June 30,
2008. If prices received during the second quarter of 2008 were
realized during the fourth quarter of 2008, natural gas revenues
would have increased by approximately $150 million.
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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, and continue to be, 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.
Although the Company continuously evaluates its options and
opportunities to support these project, 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. The Company has mitigated its exposure
to this risk by securing capacity rights to transport a portion
of its natural gas production on the Rockies Express pipeline
and delivering it to markets beyond the Rocky Mountain region.
If the
United States experiences a sustained economic downturn or
recession, natural gas prices may fall, which may adversely
affect our results of operations.
The unprecedented disruption in the U.S. and international
credit markets has resulted in a rapid deterioration in the
worldwide economy and tightening of the financial markets in the
second half of 2008, and the outlook for the economy in 2009 is
uncertain. The current global credit and economic environment
has reduced worldwide demand for energy and resulted in
significantly lower natural gas prices. A sustained reduction in
the prices we receive for our natural gas production could have
a material adverse effect on our results of operations. For
example, for the quarter ending December 31, 2008, a 10%
reduction in the price we received for natural gas would have
reduced our revenues by approximately $20 million. In
addition, current conditions in the credit and equity markets,
if they persist, could also increase our financing costs and
limit our financial flexibility. The continuation, or worsening,
of domestic and global economic conditions could continue to
adversely affect our business and results of operations.
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:
| • | require that we acquire permits before commencing drilling; | |
| • | restrict the substances that can be released into the environment in connection with drilling and production activities; | |
| • | limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and | |
| • | require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells. |
Under these laws and regulations or under the common law, the
Company could be liable for personal injury and
clean-up
costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. The Company could
also be affected by more stringent laws and regulations adopted
in the future, including any related to climate change and
greenhouse gases. 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.
17
Table of Contents
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.
We may
not be able to obtain funding on acceptable terms or at all
because of the deterioration of the credit and capital markets.
This may hinder or prevent us from meeting our future capital
needs.
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile due to a variety of
factors. As a result, the cost of raising money in the debt and
equity capital markets has increased substantially while the
availability of funds from those markets has diminished
significantly. Although we have been able to successfully raise
money in the current economic climate, we may not be successful
in the future. In particular, as a result of concerns about the
stability of financial markets generally and the solvency of
lending counterparties specifically, the cost of obtaining money
from the credit markets generally has increased as many lenders
and institutional investors have increased interest rates,
enacted tighter lending standards, refused to refinance existing
debt on similar terms or at all and reduced, or in some cases
ceased, to provide funding to borrowers. In addition, lending
counterparties under existing revolving credit facilities and
other debt instruments may be unwilling or unable to meet their
funding obligations. Due to these factors, we cannot be certain
that new debt or equity financing will be available on
acceptable terms. If funding is not available when needed, or is
available only on unfavorable terms, we may be unable to meet
our obligations as they come due. Moreover, without adequate
funding, we may be unable to execute our growth strategy, take
advantage of other business opportunities or respond to
competitive pressures, any of which could have a material
adverse effect on our revenues and results of operations.
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 “Management’s 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 loan commitment
and aggregate amount of money we can borrow under the credit
facility and from other sources is revised from time to time
based on certain restrictive covenants. A change in our ability
to meet the restrictive covenants might limit our ability to
borrow. If this occurred, we may have to sell assets or seek
substitute financing. 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 “Management’s Discussion and
Analysis of Financial Condition and Results of
Operations — Liquidity and Capital Resources.”
18
Table of Contents
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.
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
geophysical 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.
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.
19
Table of Contents
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:
| • | receipt of additional seismic data or reprocessing of existing data; | |
| • | material changes in oil or natural gas prices; | |
| • | the costs and availability of drilling equipment; | |
| • | success or failure of wells drilled in similar formations or which would use the same production facilities; | |
| • | availability and cost of capital; | |
| • | changes in the estimates of costs to drill or complete wells; | |
| • | the approval of partners to participate in the drilling of certain wells; | |
| • | our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; | |
| • | decisions of our joint working interest owners; and | |
| • | regulatory requirements, including those based on the BLM’s interpretation of an EIS and the results of the permitting process. |
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.
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.
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, Management’s 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
Company’s 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:
| • | our oil and natural gas reserve quantities, and the discounted present value of those reserves; |
20
Table of Contents
| • | the amount and nature of our capital expenditures; | |
| • | drilling of wells; | |
| • | the timing and amount of future production and operating costs; | |
| • | business strategies and plans of management; and | |
| • | prospect development and property acquisitions. |
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:
| • | the current global economic downturn; | |
| • | general economic conditions, including the availability of credit and access to existing lines of credit; | |
| • | the volatility of oil and natural gas prices; | |
| • | the uncertainty of estimates of oil and natural gas reserves; | |
| • | the impact of competition; | |
| • | the availability and cost of seismic, drilling and other equipment; | |
| • | operating hazards inherent in the exploration for and production of oil and natural gas; | |
| • | difficulties encountered during the exploration for and production of oil and natural gas; | |
| • | difficulties encountered in delivering oil and natural gas to commercial markets; | |
| • | changes in customer demand and producers’ supply; | |
| • | the uncertainty of our ability to attract capital and obtain financing on favorable terms; | |
| • | compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business, including those related to climate change and greenhouse gases; | |
| • | actions of operators of our oil and natural gas properties; and | |
| • | weather conditions. |
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.
| Item 1B. | Unresolved Staff Comments. |
None.
| Item 2. | Properties. |
Location
and Characteristics
The Company owns oil and natural gas leases in Wyoming and
Pennsylvania. 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. The Company owns 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 Company’s leases held within the
productive area of the Pinedale and Jonah fields. The leases in
Pennsylvania include both those from private individuals,
typically with lease terms of five years until establishment of
production and leases from the Commonwealth of Pennsylvania,
which have lease term of five years until establishment of
production. Production on the Pennsylvania leases extends the
lease terms until cessation of that production. The Company owns
approximately 839 gross (739 net) acres currently held by
production or operations in Pennsylvania.
Green
River Basin, Wyoming
As of December 31, 2008, the Company owned developed oil
and natural gas leases totaling 18,916 gross (8,528 net)
acres in the Green River Basin of Sublette County, Wyoming which
represents 92% of the Company’s total developed net
acreage. The Company owns undeveloped oil and natural gas leases
totaling 102,516 gross (51,425 net) acres in the Green
River Basin of Sublette County, Wyoming which represents 25% of
the Company’s total undeveloped net acreage. The
Company’s acreage in the Green River Basin primarily covers
the Pinedale field
21
Table of Contents
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 $0.1 million for the year ended
December 31, 2008. The primary target on the Company’s
Wyoming acreage is the tight gas sands of the upper Cretaceous
Lance Pool formation.
Exploratory Wells. During 2008, the Company
participated in the drilling of a total of 108 gross (59.50
net) productive exploratory wells on the Green River Basin
properties. At December 31, 2008, there were 50 gross
(18.69 net) additional exploratory wells that commenced during
the year that were either still drilling or had 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 2008, the Company
participated in the drilling of 120 gross (61.98 net)
productive development wells on the Green River Basin
properties. At year end 2008, there were 29 gross (17.99
net) additional development wells that commenced during 2008 and
were either still drilling or had 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 Company’s 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.
Pennsylvania
As of December 31, 2008, the Company owned developed oil
and gas leases totaling 839 gross (739 net) acres in the
Pennsylvania portion of the Appalachian Basin which represents
8% of the Company’s total developed net acreage. The
Company owns undeveloped oil and gas leases totaling
286,906 gross (151,488 net) acres in this area which
represents 75% of the Company’s total undeveloped net
acreage. Holding costs of leases in Pennsylvania not held by
production were approximately $0.2 million for the year
ended December 31, 2008.
Exploratory Wells. During the year ended
December 31, 2008, the Company participated in the drilling
of a total of 18 gross (9.63 net) wells on the Pennsylvania
properties. During 2008, the Company began acquisition of a 3D
seismic survey covering the Marshlands prospect area. At year
end 2008, acquisition was still underway. Processing of this
data set is expected in early 2009 with potential inclusion of
exploratory well locations in the 2009 drilling program.
22
Table of Contents
Oil and
Gas Reserves
The following table sets forth the Company’s quantities of
domestic proved reserves, for the years ended December 31,
2008, 2007, and 2006 as estimated by independent petroleum
engineers Netherland, Sewell & Associates, Inc. The
table summarizes the Company’s 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, 2008, 2007 and 2006.
In accordance with Ultra’s 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, 2012. As of December 31,
2008, proved undeveloped reserves represent 57.9% of the
Company’s total proved reserves.
| December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In thousands) | ||||||||||||
|
Proved Undeveloped Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
1,943,225 | 1,758,431 | 1,415,132 | |||||||||
|
Oil (MBbl)
|
15,546 | 14,067 | 11,321 | |||||||||
|
Proved Developed Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
1,412,562 | 1,084,224 | 842,969 | |||||||||
|
Oil (MBbl)
|
11,462 | 8,764 | 6,522 | |||||||||
|
Total Proved Reserves (MMcfe)
|
3,517,830 | 2,979,644 | 2,365,159 | |||||||||
|
Estimated future net cash flows, before income tax
|
$ | 10,040,263 | $ | 13,076,921 | $ | 6,590,206 | ||||||
|
Standardized measure of discounted future net cash flows, before
income taxes(1)
|
$ | 4,443,867 | $ | 5,841,194 | $ | 2,690,464 | ||||||
|
Future income tax
|
$ | 1,426,181 | $ | 1,971,792 | $ | 905,384 | ||||||
|
Standardized measure of discounted future net cash flows, after
income tax
|
$ | 3,017,686 | $ | 3,869,402 | $ | 1,785,080 | ||||||
|
Calculated weighted average price at December 31,
|
||||||||||||
|
Gas ($/Mcf)
|
$ | 4.71 | $ | 6.13 | $ | 4.50 | ||||||
|
Oil ($/Bbl)
|
$ | 30.10 | $ | 86.91 | $ | 59.95 | ||||||
| (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 Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s 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. |
23
Table of Contents
The following table sets forth the Company’s quantities of
proved reserves in China, for the years ended December 31,
2008, 2007 and 2006 as estimated by independent petroleum
engineers Ryder Scott Company. In accordance with the
Company’s “new field” reserve booking policy,
proved reserves were booked after production has commenced. The
table summarizes the Company’s 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, 2008, 2007 and 2006.
| December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In thousands) | ||||||||||||
|
Proved Undeveloped Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
— | — | — | |||||||||
|
Oil (MBbl)
|
— | — | 1,301 | |||||||||
|
Proved Developed Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
— | — | — | |||||||||
|
Oil (MBbl)
|
— | — | 2,686 | |||||||||
|
Total Proved Reserves (MMcfe)
|
— | — | 23,922 | |||||||||
|
Estimated future net cash flows, before income tax
|
$ | — | $ | — | $ | 111,994 | ||||||
|
Standardized measure of discounted future net cash flows, before
income taxes(1)
|
$ | — | $ | — | $ | 91,984 | ||||||
|
Future Income Tax
|
$ | — | $ | — | $ | 5,511 | ||||||
|
Standardized measure of discounted future net cash flows, after
income tax
|
$ | — | $ | — | $ | 86,473 | ||||||
|
Calculated weighted average price at December 31, Oil
($/Bbl)
|
$ | — | $ | — | $ | 46.57 | ||||||
| (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 Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s 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. |
24
Table of Contents
The following table sets forth the Company’s quantities of
total proved reserves both domestically and in China, for the
years-ended December 31, 2008, 2007 and 2006 as estimated
by independent petroleum engineers Netherland,
Sewell & Associates, Inc. and Ryder Scott Company. The
table summarizes the Company’s 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, 2008, 2007 and 2006.
In accordance with Ultra’s 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, 2012. At December 31,
2008, proved undeveloped reserves represent 57.9% of the
Company’s total proved reserves.
| December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In thousands) | ||||||||||||
|
Proved Undeveloped Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
1,943,225 | 1,758,431 | 1,415,132 | |||||||||
|
Oil (MBbl)
|
15,546 | 14,067 | 12,622 | |||||||||
|
Proved Developed Reserves
|
||||||||||||
|
Natural gas (MMcf)
|
1,412,562 | 1,084,224 | 842,969 | |||||||||
|
Oil (MBbl)
|
11,462 | 8,764 | 9,208 | |||||||||
|
Total Proved Reserves (MMcfe)
|
3,517,830 | 2,979,644 | 2,389,081 | |||||||||
|
Estimated future net cash flows, before income tax
|
$ | 10,040,263 | $ | 13,076,921 | $ | 6,702,200 | ||||||
|
Standardized measure of discounted future net cash flows, before
income taxes(1)
|
$ | 4,443,867 | $ | 5,841,194 | $ | 2,782,448 | ||||||
|
Future income tax
|
$ | 1,426,181 | $ | 1,971,792 | $ | 910,895 | ||||||
|
Standardized measure of discounted future net cash flows, after
income tax
|
$ | 3,017,686 | $ | 3,869,402 | $ | 1,871,553 | ||||||
| (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 Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s 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. |
Since January 1, 2008, no crude oil or natural gas reserve
information has been filed with, or included in any report to,
any federal authority or agency other than the SEC and the
Energy Information Administration (“EIA”) of the U.S.
Department of Energy. We file Form 23, including reserve
and other information, with the EIA.
25
Table of Contents
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 Company’s sale
of oil and natural gas for the periods indicated.
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In thousands, except per unit data) | ||||||||||||
|
Production
|
||||||||||||
|
Natural gas (Mcf)
|
138,564 | 109,178 | 78,395 | |||||||||
|
Oil (Bbl) — US
|
1,122 | 870 | 594 | |||||||||
|
Oil (Bbl) — China (See Note 11 on Discontinued
Operations)
|
— | 1,153 | 1,603 | |||||||||
|
Total (Mcfe)
|
145,293 | 121,316 | 91,580 | |||||||||
|
Revenues
|
||||||||||||
|
Natural gas sales
|
$ | 986,374 | $ | 509,140 | $ | 470,324 | ||||||
|
Oil sales — US
|
98,026 | 57,498 | 38,335 | |||||||||
|
Oil sales — China (See Note 11 on Discontinued
Operations)
|
— | 64,822 | 84,008 | |||||||||
|
Total revenues
|
$ | 1,084,400 | $ | 631,460 | $ | 592,667 | ||||||
|
Lease Operating Expenses
|
||||||||||||
|
Production costs — US(a)
|
$ | 36,997 | $ | 23,968 | $ | 15,068 | ||||||
|
Production costs — China(a) (See Note 11 on
Discontinued Operations)
|
— | 11,419 | 8,922 | |||||||||
|
Severance/production taxes — US
|
119,502 | 63,480 | 57,899 | |||||||||
|
Severance/production taxes — China (See Note 11
on Discontinued Operations)
|
— | 8,113 | 8,398 | |||||||||
|
Gathering
|
37,744 | 27,923 | 19,721 | |||||||||
|
Total lease operating expenses
|
$ | 194,243 | $ | 134,903 | $ | 110,008 | ||||||
|
Realized Prices
|
||||||||||||
|
Natural gas ($/Mcf, including cash flow hedges under
SFAS 133)
|
$ | 7.12 | $ | 4.66 | $ | 6.00 | ||||||
|
Natural gas ($/Mcf, excluding financial commodity derivatives)(b)
|
$ | 7.11 | $ | 4.65 | $ | 6.00 | ||||||
|
Oil ($/Bbl) — US
|
$ | 87.40 | $ | 66.08 | $ | 64.52 | ||||||
|
Oil ($/Bbl) — China (See Note 11 on Discontinued
Operations)
|
$ | — | $ | 56.21 | $ | 52.40 | ||||||
|
Operating Costs per Mcfe — Total Consolidated
|
||||||||||||
|
Production costs
|
$ | 0.25 | $ | 0.29 | $ | 0.26 | ||||||
|
Severance/production taxes
|
$ | 0.82 | $ | 0.59 | $ | 0.72 | ||||||
|
Gathering
|
$ | 0.26 | $ | 0.23 | $ | 0.22 | ||||||
|
Transportation charges
|
$ | 0.32 | $ | — | $ | — | ||||||
|
DD&A
|
$ | 1.27 | $ | 1.24 | $ | 1.02 | ||||||
|
Interest
|
$ | 0.15 | $ | 0.15 | $ | 0.04 | ||||||
|
Total operating costs per Mcfe
|
$ | 3.07 | $ | 2.50 | $ | 2.26 | ||||||
| (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 2008, 2007 and 2006, we sold 32.7 MMMBtu (23%), 6.8 MMMBtu (6%) and 20.4 MMMBtu (22%) pursuant to these contracts, respectively. The average price we received for production sold pursuant to term fixed price contracts was $6.84, $6.20 and $5.86 per MMBtu in 2008, 2007 and 2006, respectively. The average spot price (as measured by the Inside FERC First of Month Index for Northwest Pipeline — Rocky Mountains) was $6.25, $3.95 and $5.66 per MMBtu in 2008, 2007 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 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. |
26
Table of Contents
Productive
Wells
As of December 31, 2008, the Company’s total gross and
net wells were as follows:
|
Productive Wells*
|
Gross Wells | Net Wells | ||||||
|
Natural Gas and Condensate
|
1,007.0 | 467.6 | ||||||
| * | Productive wells are producing wells, shut-in wells the Company deems capable of production, wells that are drilled/cased and waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. 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, 2008, the Company had total gross and
net developed and undeveloped oil and natural gas leasehold
acres in the United States as set forth below. The
Company’s 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 Company’s oil and natural gas operations are
presented in the following tables.
| Developed Acres | Undeveloped Acres | |||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
|
Wyoming
|
18,916 | 8,528 | 102,516 | 51,425 | ||||||||||||
|
Pennsylvania
|
839 | 739 | 286,906 | 151,488 | ||||||||||||
|
Other
|
80 | 14 | — | — | ||||||||||||
|
All States
|
19,835 | 9,281 | 389,422 | 202,913 | ||||||||||||
Drilling
Activities
For each of the three fiscal years ended December 31, 2008,
2007 and 2006, the number of gross and net wells drilled by the
Company was as follows:
Wyoming —
Green River Basin
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Development Wells
|
||||||||||||||||||||||||
|
Productive
|
120.00 | 61.98 | 72.00 | 32.35 | 80.00 | 38.44 | ||||||||||||||||||
|
Dry
|
0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||||||||
|
Total
|
120.00 | 61.98 | 72.00 | 32.35 | 80.00 | 38.44 | ||||||||||||||||||
At year end, there were 29 gross (17.99 net) additional
development wells that were either drilling or had operations
suspended. This includes wells in both the Pinedale and Jonah
fields.
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Exploratory Wells
|
||||||||||||||||||||||||
|
Productive
|
108.00 | 59.50 | 79.0 | 43.76 | 44.0 | 19.79 | ||||||||||||||||||
|
Dry
|
0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||||||||
|
Total
|
108.00 | 59.50 | 79.0 | 43.76 | 44.0 | 19.79 | ||||||||||||||||||
At year end there were 50 gross (18.69 net) additional
exploratory wells that were either drilling or had operations
suspended.
27
Table of Contents
Pennsylvania
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Exploratory Wells
|
||||||||||||||||||||||||
|
Productive
|
0.00 | 0.00 | 2.00 | 1.12 | 0.00 | 0.00 | ||||||||||||||||||
|
Dry
|
0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||||||||
|
Total
|
0.00 | 0.00 | 2.00 | 1.12 | 0.00 | 0.00 | ||||||||||||||||||
At year end there were 18 gross (9.63 net) exploratory
wells that were either drilling or had operations suspended.
China —
Bohai Bay
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
|
Development Wells
|
||||||||||||||||||||||||
|
Productive
|
0.00 | 0.00 | 15.00 | 1.34 | 26.00 | 2.16 | ||||||||||||||||||
|
Dry
|
0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||||||||
|
Total
|
0.00 | 0.00 | 15.00 | 1.34 | 26.00 | 2.16 | ||||||||||||||||||
|
Exploratory Wells
|
||||||||||||||||||||||||
|
Productive and Successful Appraisal*
|
0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||||||||||||||||
|
Dry
|
0.00 | 0.00 | 2.00 | 0.18 | 1.00 | 0.23 | ||||||||||||||||||
|
Total
|
0.00 | 0.00 | 2.00 | 0.18 | 1.00 | 0.23 | ||||||||||||||||||
| * | 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 Company’s 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 Company’s
security holders during the fourth quarter of the fiscal year
ended December 31, 2008.
28
Table of Contents
PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Since August 3, 2007, the Company’s common stock has
traded on the New York Stock Exchange (“NYSE”) under
the symbol “UPL”. Prior to such time, the
Company’s common stock traded on the American Stock
Exchange (“AMEX”) under the symbol “UPL”.
The following table sets forth the high and low
intra-day
sales prices of the common stock for the periods indicated.
|
2008
|
High | Low | ||||||
|
First Quarter
|
$ | 81.33 | $ | 60.00 | ||||
|
Second Quarter
|
$ | 102.81 | $ | 75.35 | ||||
|
Third Quarter
|
$ | 102.81 | $ | 49.41 | ||||
|
Fourth Quarter
|
$ | 56.71 | $ | 28.85 | ||||
|
2007
|
High | Low | ||||||
|
First Quarter
|
$ | 53.65 | $ | 44.20 | ||||
|
Second Quarter
|
$ | 64.94 | $ | 52.09 | ||||
|
Third Quarter
|
$ | 62.49 | $ | 52.16 | ||||
|
Fourth Quarter
|
$ | 72.32 | $ | 61.50 | ||||
On February 13, 2009, the last reported sales price of the
common stock on the NYSE was $40.17 per share. As of
February 13, 2009 there were approximately 413 holders of
record of the common stock.
29
Table of Contents
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Ultra Petroleum Corp.
Among Ultra Petroleum Corp.
| * | $100 invested on 12/31/03 in stock or index-including reinvestment of dividends. Fiscal year ending December 31. |
Copyright
©
2009 S&P, a division of The McGraw-Hill Companies Inc. All
rights reserved.
Copyright
©
2009 Dow Jones & Co. All rights reserved.
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.
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 Company’s outstanding
common stock which has been and will be funded by cash on hand
and the Company’s senior credit facility. Pursuant to this
authorization, the Company has commenced a program to purchase
up to $750.0 million of the Company’s outstanding
shares through open market transactions or privately negotiated
transactions.
|
Total Number |
||||||||||||||||
|
of Shares |
Maximum Number |
|||||||||||||||
|
Purchased |
(or Approximate |
|||||||||||||||
|
as Part of |
Dollar Value) of |
|||||||||||||||
|
Publicly |
Shares That |
|||||||||||||||
|
Total Number |
Announced |
May Yet be |
||||||||||||||
|
of Shares |
Average |
Plans or |
Purchased |
|||||||||||||
|
Purchased |
Price Paid |
Programs |
Under the |
|||||||||||||
|
Period
|
(000’s) | per Share | (000’s) | Plans or Programs | ||||||||||||
|
Oct 1 — Oct 31, 2008
|
— | $ | — | — | $ | 420 million | ||||||||||
|
Nov 1 — Nov 30, 2008
|
— | $ | — | — | $ | 420 million | ||||||||||
|
Dec 1 — Dec 31, 2008
|
402 | $ | 32.83 | 402 | $ | 407 million | ||||||||||
30
Table of Contents
| Item 6. | Selected Financial Data. |
The selected consolidated financial information presented below
for the years ended December 31, 2008, 2007, 2006, 2005,
and 2004 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, | ||||||||||||||||||||
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
| (In thousands, except per share data) | ||||||||||||||||||||
|
Statement of Operations Data
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Natural gas sales
|
$ | 986,374 | $ | 509,140 | $ | 470,324 | $ | 422,091 | $ | 224,208 | ||||||||||
|
Gain on commodity derivatives
|
33,216 | — | — | — | — | |||||||||||||||
|
Oil sales
|
98,026 | 57,498 | 38,335 | 26,640 | 14,659 | |||||||||||||||
|
Interest and other
|
418 | 1,087 | 1,941 | 612 | 91 | |||||||||||||||
|
Total revenues
|
$ | 1,118,034 | $ | 567,725 | $ | 510,600 | $ | 449,343 | $ | 238,958 | ||||||||||
|
Expenses:
|
||||||||||||||||||||
|
Production expenses and taxes
|
194,243 | 115,371 | 92,688 | 78,862 | 47,574 | |||||||||||||||
|
Transportation charges
|
46,310 | — | — | — | — | |||||||||||||||
|
Depreciation, depletion and amortization
|
184,795 | 135,470 | 79,675 | 48,455 | 27,346 | |||||||||||||||
|
General and administrative
|
11,230 | 7,543 | 12,259 | 11,405 | 6,123 | |||||||||||||||
|
Stock compensation
|
5,816 | 5,718 | 2,626 | 2,859 | 924 | |||||||||||||||
|
Interest
|
21,276 | 17,760 | 3,909 | 3,286 | 3,783 | |||||||||||||||
|
Total expenses
|
463,670 | 281,862 | 191,157 | 144,867 | 85,750 | |||||||||||||||
|
Income before income taxes
|
654,364 | 285,863 | 319,443 | 304,476 | 153,208 | |||||||||||||||
|
Income tax provision
|
240,504 | 105,621 | 122,741 | 107,864 | 53,406 | |||||||||||||||
|
Net income from continuing operations
|
413,860 | 180,242 | 196,702 | 196,612 | $ | 99,802 | ||||||||||||||
|
Income from discontinued operations (including pre-tax gain on
sale of $98,066 in 2007)
|
415 | 82,794 | 34,493 | 31,688 | 9,348 | |||||||||||||||
|
Net income
|
$ | 414,275 | $ | 263,036 | $ | 231,195 | $ | 228,300 | $ | 109,150 | ||||||||||
|
Basic Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 2.72 | $ | 1.19 | $ | 1.28 | $ | 1.28 | $ | 0.67 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.54 | $ | 0.22 | $ | 0.21 | $ | 0.06 | ||||||||||
|
Net income per common share
|
$ | 2.72 | $ | 1.73 | $ | 1.50 | $ | 1.49 | $ | 0.73 | ||||||||||
|
Fully Diluted Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 2.65 | $ | 1.14 | $ | 1.22 | $ | 1.21 | $ | 0.62 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.52 | $ | 0.21 | $ | 0.20 | $ | 0.06 | ||||||||||
|
Net income per common share
|
$ | 2.65 | $ | 1.66 | $ | 1.43 | $ | 1.41 | $ | 0.68 | ||||||||||
|
Statement of Cash Flows Data
|
||||||||||||||||||||
|
Net cash provided by (used in):
|
||||||||||||||||||||
|
Operating activities
|
$ | 840,803 | $ | 427,949 | $ | 437,333 | $ | 414,140 | $ | 175,343 | ||||||||||
|
Investing activities
|
(915,319 | ) | (507,070 | ) | (453,882 | ) | (306,549 | ) | (165,014 | ) | ||||||||||
|
Financing activities
|
78,041 | 75,179 | (12,845 | ) | (80,344 | ) | 4,770 | |||||||||||||
|
Balance Sheet Data Cash and cash equivalents
|
$ | 14,157 | $ | 10,632 | $ | 14,574 | $ | 43,968 | $ | 16,721 | ||||||||||
|
Working capital (deficit)
|
(149,355 | ) | (67,505 | ) | 55,036 | 44,600 | (18,298 | ) | ||||||||||||
|
Oil and gas properties
|
2,350,526 | 1,574,529 | 1,006,998 | 599,901 | 381,409 | |||||||||||||||
|
Total assets
|
2,558,162 | 1,751,582 | 1,258,299 | 742,566 | 435,076 | |||||||||||||||
|
Total long-term debt
|
570,000 | 290,000 | 165,000 | — | 102,000 | |||||||||||||||
|
Other long-term obligations
|
46,206 | 26,672 | 25,262 | 19,821 | 9,312 | |||||||||||||||
|
Deferred income taxes, net
|
503,597 | 341,406 | 252,808 | 148,743 | 78,129 | |||||||||||||||
|
Total shareholders’ equity
|
1,090,786 | 857,546 | 631,258 | 572,910 | 267,992 | |||||||||||||||
31
Table of Contents
| Item 7. | Management’s 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 indicated, all amounts are
expressed in U.S. dollars. We have one operating segment,
natural gas and oil exploration and development with one
geographical segment, the United States.
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 Company’s business. The price of natural gas in
southwest Wyoming historically has been volatile. The average
annual realizations for the period
2003-2008
have ranged from $2.33 to $8.81 per Mcf. This volatility could
be detrimental to the Company’s 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. The average realization for the Company’s
natural gas during 2008 was $7.26 per Mcf, including realized
gains on commodity derivatives. For the quarter ended
December 31, 2008, the average realization for the
Company’s natural gas was $5.39 per Mcf, including realized
gains on commodity derivatives. The Company’s average price
realization for natural gas, excluding realized gains on
commodity derivatives, was $7.11 per Mcf and $4.81 per Mcf for
the year and quarter ended December 31, 2008, respectively.
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. The
Company delivered 21% production growth on an Mcfe basis during
the quarter ended December 31, 2008 as compared to the same
quarter in 2007 and 20% production growth (27% from continuing
operations) for the year-ended December 31, 2008 compared
to the same period in 2007. Management expects to deliver
additional production growth during 2009 by drilling and
bringing into production additional wells in Wyoming.
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
|
Production — Bcfe
|
145.3 | 121.3 | 91.6 | 73.8 | 49.5 | |||||||||||||||
The Company currently conducts operations exclusively in the
United States. Substantially all of the oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented reflect only the Company’s proportionate
interest in such activities. Inflation has not had a material
impact on the Company’s results of operations and is not
expected to have a material impact on the Company’s results
of operations in the future.
In 2008, we saw significant changes in the business environment
in which we operate, including severe economic uncertainty,
increasing market volatility and continued tightening of credit
markets. The market conditions in 2008 contributed to record
high commodity prices during most of the year and nearly
unprecedented drops in these commodity prices in the second half
of the year.
Against this backdrop, we believe that our results of operations
show just how successful we have been in improving our business.
The highlights in 2008 include record operational and financial
results. In 2008, the Company established new production records
along with new records in earnings and cash flow while
maintaining a low cost structure which contributes to the
consistency of the Company’s growth and returns.
Outlook
In 2008, we experienced challenges associated with changing
market conditions, which caused significant volatility in
commodity prices and the tightening of the economy. However, we
believe we are well positioned to weather the current economic
downturn because of our status as a low cost operator in the
industry and our financial flexibility.
Although we expect that our net cash provided by operating
activities may be negatively affected by general economic
conditions, we believe that we will continue to generate strong
cash flow from operations, which, along with our available cash,
will provide sufficient liquidity to allow us to return value to
our shareholders. While it is possible that we may not have
access to the credit markets on acceptable terms, we expect to
rely on our available
32
Table of Contents
cash, our existing credit facility and the cash we generate from
our operations to meet our obligations and fund our capital
expenditures and operations over the next twelve months. A
continued, long-term disruption in the credit markets could make
financing more expensive or unavailable, which could have a
material adverse effect on our operations.
Critical
Accounting Policies
The discussion and analysis of the Company’s 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 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 Company’s depreciation, depletion
and amortization (“DD&A”) expense. For example,
if estimates of proved reserves decline, the Company’s
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.
33
Table of Contents
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 utilizing prices in effect on the last day of the quarter.
SEC
regulation S-X
Rule 4-10 states
that if prices in effect at the end of a quarter are the result
of a temporary decline and prices improve prior to the issuance
of the financial statements, the increased price may be applied
in the computation of the ceiling test. 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 2008, 2007, or 2006. As of
December 31, 2008, the ceiling limitation exceeded the
carrying value of the Company’s oil and natural gas
properties. Estimates of standardized measure at
December 31, 2008 were based on realized natural gas prices
which averaged $4.71 per Mcf and on realized liquids prices
which averaged $30.10 per barrel in the U.S. A reduction in
oil and natural gas prices
and/or
estimated 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
Company’s 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 Company’s 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).
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Table of Contents
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, 2008, the
Company had net deferred tax assets totaling $27.4 million
which management considers is more likely than not to be
realized.
Forward natural gas sales transactions: The
Company primarily relies on fixed price physical delivery
contracts, which are considered sales in the normal course of
business, to manage its commodity price exposure. The Company,
from time to time, also uses derivative instruments as a way to
manage its exposure to commodity prices. (See Note 7).
Fair Value Measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair value on a recurring basis, primarily our commodity
derivatives, with no material impact on consolidated results of
operations, financial position or liquidity. See Note 13
for additional information.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at measurement date and establishes a three level hierarchy for
measuring fair value. The valuation assumptions utilized to
measure the fair value of the Company’s commodity
derivatives were observable inputs based on market data obtained
from independent sources and are considered Level 2 inputs
(quoted prices for similar assets, liabilities (adjusted) and
market-corroborated inputs).
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance
with the requirements of SFAS No. 157. In addition, we
aligned the categories below with the Level 1, 2, and 3
fair value measurements as defined by SFAS No. 157.
The balance of net unrealized gains and losses recognized for
our energy-related derivative instruments at December 31,
2008 is summarized in the following table based on the inputs
used to determine fair value:
| Level 1(a) | Level 2(b) | Level 3(c) | Total | |||||||||||||
|
Assets — current:
|
||||||||||||||||
|
Derivatives
|
$ | — | $ | 39,939 | $ | — | $ | 39,939 | ||||||||
|
Liabilities — current:
|
||||||||||||||||
|
Derivatives
|
$ | — | $ | 1,712 | $ | — | $ | 1,712 | ||||||||
| (a) | Values represent observable unadjusted quoted prices for traded instruments in active markets. | |
| (b) | Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1. | |
| (c) | Values with a significant amount of inputs that are not observable for the instrument. |
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, management’s judgment is
based on interpretation of laws and regulations, which can be
interpreted differently by regulators
and/or
courts of law. The Company’s 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. The Company
follows Statement of Financial Accounting Standards No. 123
(revised 2004), “Share-Based Payment”
(“SFAS No. 123R”) which requires the
measurement and
35
Table of Contents
recognition of compensation expense for all share-based payment
awards made to employees and directors, including employee stock
options, based on estimated fair values. Share-based
compensation expense recognized under SFAS No. 123R
for the years ended December 31, 2008, 2007 and 2006 was
$5.8 million, $5.7 million and $2.6 million,
respectively. See Note 6 for additional information.
Financial Statement Restatement. On
October 31, 2008, in connection with the preparation of our
quarterly report for the third quarter 2008, management
determined that the contemporaneous formal documentation we had
prepared in the first quarter of 2008 to support our initial
natural gas hedge designations for production sold on REX did
not meet the technical requirements to qualify for hedge
accounting treatment in accordance with Statement of Financial
Accounting Standards No. 133, “Accounting for
Derivative Instruments and Hedging Activities”
(“SFAS No. 133”). In order to cause the
hedge contracts to qualify for hedge accounting treatment under
SFAS No. 133, the Company was required to predict and
document the future relationship between prices at REX sales
points and the sales prices at the Northwest Pipeline Rockies
(the basis of the contracts) at the time the derivative
contracts were entered into. The actual relationship between the
sales prices at the two locations was different than that
predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133.
The Company restated the Consolidated Financial Statements for
the periods ended March 31, 2008 and June 30, 2008 to
reflect the inability to qualify for hedge accounting treatment
on the REX designated derivative contracts. The effect of the
restatement was to recognize a non-cash, after tax, mark to
market unrealized loss on commodity derivatives of
$18.0 million in the first quarter of 2008 and a non-cash,
after tax, mark to market unrealized gain on commodity
derivatives of $1.6 million in the second quarter of 2008.
There is no effect in any period on overall cash flows, total
assets, total liabilities or total stockholders’ equity.
Because these contracts were entered into and expire in fiscal
year 2008, there is no change in full-year 2008 net income
or operating cash flows as a result of the accounting treatment
of the derivative contracts, as restated. The restatement did
not have any impact on any of the financial covenants under the
Company’s Senior Credit Facility or Senior Notes due 2015
and 2018.
Recently issued accounting pronouncements. On
December 31, 2008, the SEC published a final rule to revise
its oil and gas reserves estimation and disclosure requirements.
The primary objectives of the revisions are to increase the
transparency and information value of reserve disclosures and
improve comparability among oil and gas companies. The rule is
effective for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009. The
Company anticipates that the implementation of the new rule will
provide a more meaningful and comprehensive understanding of oil
and gas reserves. The Company does not anticipate that the
implementation of the new reporting requirements will have a
material impact on the consolidated results of operations,
financial position or liquidity.
In March 2008, the Financial Accounting Standards Board
(“FASB”) issued SFAS No. 161,
“Disclosures about Derivative Instruments and Hedging
Activities” (“SFAS No. 161”). This
statement is intended to improve financial reporting about
derivative instruments and hedging activities by requiring
enhanced disclosures to increase transparency about the location
and amounts of derivative instruments in an entity’s
financial statements; how derivative instruments and related
hedged items are accounted for under SFAS No. 133; and
how derivative instruments and related hedged items affect
financial position, financial performance, and cash flows.
SFAS No. 161 is effective as of the beginning of an
entity’s first fiscal year that begins after
November 15, 2008. The Company does not anticipate that the
implementation of SFAS No. 161 will have a material
impact on the consolidated results of operations, financial
position or liquidity.
In February 2008, the FASB issued FASB Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157 (“FSP
SFAS 157-2”).
FSP
SFAS 157-2
delays the effective date of SFAS 157 to fiscal years
beginning after November 15, 2008 for all non-financial
assets and non-financial liabilities, such as the asset
retirement obligation, except those that are recognized or
disclosed at fair value in the financial statements on a
recurring basis (at least annually). FSP
SFAS 157-2
is effective for the Company’s fiscal year beginning
January 1, 2009. The adoption of FSP
FAS 157-2
is not expected to have a material impact on the Company’s
consolidated financial statements.
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Table of Contents
Results
of Operations — Year Ended December 31, 2008
Compared to Year Ended December 31, 2007
Oil and natural gas revenues from continuing operations
increased 91% to $1.1 billion for the year ended
December 31, 2008 from $566.6 million for the same
period in 2007. This increase was attributable to an increase in
the Company’s production volumes and higher prices received
in 2008. During 2008, the Company’s production from
continuing operations increased to 138.6 Bcf of natural gas
and 1.1 million barrels of condensate up from 2007 levels
of 109.2 Bcf of natural gas and 870.1 thousand barrels of
condensate. This 27% increase on an Mcfe basis was attributable
to the Company’s successful drilling activities in Wyoming
during 2008 and 2007. Realized natural gas prices, including
realized gains and losses on commodity derivatives, increased
56% to $7.26 per Mcf during 2008 as compared to $4.66 for the
same period in 2007. During the year ended December 31,
2008, the Company’s average price realization for natural
gas was $7.11 per Mcf, excluding gains and losses on commodity
derivatives as compared to $4.65 for the same period in 2007.
During the year ended December 31, 2008, the average
product prices received for condensate were $87.40 per barrel
compared to $66.08 per barrel for the same period in 2007.
Lease operating expense (“LOE”) increased to
$37.0 million for the year ended December 31, 2008
compared to $24.0 million during the same period in 2007
due primarily to increased production volumes as well as
increased water disposal costs on non-operated properties in
Wyoming. On a unit of production basis, LOE costs increased to
$0.25 per Mcfe during the year ended December 31, 2008 as
compared to $0.21 per Mcfe during the same period in 2007 mainly
due to costs related to non-operated properties for water
disposal costs.
During the year ended December 31, 2008 production taxes
were $119.5 million compared to $63.5 million during
the same period in 2007, or $0.82 per Mcfe during the year ended
December 31, 2008 as compared to $0.55 per Mcfe during the
same period in 2007. The increase in per unit taxes is largely
attributable to increased sales revenues as a result of
increased production and higher realized gas prices received
during the year ended December 31, 2008 as compared to the
same period in 2007. Production taxes are calculated based on a
percentage of revenue from production. Therefore, higher prices
received increased production taxes on a per unit basis.
Gathering fees increased to $37.7 million during 2008
compared to $27.9 million during 2007 largely due to
increased production volumes. On a per unit basis, gathering
fees increased slightly to $0.26 per Mcfe for the year ended
December 31, 2008 compared to $0.24 per Mcfe for the year
ended December 31, 2007.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Company’s natural gas
production away from southwest Wyoming and to mitigate
volatility and provide for reasonable basis differentials for
its natural gas, the Company incurred transportation demand
charges totaling $46.3 million, or $0.32 per Mcfe, for the
year ended December 31, 2008 in association with the REX
Pipeline. The REX Pipeline became operational beginning in the
first quarter of 2008.
DD&A expenses increased to $184.8 million during the
year ended December 31, 2008 from $135.5 million for
the same period in 2007, attributable to increased production
volumes and a higher depletion rate, due to higher development
costs. On a unit basis, DD&A increased to $1.27 per Mcfe
for the year ended December 31, 2008 from $1.18 per Mcfe
for the same period in 2007.
General and administrative expenses increased by 28% to
$17.0 million during the year ended December 31, 2008
compared to $13.3 million for the same period in 2007. The
increase in general and administrative expenses during 2008 is
primarily attributable to increased Medicare taxes as a result
of increased employee stock option exercises as well as higher
compensation costs related to increased personnel during 2008 as
compared to 2007. On a per unit basis, general and
administrative expenses remained flat at $0.12 per Mcfe during
the years ended December 31, 2008 and 2007.
Interest expense increased to $21.3 million during the year
ended December 31, 2008 from $17.8 million during the
same period in 2007. The increase is related to higher average
outstanding debt balances during the year ended
December 31, 2008 as compared to the same period in 2007.
The increase in debt balances during 2008 is primarily related
to the issuance of the Senior Notes on March 6, 2008 (See
Note 5) as well as increased share repurchase activity
in 2008 as compared to 2007 (See Note 8).
During the year ended December 31, 2008, the Company
recognized $19.0 million and $14.2 million related to
realized gain on commodity derivatives and unrealized gain on
commodity derivatives, respectively. These amounts
37
Table of Contents
relate to derivative contracts that the Company entered into
during the first quarter of 2008 in order to mitigate commodity
price exposure on a portion of the forecasted production which
was expected to be sold on REX. Due to limited historical data
correlating REX sales points and NWPL — Rockies (the
basis of the contracts), the Company was unable to effectively
demonstrate correlation between the derivative instrument and
the forecasted transaction according to the contemporaneous
documentation as set forth under the requirements of
SFAS No. 133 causing the derivative contracts to no
longer qualify for hedge accounting treatment. The realized gain
on commodity derivatives relates to actual amounts received
under these derivative contracts while the unrealized gain on
commodity derivatives represents the change in the fair value of
these derivative instruments.
Income before income taxes increased by 129% to
$654.4 million for the year ended December 31, 2008
from $285.9 million for the same period in 2007 largely as
a result of increased realized natural gas prices and increased
production volumes during the year ended December 31, 2008
as compared to 2007.
The income tax provision increased 128% to $240.5 million
for the year ended December 31, 2008 as compared to
$105.6 million for the year ended December 31, 2007
attributable to increased pre-tax income and withholding taxes
related to share repurchases (See Note 8).
Discontinued operations, net of tax, (which is comprised
entirely of results associated with the Chinese operations)
decreased to $0.4 million for the year ended
December 31, 2008 from $82.8 million for the same
period in 2007. The decrease is primarily related to the closing
of the sale of
Sino-American
Energy Corporation for net proceeds of $208.0 million,
which resulted in a pre-tax gain on sale of properties of
$98.1 million during the quarter ended December 31,
2007. (See Note 11).
For the year ended December 31, 2008, net income increased
by 57% to $414.3 million or $2.65 per diluted share as
compared with $263.0 million or $1.66 per diluted share for
the same period in 2007 primarily attributable to increased gas
prices realized in 2008 as well as increased natural gas
production during 2008.
Results
of Operations — Year Ended December 31, 2007
Compared to Year Ended December 31, 2006
Oil and natural gas revenues from continuing operations
increased 11% to $566.6 million for the year ended
December 31, 2007 from $508.7 million for the same
period in 2006. This increase was attributable to an increase in
the Company’s production volumes offset in part by lower
prices received. During 2007, the Company’s production from
continuing operations increased to 109.2 Bcf of natural gas
and 870.1 thousand barrels of condensate up from 2006 levels of
78.4 Bcf of natural gas and 594.1 thousand barrels of
condensate. This 40% increase on an Mcfe basis was attributable
to the Company’s successful drilling activities during 2007
and 2006 in Wyoming. During the year ended December 31,
2007, the average product prices received were $4.66 per Mcf
including the effects of hedging and $66.08 per barrel of
condensate compared to $6.00 per Mcf including the effects of
hedging and $64.52 per barrel of condensate for the same period
in 2006.
Lease operating expense (“LOE”) increased to
$24.0 million for the year ended December 31, 2007
compared to $15.1 million during the same period in 2006
due to increased production volumes as well as increased water
disposal costs in Wyoming. On a unit of production basis, LOE
costs increased to $0.21 per Mcfe during the year ended
December 31, 2007 as compared to $0.18 per Mcfe during the
same period in 2006 due to increased water disposal costs in
Wyoming. During the year ended December 31, 2007 production
taxes were $63.5 million compared to $57.9 million
during the same period in 2006, or $0.55 per Mcfe during the
year ended December 31, 2007 as compared to $0.71 per Mcfe
during the same period in 2006. Production taxes are calculated
based on a percentage of revenue from production. Therefore,
lower prices received decreased production taxes on a per unit
basis. Gathering fees increased to $27.9 million during
2007 compared to $19.7 million during 2006 largely due to
increased production volumes. On a per unit basis, gathering
fees remained flat at $0.24 per Mcfe for the years ended
December 31, 2007 and 2006.
DD&A expenses increased to $135.5 million during the
year ended December 31, 2007 from $79.7 million for
the same period in 2006, attributable to increased production
volumes and a higher depletion rate, due to higher development
costs. On a unit basis, DD&A increased to $1.18 per Mcfe
for the year ended December 31, 2007 from $0.97 per Mcfe
for the same period in 2006.
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Table of Contents
General and administrative expenses decreased by 11% to
$13.3 million during the year ended December 31, 2007
compared to $14.9 million for the same period in 2006. On a
per unit basis, general and administrative expenses decreased to
$0.12 per Mcfe during the year ended December 31, 2007
compared with $0.18 per Mcfe for the same period in 2006. This
decrease was primarily attributable to a reduction in year over
year compensation expense in combination with higher production
volumes.
Interest expense increased to $17.8 million during the year
ended December 31, 2007 from $3.9 million during the
same period in 2006. The increase is related to increased
borrowings under the Company’s senior bank facility during
2007.
Income before income taxes decreased by 11% to
$285.9 million for the year ended December 31, 2007
from $319.4 million for the same period in 2006 largely as
a result of reduced realized natural gas prices offset in part
by increased production volumes.
The income tax provision decreased 14% to $105.6 million
for the year ended December 31, 2007 as compared to
$122.7 million for the year ended December 31, 2006
attributable to decreased pre-tax income and lower withholding
taxes related to share repurchases (See Note 8).
Discontinued operations, net of tax, (which is comprised
entirely of results associated with the Chinese operations)
increased to $82.8 million for the year ended
December 31, 2007 from $34.5 million for the same
period in 2006. The increase is primarily related to the closing
of the sale of
Sino-American
Energy Corporation for net proceeds of $208.0 million,
which resulted in a pre-tax gain on sale of properties of
$98.1 million during the quarter ended December 31,
2007. (See Note 11).
For the year ended December 31, 2007, net income increased
by 14% to $263.0 million or $1.66 per diluted share as
compared with $231.2 million or $1.43 per diluted share for
the same period in 2006.
Liquidity
and Capital Resources
During the year-ended December 31, 2008, the Company relied
on cash provided by operations, borrowings under its senior
credit facility and proceeds from issuance of the Notes to
finance its capital expenditures. The Company participated in
the drilling of 307 wells in Wyoming. For the year ended
December 31, 2008, net capital expenditures were
$949.7 million. At December 31, 2008, the Company
reported a cash position of $14.2 million compared to
$10.6 million at December 31, 2007. The working
capital deficit at December 31, 2008 was
$149.4 million as compared to a working capital deficit of
$67.5 million at December 31, 2007. As of
December 31, 2008, the Company had $570.0 million in
outstanding bank indebtedness and other long-term obligations of
$46.2 million comprised of items payable in more than one
year, primarily related to production taxes.
The Company’s positive cash provided by operating
activities, along with availability under its senior credit
facility, are projected to be sufficient to fund the
Company’s budgeted capital expenditures for 2009, which are
currently projected to be $720.0 million. Of the
$720.0 million budget, the Company plans to allocate
approximately 90% to Wyoming and 10% to Pennsylvania. The
Company plans to drill or participate in an estimated
200 gross wells in 2009. The Company currently has no
budget for acquisitions in 2009.
Bank indebtedness: The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (87.5 basis points
per annum as of December 31, 2008).
At December 31, 2008, we had $270.0 million in
outstanding borrowings and $230.0 million of available
borrowing capacity under our credit facility.
39
Table of Contents
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At December 31, 2008, we were in compliance with
all of our debt covenants under our credit facility. The
Company’s commitment fees were $0.7 million,
$0.4 million and $0.4 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes
(“the Notes”) pursuant to a Master Note Purchase
Agreement between the Company and the purchasers of the Notes.
The Notes rank pari passu with the Company’s bank credit
facility. Payment of the Notes is guaranteed by Ultra Petroleum
Corp. and UP Energy Corporation. Of the Notes,
$200.0 million are 5.92% Senior Notes due 2018 and
$100.0 million are 5.45% Senior Notes due 2015.
Proceeds from the sale of the Notes were used to repay bank
debt, but did not reduce the borrowings available to us under
the revolving credit facility.
The Notes are pre-payable in whole or in part at any time. The
Notes are subject to representations, warranties, covenants and
events of default customary for a senior note financing. If
payment default occurs, any Note holder may accelerate its
Notes; if a non-payment default occurs, holders of 51% of the
outstanding principal amount of the Notes may accelerate all the
Notes. At December 31, 2008, we were in compliance with all
of our debt covenants under the Notes.
Operating Activities. During the year ended
December 31, 2008, net cash provided by operating
activities was $840.8 million, a 96% increase from the
$427.9 million for the same period in 2007. The increase in
net cash provided by operating activities was largely
attributable 56% higher realized natural gas prices during the
year ended December 31, 2008 as compared to the same period
in 2007 as well as the 27% increase in production from
continuing operations during the year ended December 31,
2008.
Investing Activities. During the year ended
December 31, 2008, net cash used in investing activities
was $915.3 million as compared to $507.1 million for
the same period in 2007. The increase in net cash used in
investing activities is largely due to increased capital
expenditures associated with the Company’s drilling
activities in 2008. The year ended December 31, 2007
includes $208.0 million associated with proceeds from the
sale of our Bohai Bay assets (See Note 11).
Financing Activities During the year ended
December 31, 2008, net cash provided by financing
activities was $78.0 million as compared to
$75.2 million for the same period in 2007. The slight
increase in net cash provided by financing activities is
primarily attributable to increased borrowings related to the
issuance of the Senior Notes offset by increased share
repurchase activity during the year ended December 31, 2008
(See Note 8).
Off-Balance
Sheet Arrangements
The Company did not have any off-balance sheet arrangements as
of December 31, 2008.
Contractual
Obligations
The following table summarizes our contractual obligations as of
December 31, 2008:
| Payments Due by Period: | ||||||||||||||||||||
|
Less than |
More than |
|||||||||||||||||||
| Total | One Year | 1-3 Years | 3-5 Years | 5 Years | ||||||||||||||||
| (Amounts in thousands of U.S. dollars) | ||||||||||||||||||||
|
Long-term debt (See Note 5)
|
$ | 570,000 | $ | — | $ | — | $ | 270,000 | $ | 300,000 | ||||||||||
|
Transportation contract (REX)
|
562,100 | 56,210 | 168,630 | 112,420 | 224,840 | |||||||||||||||
|
Drilling contracts
|
203,129 | 61,713 | 114,740 | 26,676 | — | |||||||||||||||
|
Office space lease
|
2,285 | 845 | 1,440 | — | — | |||||||||||||||
|
Total contractual obligations
|
$ | 1,337,514 | $ | 118,768 | $ | 284,810 | $ | 409,096 | $ | 524,840 | ||||||||||
40
Table of Contents
Transportation contract. In December 2005, the
Company agreed to become an anchor shipper on REX securing
pipeline infrastructure providing sufficient capacity to
transport a portion of its natural gas production away from
southwest Wyoming and to provide for reasonable basis
differentials for its natural gas in the future. The
Company’s commitment involves capacity of 200 MMBtu
per day of natural gas for a term of 10 years (beginning in
the first quarter of 2008), and the Company is obligated to pay
REX certain demand charges related to its rights to hold this
firm transportation capacity as an anchor shipper. The pipeline
is being built in two phases: REX — West (Wyoming to
Missouri — in service) and REX — East
(Missouri to Ohio — under construction).
Drilling contracts. As of December 31,
2008, the Company had committed to drilling obligations with
certain rig contractors that will continue into 2012. The
drilling rigs were contracted to fulfill the
2009-2012
drilling program initiatives in Wyoming.
Office space lease. In May 2007, the Company
amended its office leases in Englewood, Colorado and Houston,
Texas, both of which it has committed through 2012. The
Company’s total remaining commitment for office leases is
$2.3 million at December 31, 2008 ($0.8 million
in 2009, $0.7 million in 2010 and 2011, and
$0.1 million in 2012).
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
The Company’s 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 Company’s Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable, ranging from $4.24 per Mcf to a
monthly high of $8.81 per Mcf during 2008. Pricing volatility is
expected to continue. Realized natural gas prices are derived
from the financial statements which include the effects of
realized hedging gains and losses 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, from time to time, also uses derivative instruments 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 natural gas
production. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas
index prices as reported by such publications as Inside FERC Gas
Market Report. Based on management’s current estimates,
future production is expected to be sufficient to meet delivery
requirements associated with the Company’s derivative
contracts and fixed price forward physical delivery contracts.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivative’s fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. 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 Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Company and the Audit Committee of the Board of Directors
determined that the contemporaneous formal documentation we had
prepared in the first quarter of 2008 to support our initial
natural gas hedge designations for production sold on REX did
not meet the technical requirements to qualify for hedge
accounting treatment in accordance with SFAS No. 133.
In order to cause the hedge contracts to qualify for hedge
accounting treatment under SFAS No. 133, the Company
was required to predict and document the future relationship
between prices at REX sales points and the sales prices at the
Northwest Pipeline Rockies (the basis of the contracts) at the
time the hedge contracts were entered into. The actual
relationship between the sales prices at the two locations was
different than that predicted by the Company, which affected our
ability to effectively demonstrate ongoing effectiveness between
the derivative instrument and the forecasted transaction as
outlined in our contemporaneous documentation as set forth under
the requirements of SFAS No. 133. While such
derivatives no longer qualify for
41
Table of Contents
hedge accounting treatment, the Company believes that these
contracts remain a valuable component of our commodity price
risk management program.
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The
Company has historically followed hedge accounting for its
natural gas hedges. Under this accounting method, the unrealized
gain or loss on qualifying cash flow hedges (calculated on a
mark to market basis, net of tax) was recorded on the balance
sheet in stockholders’ equity as accumulated other
comprehensive income. When an unrealized hedging gain or loss
was realized upon contract expiration, it was reclassified into
earnings through inclusion in natural gas sales revenues. The
Company continues to record the fair value of its commodity
derivatives as an asset or liability on the Consolidated Balance
Sheets, but records the changes in the fair value of its
commodity derivatives in the Consolidated Statements of Income
as gains or losses on commodity derivatives. There is no
resulting effect on overall cash flow, total assets, total
liabilities or total stockholders’ equity, and there is no
impact on any of the financial covenants under the
Company’s senior credit facility or senior notes due 2015
and 2018.
The Company also utilizes fixed price forward physical delivery
contracts at southwest Wyoming delivery points to mitigate its
commodity price exposure. 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, 2008.
(In November 2007, the Minerals Management Service commenced a
Royalty-in-Kind
program which had the effect of increasing the Company’s
average net interest in physical gas sales from 80% to
approximately 91%.)
|
Volume- |
Average |
|||||||
|
Remaining Contract Period
|
MMBTU/Day | Price/MMBTU | ||||||
|
Summer 2009 (April — October)
|
130,000 | $ | 6.15 | |||||
|
Calendar 2009
|
60,000 | $ | 5.04 | |||||
|
Calendar 2010
|
20,000 | $ | 5.17 | |||||
At December 31, 2008, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price.
|
Volume- |
Average |
|||||||||||||
|
Type
|
Point of Sale
|
Remaining Contract Period | MMBTU/Day | Price/MMBTU | ||||||||||
|
Swap
|
NWPL — Rockies | Jan 2009 — Dec 2009 | 40,000 | $ | 6.57 | |||||||||
|
Swap
|
Mid-Continent | Apr 2009 — Oct 2009 | 110,000 | $ | 4.99 | |||||||||
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Income for the years ended December 31, 2008
and 2007 (refer to Note 1(n) for details of unrealized
gains or losses included in accumulated other comprehensive
income in the Consolidated Balance Sheets):
| For the Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Realized gain (loss) on derivatives designated as cash flow
hedges(1)
|
$ | 1,148 | $ | 1,107 | $ | — | ||||||
|
Realized gain (loss) on commodity derivatives(2)
|
$ | 18,991 | $ | — | $ | — | ||||||
|
Unrealized gain (loss) on commodity derivatives(3)
|
$ | 14,225 | $ | — | $ | — | ||||||
| (1) | Included in natural gas sales in the income statement. (Related tax expense of $403 and $389, respectively). | |
| (2) | Included in gain on commodity derivatives in the income statement. (Related tax expense of $6,666). | |
| (3) | Included in gain on commodity derivatives in the income statement. (Related tax expense of $4,993). |
42
Table of Contents
Subsequent to December 31, 2008 and through
February 13, 2009, the Company has entered into the
following fixed price physical delivery contracts on behalf of
its interest and those of other parties:
|
Volume- |
Average |
|||||||
|
Remaining Contract Period
|
MMBTU/Day | Price/MMBTU | ||||||
|
Calendar 2010
|
30,000 | $ | 4.87 | |||||
Subsequent to December 31, 2008 and through
February 13, 2009, the Company has entered into the
following open commodity derivative contracts to manage price
risk on a portion of its natural gas production whereby the
Company receives the fixed price and pays the variable price:
|
Volume- |
Average |
|||||||||||||||
|
Type
|
Point of Sale
|
Remaining Contract Period | MMBTU/Day | Price/MMBTU | ||||||||||||
|
Swap
|
Mid-Continent | Apr 2009 — Oct 2009 | 20,000 | $ | 5.02 | |||||||||||
43
Table of Contents
| Item 8. | Financial Statements and Supplementary Data. |
MANAGEMENT’S
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 management’s 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, 2008.
The effectiveness of our internal control over financial
reporting has been audited by Ernst & Young LLP, an
independent registered public accounting firm, as stated in
their report which is included herein.
44
Table of Contents
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
Ultra Petroleum Corp.
Ultra Petroleum Corp.
We have audited Ultra Petroleum Corp.’s internal control
over financial reporting as of December 31, 2008, based on
criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (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 included in the accompanying
Management’s Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
company’s 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, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, 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 company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (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
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Ultra Petroleum Corp. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2008, 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 sheets of Ultra Petroleum Corp. as of
December 31, 2008 and 2007, and the related consolidated
statements of operations, shareholders’ equity, and cash
flows for each of the three years in the period ended
December 31, 2008 of Ultra Petroleum Corp. and our report
dated February 19, 2009 expressed an unqualified opinion
thereon.
/s/ Ernst &
Young LLP
Houston, Texas
February 19, 2009
45
Table of Contents
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
Ultra Petroleum Corp.
Ultra Petroleum Corp.
We have audited the accompanying consolidated balance sheets of
Ultra Petroleum Corp. as of December 31, 2008 and 2007, and
the related consolidated statements of operations,
shareholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2008. These
financial statements are the responsibility of the
Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits 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 financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Ultra Petroleum Corp. at December 31,
2008 and 2007, and the consolidated results of their operations
and their cash flows for each of the three years in the period
ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), Ultra
Petroleum Corp.’s internal control over financial reporting
as of December 31, 2008, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our
report dated February 19, 2009 expressed an unqualified
opinion thereon.
/s/ Ernst &
Young LLP
Houston, Texas
February 19, 2009
46
Table of Contents
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (Amounts in thousands of U.S. dollars, except per share data) | ||||||||||||
|
REVENUES:
|
||||||||||||
|
Natural gas sales
|
$ | 986,374 | $ | 509,140 | $ | 470,324 | ||||||
|
Oil sales
|
98,026 | 57,498 | 38,335 | |||||||||
| 1,084,400 | 566,638 | 508,659 | ||||||||||
|
EXPENSES:
|
||||||||||||
|
Lease operating expenses
|
36,997 | 23,968 | 15,068 | |||||||||
|
Production taxes
|
119,502 | 63,480 | 57,899 | |||||||||
|
Gathering fees
|
37,744 | 27,923 | 19,721 | |||||||||
|
Transportation charges
|
46,310 | — | — | |||||||||
|
Depletion, depreciation and amortization
|
184,795 | 135,470 | 79,675 | |||||||||
|
General and administrative, excluding depreciation and
amortization
|
17,046 | 13,261 | 14,885 | |||||||||
| 442,394 | 264,102 | 187,248 | ||||||||||
|
OPERATING INCOME
|
642,006 | 302,536 | 321,411 | |||||||||
|
OTHER INCOME (EXPENSE):
|
||||||||||||
|
Interest income
|
418 | 1,087 | 1,941 | |||||||||
|
Gain on commodity derivatives
|
33,216 | — | — | |||||||||
|
Interest expense
|
(21,276 | ) | (17,760 | ) | (3,909 | ) | ||||||
| 12,358 | (16,673 | ) | (1,968 | ) | ||||||||
|
INCOME BEFORE INCOME TAX PROVISION
|
654,364 | 285,863 | 319,443 | |||||||||
|
Income tax provision
|
240,504 | 105,621 | 122,741 | |||||||||
|
NET INCOME FROM CONTINUING OPERATIONS
|
413,860 | 180,242 | 196,702 | |||||||||
|
Income from discontinued operations (including pre-tax gain on
sale in 2007 of $98,066)
|
415 | 82,794 | 34,493 | |||||||||
|
NET INCOME
|
$ | 414,275 | $ | 263,036 | $ | 231,195 | ||||||
|
Basic Earnings per Share:
|
||||||||||||
|
Income per common share from continuing operations
|
$ | 2.72 | $ | 1.19 | $ | 1.28 | ||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.54 | $ | 0.22 | ||||||
|
Net income per common share
|
$ | 2.72 | $ | 1.73 | $ | 1.50 | ||||||
|
Fully Diluted Earnings per Share:
|
||||||||||||
|
Income per common share from continuing operations
|
$ | 2.65 | $ | 1.14 | $ | 1.22 | ||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.52 | $ | 0.21 | ||||||
|
Net income per common share
|
$ | 2.65 | $ | 1.66 | $ | 1.43 | ||||||
|
Weighted average common shares outstanding — basic
|
152,075 | 151,762 | 153,879 | |||||||||
|
Weighted average common shares outstanding — diluted
|
156,531 | 158,616 | 161,615 | |||||||||
Approved on behalf of the Board:
|
/s/ Michael
D. Watford
|
/s/ Stephen
J. McDaniel
|
|
|
Chairman of the Board,
Chief Executive Officer and President |
Director |
See accompanying notes to consolidated financial statements.
47
Table of Contents
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
| December 31, | ||||||||
| 2008 | 2007 | |||||||
|
(Amounts in thousands of |
||||||||
| U.S. dollars, except share data) | ||||||||
|
ASSETS
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | 14,157 | $ | 10,632 | ||||
|
Restricted cash
|
2,727 | 2,590 | ||||||
|
Accounts receivable
|
126,710 | 135,849 | ||||||
|
Derivative assets
|
39,939 | 5,625 | ||||||
|
Inventory
|
8,522 | 13,333 | ||||||
|
Prepaid expenses and other current assets
|
6,163 | 424 | ||||||
|
Total current assets
|
198,218 | 168,453 | ||||||
|
Oil and gas properties, using the full cost method of accounting
Proved
|
2,294,982 | 1,537,751 | ||||||
|
Unproved
|
55,544 | 36,778 | ||||||
|
Property, plant and equipment
|
5,770 | 4,739 | ||||||
|
Deferred financing costs, derivative assets and other
|
3,648 | 3,861 | ||||||
|
TOTAL ASSETS
|
$ | 2,558,162 | $ | 1,751,582 | ||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
|
Current liabilities
|
||||||||
|
Accounts payable and accrued liabilities
|
$ | 163,902 | $ | 102,405 | ||||
|
Production taxes payable
|
61,416 | 34,269 | ||||||
|
Derivative liabilities
|
1,712 | — | ||||||
|
Current taxes payable
|
— | 10,839 | ||||||
|
Capital cost accrual
|
120,543 | 88,445 | ||||||
|
Total current liabilities
|
347,573 | 235,958 | ||||||
|
Long-term debt
|
570,000 | 290,000 | ||||||
|
Deferred income tax liability
|
503,597 | 341,406 | ||||||
|
Other long-term obligations
|
46,206 | 26,672 | ||||||
|
Shareholders’ equity:
|
||||||||
|
Common stock — no par value; authorized —
unlimited; issued and outstanding — 151,232,545 and
152,003,671 at December 31, 2008 and 2007, respectively
|
346,832 | 256,889 | ||||||
|
Treasury stock
|
(45,740 | ) | (59,245 | ) | ||||
|
Retained earnings
|
774,117 | 654,948 | ||||||
|
Accumulated other comprehensive income
|
15,577 | 4,954 | ||||||
|
Total shareholders’ equity
|
1,090,786 | 857,546 | ||||||
|
Commitments and contingencies (Note 12)
|
||||||||
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
$ | 2,558,162 | $ | 1,751,582 | ||||
See accompanying notes to consolidated financial statements.
48
Table of Contents
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY
|
Accumulated |
||||||||||||||||||||||||
|
Other |
||||||||||||||||||||||||
|
Shares |
Comprehensive |
Total |
||||||||||||||||||||||
|
Issued and |
Common |
Retained |
Income |
Treasury |
Shareholders’ |
|||||||||||||||||||
| Outstanding | Stock | Earnings | (Loss) | Stock | Equity | |||||||||||||||||||
| (Amounts in thousands) | ||||||||||||||||||||||||
|
Balances at December 31, 2005
|
155,076 | $ | 180,511 | $ | 392,399 | $ | — | $ | — | $ | 572,910 | |||||||||||||
|
Stock options exercised
|
656 | 9,203 | — | — | — | 9,203 | ||||||||||||||||||
|
Employee stock plan grants
|
34 | 2,141 | — | — | — | 2,141 | ||||||||||||||||||
|
Shares repurchased and retired
|
(3,970 | ) | (3,302 | ) | (194,249 | ) | — | — | (197,551 | ) | ||||||||||||||
|
Fair value of employee stock plan grants
|
— | 2,857 | — | — | — | 2,857 | ||||||||||||||||||
|
Tax benefit of stock options exercised
|
— | 10,503 | — | — | — | 10,503 | ||||||||||||||||||
|
Comprehensive earnings:
|
||||||||||||||||||||||||
|
Net earnings
|
— | — | 231,195 | — | — | 231,195 | ||||||||||||||||||
|
Total comprehensive earnings
|
231,195 | |||||||||||||||||||||||
|
Balances at December 31, 2006
|
151,796 | $ | 201,913 | $ | 429,345 | $ | — | $ | — | $ | 631,258 | |||||||||||||
|
Stock options exercised
|
1,849 | 11,686 | — | — | — | 11,686 | ||||||||||||||||||
|
Employee stock plan grants
|
56 | 877 | — | — | — | 877 | ||||||||||||||||||
|
Shares repurchased and retired
|
(364 | ) | (317 | ) | (19,326 | ) | — | — | (19,643 | ) | ||||||||||||||
|
Shares repurchased
|
(1,068 | ) | — | — | — | (59,245 | ) | (59,245 | ) | |||||||||||||||
|
Net share settlements
|
(265 | ) | — | (18,107 | ) | — | — | (18,107 | ) | |||||||||||||||
|
Fair value of employee stock plan grants
|
— | 6,038 | — | — | — | 6,038 | ||||||||||||||||||
|
Tax benefit of stock options exercised
|
— | 36,692 | — | — | — | 36,692 | ||||||||||||||||||
|
Comprehensive earnings:
|
||||||||||||||||||||||||
|
Net earnings
|
— | — | 263,036 | — | — | 263,036 | ||||||||||||||||||
|
Change in derivative instruments fair value, net of taxes
|
— | — | — | 4,954 | — | 4,954 | ||||||||||||||||||
|
Total comprehensive earnings
|
267,990 | |||||||||||||||||||||||
|
Balances at December 31, 2007
|
152,004 | $ | 256,889 | $ | 654,948 | $ | 4,954 | $ | (59,245 | ) | $ | 857,546 | ||||||||||||
|
Stock options exercised
|
3,595 | 19,086 | — | — | — | 19,086 | ||||||||||||||||||
|
Employee stock plan grants
|
151 | 997 | — | — | — | 997 | ||||||||||||||||||
|
Shares repurchased and retired
|
— | (1,669 | ) | (108,741 | ) | — | 110,410 | — | ||||||||||||||||
|
Shares reissued from treasury
|
— | (14,885 | ) | (135,581 | ) | — | 150,466 | — | ||||||||||||||||
|
Shares repurchased
|
(3,661 | ) | — | — | — | (247,371 | ) | (247,371 | ) | |||||||||||||||
|
Net share settlements
|
(856 | ) | (152 | ) | (50,784 | ) | — | — | (50,936 | ) | ||||||||||||||
|
Fair value of employee stock plan grants
|
— | 7,726 | — | — | — | 7,726 | ||||||||||||||||||
|
Tax benefit of stock options exercised
|
— | 78,840 | — | — | — | 78,840 | ||||||||||||||||||
|
Comprehensive earnings:
|
||||||||||||||||||||||||
|
Net earnings
|
— | — | 414,275 | — | — | 414,275 | ||||||||||||||||||
|
Change in derivative instruments fair value, net of taxes
|
— | — | — | 14,273 | — | 14,273 | ||||||||||||||||||
|
Reclassification of derivative fair value into earnings, net of
taxes
|
— | — | — | (3,650 | ) | — | (3,650 | ) | ||||||||||||||||
|
Total comprehensive earnings
|
424,898 | |||||||||||||||||||||||
|
Balances at December 31, 2008
|
151,233 | $ | 346,832 | $ | 774,117 | $ | 15,577 | $ | (45,740 | ) | $ | 1,090,786 | ||||||||||||
See accompanying notes to consolidated financial statements.
49
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ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (Amounts in thousands of U.S. dollars) | ||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net income
|
$ | 414,275 | $ | 263,036 | $ | 231,195 | ||||||
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
||||||||||||
|
Income from discontinued operations (including pre-tax gain on
sale in 2007 of $98,066)
|
(415 | ) | (82,794 | ) | (34,493 | ) | ||||||
|
Depletion, depreciation and amortization
|
184,795 | 135,470 | 79,675 | |||||||||
|
Deferred and current non-cash income taxes
|
235,031 | 127,802 | 105,681 | |||||||||
|
Stock compensation
|
5,816 | 5,718 | 2,626 | |||||||||
|
Excess tax benefit from stock based compensation
|
(78,840 | ) | (36,692 | ) | (10,503 | ) | ||||||
|
Unrealized (gain) on commodity derivatives
|
(14,225 | ) | — | — | ||||||||
|
Other
|
426 | 177 | — | |||||||||
|
Net changes in non-cash working capital:
|
||||||||||||
|
Restricted cash
|
(137 | ) | (1,923 | ) | (453 | ) | ||||||
|
Accounts receivable
|
9,139 | (48,044 | ) | (12,149 | ) | |||||||
|
Prepaid expenses and other current assets
|
(5,543 | ) | (273 | ) | 128 | |||||||
|
Accounts payable and accrued liabilities
|
86,487 | 58,019 | 28,635 | |||||||||
|
Other long-term obligations
|
14,833 | 413 | 129 | |||||||||
|
Taxation payable
|
(10,839 | ) | 8,632 | 2,207 | ||||||||
|
Net cash provided by operating activities from continuing
operations
|
840,803 | 429,541 | 392,678 | |||||||||
|
Net cash provided by operating activities from discontinued
operations
|
— | (1,592 | ) | 44,655 | ||||||||
|
Net cash provided by operating activities
|
840,803 | 427,949 | 437,333 | |||||||||
|
Cash flows from investing activities:
|
||||||||||||
|
Oil and gas property expenditures
|
(949,650 | ) | (696,124 | ) | (480,432 | ) | ||||||
|
Change in capital costs accrual
|
32,097 | (6,422 | ) | 47,987 | ||||||||
|
Post closing adjustments on sale of subsidiary
|
640 | — | — | |||||||||
|
Proceeds on sale of subsidiary, net of transaction costs
|
— | 208,032 | — | |||||||||
|
Inventory
|
4,811 | 5,596 | 1,677 | |||||||||
|
Purchase of capital assets
|
(1,356 | ) | (3,702 | ) | (623 | ) | ||||||
|
Other
|
(1,861 | ) | — | — | ||||||||
|
Investing activities from discontinued operations
|
— | (14,450 | ) | (22,491 | ) | |||||||
|
Net cash (used in) investing activities
|
(915,319 | ) | (507,070 | ) | (453,882 | ) | ||||||
|
Cash flows from financing activities:
|
||||||||||||
|
Borrowings of long-term debt, gross
|
662,000 | 396,000 | 180,000 | |||||||||
|
Payments on long-term debt, gross
|
(682,000 | ) | (271,000 | ) | (15,000 | ) | ||||||
|
Proceeds from issuance of Senior Notes
|
300,000 | — | — | |||||||||
|
Repurchased shares
|
(298,307 | ) | (96,995 | ) | (197,551 | ) | ||||||
|
Proceeds from issuance of common stock
|
19,086 | 11,686 | 9,203 | |||||||||
|
Excess tax benefit from stock based compensation
|
78,840 | 36,692 | 10,503 | |||||||||
|
Deferred financing costs
|
(1,578 | ) | (1,204 | ) | — | |||||||
|
Net cash provided by (used in) financing activities
|
78,041 | 75,179 | (12,845 | ) | ||||||||
|
Net (decrease)/increase in cash and cash equivalents
|
3,525 | (3,942 | ) | (29,394 | ) | |||||||
|
Cash and cash equivalents, beginning of year
|
10,632 | 14,574 | 43,968 | |||||||||
|
Cash and cash equivalents, end of year
|
$ | 14,157 | $ | 10,632 | $ | 14,574 | ||||||
|
SUPPLEMENTAL INFORMATION
|
||||||||||||
|
Cash paid for:
|
||||||||||||
|
Interest
|
$ | 16,092 | $ | 16,218 | $ | 1,913 | ||||||
|
Income taxes
|
$ | 16,322 | $ | 21,513 | $ | 21,380 | ||||||
See accompanying notes to consolidated financial statements.
50
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2008, 2007 and 2006
DESCRIPTION OF THE BUSINESS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2008, 2007 and 2006
DESCRIPTION OF THE BUSINESS
(All amounts in this Report on
Form 10-K
are expressed in thousands of U.S. dollars (except per
share data), unless otherwise noted).
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 Company’s
principal business activities are in the Green River Basin of
southwest Wyoming.
| 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 through the date of the sale of the China operations. The
Company presents its financial statements in accordance with
U.S. Generally Accepted Accounting Principles
(“GAAP”). All inter-company transactions and balances
have been eliminated upon consolidation.
(b) Cash and cash equivalents: We
consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents.
(c) 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.
(d) Capital assets: Capital assets are
recorded at cost and depreciated using the declining-balance
method based on a seven-year useful life.
(e) 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.
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. 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 until proved reserves
are found or until it is determined that the costs are 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).
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 utilizing prices in effect on the last day of the quarter.
SEC
regulation S-X
Rule 4-10 states
that if prices in
51
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
effect at the end of a quarter are the result of a temporary
decline and prices improve prior to the issuance of the
financial statements, the increased price may be applied in the
computation of the ceiling test. 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.
(f) Inventories: Materials and supplies
inventories are carried at cost. Inventory costs include
expenditures and other charges directly and indirectly incurred
in bringing the inventory to its existing condition and
location. 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. At December 31, 2008,
drilling and completion supplies inventory of $8.5 million
primarily includes the cost of pipe and production equipment
that will be utilized during the 2009 drilling program.
(g) Forward natural gas sales
transactions: The Company primarily relies on
fixed price physical delivery contracts, which are considered
sales in the normal course of business, to manage its commodity
price exposure. 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 does not offset
the value of its derivative arrangements with the same
counterparty. (See Note 7).
(h) 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. Valuation
allowances are recorded related to deferred tax assets based on
the “more likely than not” criteria of
SFAS No. 109.
Effective January 1, 2007, we adopted Financial Accounting
Standards Board (“FASB”) Interpretation No. 48
(“FIN 48”) which requires that we recognize the
financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely
than not sustain the position following an audit.
(i) 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.
52
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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, 2008, 2007 and 2006:
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Income from continuing operations
|
$ | 413,860 | $ | 180,242 | $ | 196,702 | ||||||
|
Income from discontinued operations
|
415 | 82,794 | 34,493 | |||||||||
|
Net Income
|
$ | 414,275 | $ | 263,036 | $ | 231,195 | ||||||
|
Weighted average common shares outstanding during the period
|
152,075 | 151,762 | 153,879 | |||||||||
|
Effect of dilutive instruments
|
4,456 | 6,854 | 7,736 | |||||||||
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
156,531 | 158,616 | 161,615 | |||||||||
|
Basic Earnings per Share:
|
||||||||||||
|
Income per common share from continuing operations
|
$ | 2.72 | $ | 1.19 | $ | 1.28 | ||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.54 | $ | 0.22 | ||||||
|
Net income per common share
|
$ | 2.72 | $ | 1.73 | $ | 1.50 | ||||||
|
Fully Diluted Earnings per Share:
|
||||||||||||
|
Income per common share from continuing operations
|
$ | 2.65 | $ | 1.14 | $ | 1.22 | ||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.52 | $ | 0.21 | ||||||
|
Net income per common share
|
$ | 2.65 | $ | 1.66 | $ | 1.43 | ||||||
|
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
|
418 | 674 | 240 | |||||||||
(j) 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.
(k) Accounting for share-based
compensation: The Company follows 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.
(l) Fair Value Accounting. In September
2006, the FASB issued SFAS No. 157, “Fair Value
Measurements” (“SFAS No. 157”). This
Statement defines fair value, establishes a framework for
measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurements. This Statement applies under other accounting
pronouncements that require or permit fair value measurements.
Accordingly, this statement does not require any new fair value
measurements. The changes to current practice resulting from the
application of this statement relate to the definition of fair
value, the methods used to measure fair value, and the expanded
disclosures about fair value measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair
53
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ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
value on a recurring basis, primarily our commodity derivatives,
with no material impact on consolidated results of operations,
financial position or liquidity. For those non-financial assets
and liabilities measured or disclosed at fair value on a
non-recurring basis, SFAS No. 157 is effective
January 1, 2009. Implementation of this portion of the
standard is not expected to have a material impact on
consolidated results of operations, financial position or
liquidity. See Note 13 for additional information.
(m) Revenue Recognition. Natural gas
revenues are recorded on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Company’s 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 Company’s 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, 2008 the Company had a net natural gas
imbalance liability of $0.3 million and at
December 31, 2007, the Company had a net natural gas
imbalance asset of $3.1 million.
(n) Accumulated Other Comprehensive
Income: Other comprehensive income 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.
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Net income
|
$ | 414,275 | $ | 263,036 | $ | 231,195 | ||||||
|
Unrealized gain on derivative instruments*
|
16,368 | 7,633 | — | |||||||||
|
Taxes on unrealized gain on derivative instruments*
|
(5,745 | ) | (2,679 | ) | — | |||||||
|
Other comprehensive income
|
$ | 424,898 | $ | 267,990 | $ | 231,195 | ||||||
| * | Effective November 3, 2008, the Company changed its method of accounting for natural gas commodity derivatives to reflect unrealized gains and losses on commodity derivative contracts in the income statement rather than on the balance sheet (See Note 7). The net gain or loss in accumulated other comprehensive income at November 3, 2008 will remain on the balance sheet and the respective month’s gains or losses will continue to be reclassified from accumulated other comprehensive income to earnings as the counterparty settlements affect earnings (January through December 2009). It is still considered probable that the original forecasted transactions will occur; therefore, the net gain or loss in accumulated other comprehensive income shall not be immediately reclassified into earnings. As a result of the de-designation on November 3, 2008, the company no longer has any derivative instruments which qualify for cash flow hedge accounting. |
At December 31, 2008, the Company recorded a current asset
of $39.9 million and a current liability of
$1.7 million associated with the fair value of derivative
instruments.
(o) Reclassifications: Certain amounts in
the financial statements of the prior periods have been
reclassified to conform to the current period financial
statement presentation.
During the fourth quarter of 2008, the Company reclassified
amounts on the consolidated balance sheets associated with its
share repurchases (See Note 8) in order to
appropriately reflect the treatment of open-market share
repurchases, employee net share settlements, treasury stock
re-issuances and retirements in the financial statements.
(p) Financial Statement Restatement. On
October 31, 2008, in connection with the preparation of our
quarterly report for the third quarter 2008, management
determined that the contemporaneous formal
54
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
documentation we had prepared in the first quarter of 2008 to
support our initial natural gas hedge designations for
production sold on the Rockies Express Pipeline
(“REX”) did not meet the technical requirements to
qualify for hedge accounting treatment in accordance with
Statement of Financial Accounting Standards No. 133,
“Accounting for Derivative Instruments and Hedging
Activities” (“SFAS No. 133”). In order
to cause the hedge contracts to qualify for hedge accounting
treatment under SFAS No. 133, the Company was required
to predict and document the future relationship between prices
at REX sales points and the sales prices at the Northwest
Pipeline Rockies (the basis of the contracts) at the time the
derivative contracts were entered into. The actual relationship
between the sales prices at the two locations was different than
that predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133.
The Company restated the Consolidated Financial Statements for
the periods ended March 31, 2008 and June 30, 2008 to
reflect the inability to qualify for hedge accounting treatment
on the REX designated derivative contracts. The effect of the
restatement was to recognize a non-cash, after tax, mark to
market unrealized loss on commodity derivatives of
$18.0 million in the first quarter of 2008 and a non-cash,
after tax, mark to market unrealized gain on commodity
derivatives of $1.6 million in the second quarter of 2008.
There was no effect in any period on overall cash flows, total
assets, total liabilities or total stockholders’ equity.
Because these contracts were entered into and expire in fiscal
year 2008, there is no change in full-year 2008 net income
or operating cash flows as a result of the accounting treatment
of the derivative contracts, as restated. The restatement did
not have any impact on any of the financial covenants under the
Company’s Senior Credit Facility or Senior Notes due 2015
and 2018.
(q) Impact of recently issued accounting
pronouncements: On December 31, 2008, the
SEC published a final rule to revise its oil and gas reserves
estimation and disclosure requirements. The primary objectives
of the revisions are to increase the transparency and
information value of reserve disclosures and improve
comparability among oil and gas companies. The rule is effective
for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009. The
Company anticipates that the implementation of the new rule will
provide a more meaningful and comprehensive understanding of oil
and gas reserves. The Company does not anticipate that the
implementation of the new reporting requirements will have a
material impact on the consolidated results of operations,
financial position or liquidity.
In March 2008, the FASB issued SFAS No. 161,
“Disclosures about Derivative Instruments and Hedging
Activities” (“SFAS No. 161”). This
statement is intended to improve financial reporting about
derivative instruments and hedging activities by requiring
enhanced disclosures to increase transparency about the location
and amounts of derivative instruments in an entity’s
financial statements; how derivative instruments and related
hedged items are accounted for under SFAS No. 133; and
how derivative instruments and related hedged items affect
financial position, financial performance, and cash flows.
SFAS No. 161 is effective as of the beginning of an
entity’s first fiscal year that begins after
November 15, 2008. The Company does not anticipate that the
implementation of SFAS No. 161 will have a material
impact on the consolidated results of operations, financial
position or liquidity.
In February 2008, the FASB issued FASB Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157 (“FSP
SFAS 157-2”).
FSP
SFAS 157-2
delays the effective date of SFAS 157 to fiscal years
beginning after November 15, 2008 for all non-financial
assets and non-financial liabilities, such as the asset
retirement obligation, except those that are recognized or
disclosed at fair value in the financial statements on a
recurring basis (at least annually). FSP
SFAS 157-2
is effective for the Company’s fiscal year beginning
January 1, 2009. The adoption of FSP
FAS 157-2
is not expected to have a material impact on the Company’s
consolidated financial statements.
| 2. | ASSET RETIREMENT OBLIGATIONS: |
The Company is required 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, 2008 and 2007,
the
55
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Company recorded a liability of $14.1 million and
$8.3 million, respectively, to account for future
obligations associated with its assets.
The following table summarizes the activities for the
Company’s asset retirement obligations for the year ended:
|
December 31, |
December 31, |
|||||||
| 2008 | 2007 | |||||||
|
Asset retirement obligations at beginning of period
|
$ | 8,298 | $ | 6,131 | ||||
|
Accretion expense
|
686 | 493 | ||||||
|
Liabilities incurred
|
3,140 | 2,674 | ||||||
|
Liabilities settled
|
(220 | ) | (66 | ) | ||||
|
Revisions of estimated liabilities
|
2,175 | (934 | ) | |||||
|
Asset retirement obligations at end of period
|
14,079 | 8,298 | ||||||
|
Less: current asset retirement obligations
|
— | — | ||||||
|
Long-term asset retirement obligations
|
$ | 14,079 | $ | 8,298 | ||||
| 3. | OIL AND GAS PROPERTIES: |
|
December 31, |
December 31, |
|||||||
| 2008 | 2007 | |||||||
|
Developed Properties:
|
||||||||
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
$ | 2,809,082 | $ | 1,868,564 | ||||
|
Less accumulated depletion, depreciation and amortization
|
(514,100 | ) | (330,813 | ) | ||||
| 2,294,982 | 1,537,751 | |||||||
|
Unproven Properties:
|
||||||||
|
Acquisition and exploration costs
|
55,544 | 36,778 | ||||||
| $ | 2,350,526 | $ | 1,574,529 | |||||
The Company holds interests in projects in which leasehold costs
and seismic costs related to these interests of
$55.5 million ($15.2 million in Wyoming and
$40.3 million in Pennsylvania) are not being depleted
pending determination of existence of estimated proved reserves.
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.
On a unit basis, DD&A from continuing operations was $1.27
per Mcfe for the year ended December 31, 2008 and $1.18 per
Mcfe for the same period in 2007.
| Total | 2008 | 2007 | 2006 | Prior | ||||||||||||||||
|
United States:
|
||||||||||||||||||||
|
Acquisition costs
|
$ | 54,459 | $ | 17,650 | $ | 5,423 | $ | 12,780 | $ | 18,606 | ||||||||||
|
Exploration costs
|
13,261 | 2,284 | 3,348 | 151 | 7,478 | |||||||||||||||
|
Less transfers to proved
|
(12,176 | ) | (1,168 | ) | (991 | ) | (1,580 | ) | (8,437 | ) | ||||||||||
|
Total
|
$ | 55,544 | $ | 18,766 | $ | 7,780 | $ | 11,351 | $ | 17,647 | ||||||||||
56
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 4. | CAPITAL ASSETS: |
|
December 31, |
||||||||||||||||
|
December 31, |
2008 |
December 31, |
December 31, |
|||||||||||||
|
2008 |
Accumulated |
2008 |
2007 |
|||||||||||||
| Cost | Depreciation | Net Book Value | Net Book Value | |||||||||||||
|
Computer equipment
|
$ | 1,475 | $ | (738 | ) | $ | 737 | $ | 508 | |||||||
|
Office equipment
|
384 | (245 | ) | 139 | 163 | |||||||||||
|
Leasehold improvements
|
380 | (232 | ) | 148 | 210 | |||||||||||
|
Land
|
2,437 | — | 2,437 | 2,437 | ||||||||||||
|
Other
|
4,171 | (1,862 | ) | 2,309 | 1,421 | |||||||||||
| $ | 8,847 | $ | (3,077 | ) | $ | 5,770 | $ | 4,739 | ||||||||
| 5. | LONG TERM LIABILITIES: |
|
December 31, |
December 31, |
|||||||
| 2008 | 2007 | |||||||
|
Bank indebtedness
|
$ | 270,000 | $ | 290,000 | ||||
|
Senior notes
|
300,000 | — | ||||||
|
Other long-term obligations
|
46,206 | 26,672 | ||||||
| $ | 616,206 | $ | 316,672 | |||||
Bank indebtedness: The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (87.5 basis points
per annum as of December 31, 2008).
At December 31, 2008, we had $270.0 million in
outstanding borrowings and $230.0 million of available
borrowing capacity under our credit facility.
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At December 31, 2008, we were in compliance with
all of our debt covenants under our credit facility. The
Company’s commitment fees were $0.7 million,
$0.4 million and $0.4 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes
(“the Notes”) pursuant to a Master Note Purchase
Agreement between the Company and the purchasers of the Notes.
The Notes rank pari passu with the Company’s bank credit
facility. Payment of the Notes is guaranteed by Ultra Petroleum
Corp. and UP Energy Corporation. Of the Notes,
$200.0 million are 5.92% Senior Notes due 2018 and
$100.0 million are 5.45% Senior Notes due 2015.
57
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Proceeds from the sale of the Notes were used to repay bank
debt, but did not reduce the borrowings available to us under
the revolving credit facility.
The Notes are pre-payable in whole or in part at any time. The
Notes are subject to representations, warranties, covenants and
events of default customary for a senior note financing. If
payment default occurs, any Note holder may accelerate its
Notes; if a non-payment default occurs, holders of 51% of the
outstanding principal amount of the Notes may accelerate all the
Notes. At December 31, 2008, we were in compliance with all
of our debt covenants under the Notes.
Other long-term obligations: These costs
relate to the long-term portion of production taxes payable, our
asset retirement obligations mentioned in Note 2 and the
long-term portion of the Company’s incentive compensation
plans.
| 6. | SHARE BASED COMPENSATION: |
The Company sponsors three share based compensation plans: the
2005 Stock Incentive Plan (the “2005 Plan”); the 2000
Stock Incentive Plan (the “2000 Plan”); and the 1998
Stock Option Plan (the “1998 Plan”). Each of the plans
is administered by the Compensation Committee of the Board of
Directors (the “Committee”). The share based
compensation plans are an important component of the total
compensation package offered to the Company’s key service
providers, and they reflect the importance that the Company
places on motivating and rewarding superior results.
The 2005 Plan was adopted by the Company’s Board of
Directors on January 1, 2005 and approved by the
Company’s shareholders on April 29, 2005. The purpose
of the 2005 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 outside directors, and providing such
participants with a program for obtaining an ownership interest
in the Company that links and aligns their personal interests
with those of the Company’s shareholders, and thus,
enabling such participants to share in the long-term growth and
success of the Company. To accomplish these goals, the 2005 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. Under the 2005 Plan, the aggregate
number of common shares issuable to any one person pursuant to
an award cannot exceed 5% of the number of common shares
outstanding at the time of the award. In addition, no
participant may receive during any calendar year, awards
covering an aggregate of more than 2.0 million common
shares, or a cash payout with respect to any awards in excess of
$5.0 million. The Committee determines the terms and
conditions of the awards, including, any vesting requirements
and vesting restrictions or forfeitures that may occur. The
Committee may grant awards under the 2005 Plan until
December 31, 2014, unless terminated sooner by the Board of
Directors.
The 2000 Plan was adopted by the Company’s Board of
Directors on May 1, 2000 and approved by the Company’s
shareholders on June 6, 2000. The 2000 Plan was established
for the purposes of associating the interests of the management
of the Company and its subsidiaries and affiliates closely with
the Company’s shareholders to generate an increased
incentive to contribute to the Company’s future success and
prosperity; maintaining competitive compensation levels thereby
attracting and retaining highly competent and talented outside
directors, employees, and consultants; and providing an
incentive to such management for continuous employment with the
Company. The 2000 Plan operates in a very similar manner to the
2005 Plan and permits the granting of incentive stock options,
non-statutory stock options, stock appreciation rights, and
restricted stock. Under the 2000 Plan, the aggregate number of
common shares issuable to any one person pursuant to such award
cannot 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 Company, awards covering an
aggregate of more than 500,000 common shares. The Committee
determines the terms and conditions of the awards, including,
any vesting requirements and vesting restrictions or forfeitures
that may occur. The Committee may continue to grant awards under
the 2000 Plan until April 30, 2010, unless terminated
sooner by the Board of Directors.
58
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The 1998 Plan was adopted by the Company’s Board of
Directors on October 28, 1998 and approved by the
Company’s shareholders on December 3, 1998. Similar to
the 2000 Plan and 2005 Plan, the 1998 Plan was established as a
means to attract, retain, and motivate service providers of the
Company by providing them with an opportunity to acquire an
increased proprietary interest in the Company through the
granting of stock options. The 1998 Plan permits the granting of
non-statutory stock options. Under the 1998 Plan, the aggregate
number of common shares issuable to any one person pursuant to
an award under the 1998 Plan, together with all other
outstanding stock options granted to such person, cannot exceed
5% of the number of common shares outstanding. The Committee
determines the terms and conditions of the awards, including,
any vesting requirements and vesting restrictions or forfeitures
that may occur. The 1998 Plan remains effective and the Company
may continue to make stock option grants under the plan.
Valuation
and Expense Information under SFAS 123R
The following table summarizes share-based compensation costs:
|
Year-Ended |
Year-Ended |
Year-Ended |
||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Total cost of share-based payment plans
|
$ | 10,355 | $ | 9,581 | $ | 4,742 | ||||||
|
Amounts capitalized in fixed assets
|
$ | 4,539 | $ | 3,863 | $ | 2,116 | ||||||
|
Amounts charged against income, before income tax benefit
|
$ | 5,816 | $ | 5,718 | $ | 2,626 | ||||||
|
Amount of related income tax benefit recognized in income
|
$ | 2,041 | $ | 2,007 | $ | 922 | ||||||
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 Company’s
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 Company’s 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.
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Non-Executives | Executives | Non-Executives | Executives | Non-Executives | Executives | |||||||||||||||||||
|
Expected volatility
|
41.2-47.6 | % | 42.5-43.3 | % | 41.3-45.8 | % | 43.5-47.4 | % | 43.7-45.8 | % | 43.5-47.4 | % | ||||||||||||
|
Expected dividends
|
0 | % | 0 | % | 0 | % | 0 | % | 0 | % | 0 | % | ||||||||||||
|
Expected term (in years)
|
5.01-5.15 | 5.98-6.45 | 2.75-5.02 | 3.58-5.55 | 2.75-4.71 | 3.58-5.55 | ||||||||||||||||||
|
Risk free rate
|
2.48-3.41 | % | 2.98-3.00 | % | 4.16-5.07 | % | 4.69-4.84 | % | 4.51-5.03 | % | 4.76-4.84 | % | ||||||||||||
|
Expected forfeiture rate
|
14.0 | % | 14.0 | % | 18.0 | % | 18.0 | % | 20.0 | % | 20.0 | % | ||||||||||||
59
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Securities
Authorized for Issuance Under Equity Compensation
Plans
As of December 31, 2008, the Company had the following
securities issuable pursuant to outstanding award agreements or
reserved for issuance under the Company’s previously
approved stock incentive plans. Upon exercise, shares issued
will be newly issued shares or shares issued from treasury.
|
Number of Securities |
||||||||||||
|
Number of |
Remaining Available for |
|||||||||||
|
Securities to |
Weighted- |
Future Issuance Under |
||||||||||
|
be Issued |
Average |
Equity Compensation |
||||||||||
|
Upon Exercise 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
|
4,213 | $ | 24.04 | 10,004 | ||||||||
|
Equity compensation plans not approved by security holders
|
n/a | n/a | n/a | |||||||||
|
Total
|
4,213 | $ | 24.04 | 10,004 | ||||||||
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, 2008:
|
Number of |
Weighted Average |
|||||||
| Options | Exercise Price (US$) | |||||||
|
Balance, December 31, 2005
|
9,389 | $ | 0.25 to $58.71 | |||||
|
Granted
|
380 | $ | 46.05 to $67.73 | |||||
|
Exercised
|
(656 | ) | $ | 0.46 to $40.00 | ||||
|
Forfeited
|
(30 | ) | $ | 16.97 to $63.05 | ||||
|
Balance, December 31, 2006
|
9,083 | $ | 0.25 to $67.73 | |||||
|
Granted
|
436 | $ | 45.95 to $65.94 | |||||
|
Exercised
|
(1,849 | ) | $ | 0.25 to $67.73 | ||||
|
Forfeited
|
(81 | ) | $ | 47.19 to $63.05 | ||||
|
Balance, December 31, 2007
|
7,589 | $ | 0.25 to $67.73 | |||||
|
Granted
|
299 | $ | 51.14 to $98.87 | |||||
|
Exercised
|
(3,595 | ) | $ | 0.25 to $67.73 | ||||
|
Forfeited
|
(80 | ) | $ | 51.60 to $85.05 | ||||
|
Balance, December 31, 2008
|
4,213 | $ | 0.25 to $98.87 | |||||
60
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following tables summarize information about the stock
options outstanding at December 31, 2008:
| Options Outstanding | ||||||||||||||||
|
Weighted |
||||||||||||||||
|
Average |
Weighted |
|||||||||||||||
|
Number |
Remaining |
Average |
Aggregate |
|||||||||||||
|
Range of Exercise Price
|
Outstanding | Contractual Life | Exercise Price | Intrinsic Value | ||||||||||||
|
$0.25 — 2.61
|
1,082 | 1.71 | $ | 0.98 | $ | 36,279 | ||||||||||
|
$3.91 — 4.83
|
672 | 3.86 | $ | 4.63 | $ | 20,078 | ||||||||||
|
$11.68 — 19.18
|
639 | 5.21 | $ | 13.71 | $ | 13,291 | ||||||||||
|
$25.08 — 58.71
|
899 | 6.52 | $ | 36.98 | $ | 2,283 | ||||||||||
|
$46.05 — 65.04
|
240 | 7.48 | $ | 57.88 | $ | — | ||||||||||
|
$45.95 — 65.94
|
421 | 8.28 | $ | 53.97 | $ | — | ||||||||||
|
$51.14 — 98.87
|
260 | 9.40 | $ | 71.15 | $ | — | ||||||||||
| Options Exercisable | ||||||||||||||||
|
Weighted |
||||||||||||||||
|
Average |
Weighted |
|||||||||||||||
|
Number |
Remaining |
Average |
Aggregate |
|||||||||||||
|
Range of Exercise Price
|
Exercisable | Contractual Life | Exercise Price | Intrinsic Value | ||||||||||||
|
$0.25 — 2.61
|
1,082 | 1.71 | $ | 0.98 | $ | 36,279 | ||||||||||
|
$3.91 — 4.83
|
672 | 3.86 | $ | 4.63 | $ | 20,078 | ||||||||||
|
$11.68 — 19.18
|
639 | 5.21 | $ | 13.71 | $ | 13,291 | ||||||||||
|
$25.08 — 58.71
|
899 | 6.52 | $ | 36.98 | $ | 2,283 | ||||||||||
|
$46.05 — 65.04
|
85 | 7.25 | $ | 62.42 | $ | — | ||||||||||
|
$45.95 — 65.94
|
— | — | $ | — | $ | — | ||||||||||
|
$51.14 — 98.87
|
— | — | $ | — | $ | — | ||||||||||
The aggregate intrinsic value in the preceding tables represents
the total pre-tax intrinsic value, based on the Company’s
closing stock price of $34.51 on December 31, 2008, 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, 2008 was 2.9 million options.
The following table summarizes information about the
weighted-average grant-date fair value of share options:
| 2008 | 2007 | 2006 | ||||||||||
|
Share options granted
|
$ | 30.94 | $ | 23.85 | $ | 23.65 | ||||||
|
Non-vested share options at beginning of year
|
$ | 23.93 | $ | 23.65 | $ | — | ||||||
|
Non-vested share options at end of year
|
$ | 26.18 | $ | 23.93 | $ | 23.65 | ||||||
|
Options vested during the year
|
$ | — | $ | 22.79 | $ | — | ||||||
|
Options forfeited during the year
|
$ | 27.35 | $ | 22.25 | $ | 21.64 | ||||||
There were no stock options that vested during the years ended
December 31, 2008 or 2006. The fair value of stock options
that vested during the year ended December 31, 2007 was
$2.8 million. The total intrinsic value of stock options
exercised during the years ended December 31, 2008, 2007
and 2006 was $224.6 million, $104.5 million and
$28.7 million, respectively.
At December 31, 2008, there was $10.1 million of total
unrecognized compensation cost related to non-vested, employee
stock options granted under the Stock Incentive Plans. That cost
is expected to be recognized over a weighted average period of
1.6 years.
61
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
PERFORMANCE
SHARE PLANS:
Long-Term
Incentive Plan
Each year, beginning in 2005, the Company has adopted a Long
Term Incentive Plan (“LTIP”) in order to further align
the interests of key employees with shareholders and to give key
employees the opportunity to share in the long-term performance
of the Company when achieving specific corporate financial and
operational goals. Each LTIP covers a period of three years. For
example, the “2005 LTIP” covers the period between
January 2005 — December 2007, and the “2006
LTIP” covers the period between January 2006 —
December 2008. Thus far, the Company has adopted the 2005 LTIP,
2006 LTIP, 2007 LTIP, and the 2008 LTIP. The Company expects to
adopt an LTIP in 2009.
Officers, managers, and other key employees of the Company who
are recommended by the CEO and approved by the Committee are
eligible to participate in the LTIPs. Each LTIP has two
components: an “LTIP Stock Option Award” and an
“LTIP Common Stock Award.” Under each LTIP, the
Committee establishes a percentage of base salary for each
participant which is multiplied by the participant’s base
salary to derive a Long Term Incentive Value (“LTI
Value”). With respect to the LTIP Stock Option Award
portion of the LTIP, participants are awarded options to
purchase shares of common stock of the Company in an amount
equal to one half of the LTI Value based on the fair market
value of the optioned shares on the date of grant (using
Black-Scholes methodology). The options vest and become
exercisable equally over a period of three years. The options
are not performance based.
The LTIP Common Stock Award is based on the other half of the
LTI Value, which is the “target” value amount that may
be awarded to the participant in the form of shares of the
Company’s common stock at the end of the three year
performance period if the performance measures are met. The LTIP
Common Stock Award is performance based and is measured over a
three year performance period. For each LTIP Common Stock Award,
the Committee establishes performance measures at the beginning
of each performance period, and each participant is assigned
threshold and maximum award levels in the event that actual
performance is below or above target levels. For the 2006, 2007,
and the 2008 LTIP Common Stock Awards, the Committee used the
following performance measures: return on equity, reserve
replacement ratio, and production growth.
The value of the award for the 2006 and 2007 LTIP Common Stock
Awards are expressed as dollar targets and become payable in
common shares equal to a percentage of the dollar target at the
end of each performance period based on the Company’s
overall performance during such period. During the third quarter
of 2008, the Board of Directors modified the 2008 LTIP Common
Stock Award such that the dollar target is converted to a target
number of shares on the date the Board approved the
modification. Thus, with respect to the 2008 LTIP Common Stock
Award, the participants are able to participate in the movement
of the Company’s stock price during the performance period,
similar to the “Best in Class Program” (described
below). Participants must be employed by the Company when the
common stock payment for the LTIP Common Stock Award is
distributed in order to receive the award. If the participant is
not employed on the distribution date, then
he/she will
not receive the award.
For the year ended December 31, 2008, the Company
recognized $1.2 million, $1.3 million, and
$1.1 million in pre-tax compensation costs related to the
2006, 2007, and 2008 LTIP Common Stock Awards, respectively. For
the year ended December 31, 2007, the Company recognized
$0.9 million, $0.8 million, and $1.0 million in
pre-tax compensation costs related to the 2005, 2006, and 2007
LTIP Common Stock Awards, respectively. For the year ended
December 31, 2006, the Company recognized $0.7 million
and $0.7 million in pre-tax compensation costs related to
the 2005 and 2006 LTIP Common Stock Awards, respectively. The
amounts recognized during the each of the years ended
December 31, 2008, 2007, and 2006 assume that maximum
performance objectives are attained. If the Company ultimately
attains maximum performance objectives, the associated total
compensation cost, estimated at December 31, 2008, for the
three year performance periods is expected to be approximately
$2.7 million, $3.6 million, and $3.4 million
(before taxes) related to the 2006, 2007, and 2008 LTIP Common
Stock Awards, respectively. The 2005 LTIP Common Stock Award was
paid in shares of the Company’s stock to employees during
the first quarter of 2008 and totaled $2.3 million.
62
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Best in
Class Program
In 2005 and in 2008, the Company established the “Best in
Class Program” for all permanent full time employees.
Under the Best in Class Programs, participants are eligible
to receive a number of shares of the Company’s common stock
based on the performance of the Company. As with the LTIP, the
Best in Class Program is measured over a three year
performance period. The performance period related to the 2005
Best in Class Program ended on December 31, 2007, with
the resulting payout in the second quarter of 2008.
The Best in Class Program recognizes and financially
rewards the collective efforts of all of the Company’s
employees in achieving sustained industry leading performance
and the enhancement of shareholder value. Under the 2008 Best in
Class Program, on January 1, 2008 or the employment
date if subsequent to January 1, 2008, eligible employees
received a contingent award of stock units equal to $60,000
worth of the Company’s common stock based on the average
high and low share price on the first day of the performance
period. Employees joining the Company after January 1, 2008
participate on a pro-rata basis based on their length of
employment during the performance period.
The number of contingent units that will vest and become payable
is based on the Company’s performance relative to the
industry during a three year performance period beginning
January 1, 2008, and ending December 31, 2010, 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 participant must be employed on the
date the awards are distributed in order to receive the award.
For example, at a conversion price of $71.60 per share (price
per share on the first day of the performance period), the
$60,000 award is equal to 838 contingent units. At the end of
the performance period, if the “maximum” level for all
performance measures is met and the participant was employed
from the beginning of the performance period, then 1,257 (150%
of 838) units will vest. If the participant is employed on
the date the award is distributed, the participant will receive
1,257 shares of the Company’s common stock on such
date. If the participant is not employed on the distribution
date, then
he/she will
not receive the award.
For the year ended December 31, 2008, the Company
recognized $1.2 million in pre-tax compensation costs
related to the 2008 Best in Class Program. For the years
ended December 31, 2007 and 2006, the Company recognized
$1.7 million and $0.5 million in pre-tax compensation
costs related to the 2005 Best in Class Program. The amount
recognized for the year ended December 31, 2008 assumes
that “target” performance levels are achieved. If the
Company ultimately attains the target performance level, the
associated total compensation cost related to the 2008 Best in
Class Program is estimated at $3.6 million before
income taxes. The 2005 Best in Class Program was paid in
shares of the Company’s common stock to employees in May
2008 and totaled $4.0 million.
| 7. | DERIVATIVE FINANCIAL INSTRUMENTS: |
The Company’s 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 Company’s Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable, ranging from $4.24 per Mcf to a
monthly high of $8.81 per Mcf during 2008. Pricing volatility is
expected to continue. Realized natural gas prices are derived
from the financial statements which include the effects of
realized hedging gains and losses 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, from time to time, also uses derivative instruments 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 natural gas
production. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas
index prices as reported by such publications as Inside FERC Gas
Market Report.
63
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivative’s fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. 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 Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
Based on management’s current estimates, future production
is expected to be sufficient to meet delivery requirements
associated with the Company’s derivative contracts and
fixed price forward physical delivery contracts.
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Company and the Audit Committee of the Board of Directors
determined that the contemporaneous formal documentation we had
prepared in the first quarter of 2008 to support our initial
natural gas hedge designations for production sold on REX did
not meet the technical requirements to qualify for hedge
accounting treatment in accordance with SFAS No. 133.
In order to cause the hedge contracts to qualify for hedge
accounting treatment under SFAS No. 133, the Company
was required to predict and document the future relationship
between prices at REX sales points and the sales prices at the
Northwest Pipeline Rockies (the basis of the contracts) at the
time the hedge contracts were entered into. The actual
relationship between the sales prices at the two locations was
different than that predicted by the Company, which affected our
ability to effectively demonstrate ongoing effectiveness between
the derivative instrument and the forecasted transaction as
outlined in our contemporaneous documentation as set forth under
the requirements of SFAS No. 133. While such
derivatives no longer qualify for hedge accounting treatment,
the Company believes that these contracts remain a valuable
component of our commodity price risk management program.
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The
Company has historically followed hedge accounting for its
natural gas hedges. Under this accounting method, the unrealized
gain or loss on qualifying cash flow hedges (calculated on a
mark to market basis, net of tax) was recorded on the balance
sheet in stockholders’ equity as accumulated other
comprehensive income. When an unrealized hedging gain or loss
was realized upon contract expiration, it was reclassified into
earnings through inclusion in natural gas sales revenues. The
Company continues to record the fair value of its commodity
derivatives as an asset or liability on the Consolidated Balance
Sheets, but records the changes in the fair value of its
commodity derivatives in the Consolidated Statements of Income
as an unrealized gain or loss on commodity derivatives. There is
no resulting effect on overall cash flow, total assets, total
liabilities or total stockholders’ equity, and there is no
impact on any of the financial covenants under the
Company’s Senior Credit Facility or Senior Notes due 2015
and 2018.
The Company also utilizes fixed price forward physical delivery
contracts at southwest Wyoming delivery points to mitigate its
commodity price exposure. 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, 2008. (In
November 2007, the Minerals Management Service commenced a
Royalty-in-Kind program which had the effect of increasing the
Company’s average net interest in physical gas sales from
80% to approximately 91%.)
|
Volume- |
Average |
|||||||
|
Remaining Contract Period
|
MMBTU/Day | Price/MMBTU | ||||||
|
Summer 2009 (April — October)
|
130,000 | $ | 6.15 | |||||
|
Calendar 2009
|
60,000 | $ | 5.04 | |||||
|
Calendar 2010
|
20,000 | $ | 5.17 | |||||
64
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2008, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price.
|
Volume- |
Average |
|||||||||||||
|
Type
|
Point of Sale
|
Remaining Contract Period | MMBTU/Day | Price/MMBTU | ||||||||||
|
Swap
|
NWPL — Rockies | Jan 2009 — Dec 2009 | 40,000 | $ | 6.57 | |||||||||
|
Swap
|
Mid-Continent | Apr 2009 — Oct 2009 | 110,000 | $ | 4.99 | |||||||||
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Income for the years ended December 31, 2008,
2007 and 2006 (refer to Note 1(n) for details of unrealized
gains or losses included in accumulated other comprehensive
income in the Consolidated Balance Sheets):
|
For the Year |
||||||||||||
| Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Realized gain (loss) on derivatives designated as cash flow
hedges(1)
|
$ | 1,148 | $ | 1,107 | $ | — | ||||||
|
Realized gain (loss) on commodity derivatives(2)
|
$ | 18,991 | $ | — | $ | — | ||||||
|
Unrealized gain (loss) on commodity derivatives(3)
|
$ | 14,225 | $ | — | $ | — | ||||||
| (1) | Included in natural gas sales in the income statement. (Related tax expense of $403 and $389, respectively). | |
| (2) | Included in gain on commodity derivatives in the income statement. (Related tax expense of $6,666). | |
| (3) | Included in gain on commodity derivatives in the income statement. (Related tax expense of $4,993). |
Subsequent to December 31, 2008 and through
February 13, 2009, the Company has entered into the
following fixed price physical delivery contracts on behalf of
its interest and those of other parties:
|
Volume- |
Average |
|||||||
|
Remaining Contract Period
|
MMBTU/Day | Price/MMBTU | ||||||
|
Calendar 2010
|
30,000 | $ | 4.87 | |||||
Subsequent to December 31, 2008 and through
February 13, 2009, the Company has entered into the
following open commodity derivative contracts to manage price
risk on a portion of its natural gas production whereby the
Company receives the fixed price and pays the variable price:
|
Volume- |
Average |
|||||||||||||||
|
Type
|
Point of Sale
|
Remaining Contract Period | MMBTU/Day | Price/MMBTU | ||||||||||||
|
Swap
|
Mid-Continent | Apr 2009 — Oct 2009 | 20,000 | $ | 5.02 | |||||||||||
| 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 Company’s outstanding
common stock which has been and will be funded by cash on hand
and the Company’s senior credit facility. Pursuant to this
authorization, the Company has commenced a program to purchase
up to $750.0 million of the Company’s 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.
Subsequent to settlement, the repurchased stock will be
transferred to Ultra Petroleum or held as treasury stock by
Ultra Resources, subject to a limit of 1% of current outstanding
shares.
65
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following tables summarize the Company’s share
repurchases in total (open market repurchases plus net share
settlements) as of December 31, 2008:
|
Shares |
Weighted Average |
|||||||||||
|
Total
|
Purchased | Price per Share | $ Value | |||||||||
|
1st
Quarter — 2008
|
397 | $ | 75.25 | $ | 29,829 | |||||||
|
2nd
Quarter — 2008
|
452 | $ | 85.97 | $ | 38,807 | |||||||
|
3rd
Quarter — 2008
|
3,266 | $ | 66.27 | $ | 216,461 | |||||||
|
4th Quarter —
2008
|
402 | $ | 32.83 | $ | 13,210 | |||||||
|
Prior
|
5,694 | $ | 51.73 | $ | 294,549 | |||||||
|
May 2006 — December 31, 2008
|
10,211 | $ | 58.06 | $ | 592,856 | |||||||
|
Shares |
Weighted Average |
|||||||||||
|
Open Market
|
Purchased | Price per Share | $ Value | |||||||||
|
1st
Quarter — 2008
|
214 | $ | 75.53 | $ | 16,139 | |||||||
|
2nd
Quarter — 2008
|
210 | $ | 84.13 | $ | 17,643 | |||||||
|
3rd
Quarter — 2008
|
3,237 | $ | 65.97 | $ | 213,589 | |||||||
|
4th Quarter —
2008
|
— | $ | — | $ | — | |||||||
|
Prior
|
5,401 | $ | 51.19 | $ | 276,442 | |||||||
|
May 2006 — December 31, 2008
|
9,062 | $ | 57.81 | $ | 523,813 | |||||||
|
Shares |
Weighted Average |
|||||||||||
|
Net Share Settlements
|
Purchased | Price per Share | $ Value | |||||||||
|
1st
Quarter — 2008
|
183 | $ | 74.92 | $ | 13,690 | |||||||
|
2nd
Quarter — 2008
|
242 | $ | 87.57 | $ | 21,164 | |||||||
|
3rd
Quarter — 2008
|
29 | $ | 98.88 | $ | 2,872 | |||||||
|
4th Quarter —
2008
|
402 | $ | 32.83 | $ | 13,210 | |||||||
|
Prior
|
293 | $ | 61.73 | $ | 18,107 | |||||||
|
May 2006 — December 31, 2008
|
1,149 | $ | 60.08 | $ | 69,043 | |||||||
| 9. | INCOME TAXES: |
Income from continuing operations before income taxes is as
follows:
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
United States
|
$ | 654,465 | $ | 286,045 | $ | 320,033 | ||||||
|
Foreign
|
(100 | ) | (182 | ) | (590 | ) | ||||||
|
Total
|
$ | 654,365 | $ | 285,863 | $ | 319,443 | ||||||
66
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The consolidated income tax provision is comprised of the
following:
| Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Current:
|
||||||||||||
|
U.S. federal & state
|
$ | 84,313 | $ | 14,511 | $ | 27,563 | ||||||
|
Foreign
|
— | — | — | |||||||||
|
Deferred:
|
||||||||||||
|
U.S. federal & state
|
156,191 | 91,110 | 95,178 | |||||||||
|
Foreign
|
— | — | — | |||||||||
|
Total income tax provision
|
$ | 240,504 | $ | 105,621 | $ | 122,741 | ||||||
During 2008, 2007 and 2006, the Company realized tax benefits of
$78.8 million $36.7 million, and $10.5 million,
respectively, attributable to tax deductions associated with the
exercise of stock options. These benefits reduce the amount of
the Company’s 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.
The income tax provision for continuing operations 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, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Income tax provision computed at the U.S. statutory rate
|
$ | 229,028 | $ | 100,052 | $ | 111,805 | ||||||
|
State income tax provision net of federal benefit
|
650 | 423 | 150 | |||||||||
|
Withholding tax on share repurchase transactions
|
5,409 | 1,068 | 10,401 | |||||||||
|
Foreign tax credit valuation allowance
|
1,692 | — | — | |||||||||
|
Other, net
|
3,725 | 4,078 | 385 | |||||||||
| $ | 240,504 | $ | 105,621 | $ | 122,741 | |||||||
During 2008, 2007, and 2006, the Company incurred
U.S. withholding taxes totaling $5.4 million,
$1.1 million, and $10.4 million, respectively, in
connection with the repurchase of shares of its common stock.
(See Note 8).
The tax effects of temporary differences that give rise to
significant components of the Company’s deferred tax assets
and liabilities for continuing operations are as follows:
| Year Ended December 31, | ||||||||
| 2008 | 2007 | |||||||
|
Deferred tax assets:
|
||||||||
|
U.S. federal tax credit carryforwards
|
$ | 21,263 | $ | 20,101 | ||||
|
Canadian net operating loss carryforwards
|
497 | 1,808 | ||||||
|
Incentive compensation / Other, net
|
7,866 | 4,517 | ||||||
| 29,626 | 26,426 | |||||||
|
Valuation allowance (FTC)
|
(1,692 | ) | — | |||||
|
Valuation allowance (Canadian NOL)
|
(497 | ) | (1,808 | ) | ||||
|
Net deferred tax assets
|
$ | 27,437 | $ | 24,618 | ||||
|
Deferred tax liabilities:
|
||||||||
|
Property and equipment
|
(517,616 | ) | (363,345 | ) | ||||
|
Other comprehensive income, tax effect of derivative instruments
|
(13,418 | ) | (2,679 | ) | ||||
|
Net deferred tax liabilities
|
$ | (531,034 | ) | $ | (366,024 | ) | ||
|
Net deferred tax asset (liability)
|
$ | (503,597 | ) | $ | (341,406 | ) | ||
67
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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.
The Company did not have any unrecognized tax benefits and there
was no effect on our financial condition or results of
operations as a result of implementing FIN 48. The amount
of unrecognized tax benefits did not materially change as of
December 31, 2008.
It is expected that the amount of unrecognized tax benefits may
change in the next twelve months; however Ultra does not expect
the change to have a significant impact on the results of
operations or the financial position of the Company. The Company
currently has no unrecognized tax benefits that if recognized
would affect the effective tax rate.
The Company files a consolidated federal income tax return in
the United States federal jurisdiction and various combined,
consolidated, unitary, and separate filings in several states,
and Canada. With certain exceptions, the Company is no longer
subject to U.S. federal, state and local, or
non-U.S. income
tax examinations by tax authorities for years before 1999.
Estimated interest and penalties related to potential
underpayment on any unrecognized tax benefits are classified as
a component of tax expense in the Consolidated Statement of
Operations. The Company has not recorded any interest or
penalties associated with unrecognized tax benefits.
The Company does not anticipate that total unrecognized tax
benefits will significantly change due to the settlement of
audits and the expiration of statute of limitations prior to
December 31, 2009.
As of December 31, 2008, the Company had approximately
$19.1 million of U.S. federal alternative minimum tax
(AMT) credits available to offset regular U.S. federal
income taxes. These AMT credits do not expire and can be carried
forward indefinitely. In addition, as of December 31, 2008,
the Company has $2.1 million of foreign tax credit
carryforwards, none of which expire prior to 2017. However, with
the 2007 sale of Sino American Energy, the Company no longer has
foreign source income for which to utilize its foreign tax
credit carryforwards. As such, the Company has chosen to put a
valuation allowance on the remaining foreign tax credit
carryforwards.
The Company has Canadian non-capital tax loss carryforwards of
approximately $2.3 million and $3.5 million as of
December 31, 2008 and December 31, 2007, 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 2009 and 2028.
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, 2008
and December 31, 2007 attributable to this deferred tax
asset.
The undistributed earnings of the Company’s
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.
The Company periodically uses derivative instruments designated
as cash flow hedges for tax purposes 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. To the extent these hedges are
ineffective, they are marked to market with gains and losses
recorded in the statement of operations. At December 31,
2008 and December 31, 2007, the Company had open derivative
contracts; and, therefore, recorded a deferred tax liability of
$8.4 million and $2.7 million, respectively,
attributable to unrecognized gains on derivative instruments
which are allocated directly to Other Comprehensive Income. At
68
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
December 31, 2008, the Company also recorded a deferred tax
liability of $5.0 million attributable to the unrealized
gains recorded in the statement of operations. As of
December 31, 2006, the Company had no open derivative
contracts; and, therefore, no recorded tax benefit attributable
to unrecognized loss on derivative instruments.
| 10. | EMPLOYEE BENEFITS: |
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 expense associated with the Company’s
contribution was $0.9 million, $0.9 million and
$0.7 million for the years ended December 31, 2008,
2007 and 2006, respectively.
| 11. | DISCONTINUED OPERATIONS: |
During the third quarter of 2007, we made the decision to
dispose of
Sino-American
Energy Corporation
(“Sino-American”),
which owned our Bohai Bay assets in China, in order to focus on
our legacy asset in the Pinedale Field in southwest Wyoming. The
reserve volumes sold represent all of Ultra’s international
assets and, previously, were the only results included in our
foreign operating segment.
On September 26, 2007, Ultra Petroleum Corp.’s
wholly-owned subsidiary, UP Energy Corporation, a
Nevada corporation, entered into a definitive share
purchase agreement with an effective date of June 30, 2007
and a closing date of October 22, 2007 in order to sell all
of the outstanding shares of
Sino-American,
a Texas corporation, for a total purchase price of
US$223.0 million, subject to adjustments. The Company
recorded results of operations for the China properties through
the close date of October 22, 2007. The purchaser was SPC
E&P (China) Pte. Ltd., a wholly-owned subsidiary of
Singapore Petroleum Company. For tax purposes, this transaction
was treated as an asset sale as the Company agreed to make a
338(h)(10) election in the stock purchase agreement.
The Company accounted for its
Sino-American
operations as discontinued operations and reclassified prior
period financial statements to exclude these businesses from
continuing operations. A summary of financial information
related to the Company’s discontinued operations is as
follows:
| For the Year Ended December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Operating revenues
|
$ | — | $ | 64,822 | $ | 84,008 | ||||||
|
Gain on sale of subsidiary
|
640 | 98,066 | — | |||||||||
|
Lease operating expenses
|
— | 11,419 | 8,922 | |||||||||
|
Severance taxes
|
— | 8,113 | 8,398 | |||||||||
|
Depletion, depreciation and amortization expenses
|
— | 14,981 | 13,822 | |||||||||
|
General and administrative expenses
|
— | 99 | 52 | |||||||||
|
Income before income tax provision
|
640 | 128,276 | 52,814 | |||||||||
|
Income tax provision
|
225 | 45,482 | 18,321 | |||||||||
|
Income from discontinued operations, net of tax
|
$ | 415 | $ | 82,794 | $ | 34,493 | ||||||
| 12. | COMMITMENTS AND CONTINGENCIES: |
Office space lease. In May 2007, the Company
amended its office leases in Englewood, Colorado and Houston,
Texas, both of which it has committed through 2012. The
Company’s total remaining commitment for office leases is
$2.3 million at December 31, 2008 ($0.8 million
in 2009, $0.7 million in 2010 and 2011, and
$0.1 million in 2012).
69
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
During the years ended December 31, 2008, 2007 and 2006,
the Company recognized expense associated with its office leases
in the amount of $0.7 million, $0.6 million, and
$0.4 million, respectively.
Drilling contracts. As of December 31,
2008, the Company had committed to drilling obligations with
certain rig contractors totaling $203.1 million
($61.7 million due in 2009, $114.7 million due in one
to three years, and the remaining $26.7 million due in
three to five years). The commitments expire in 2012 and were
entered into to fulfill the Company’s
2009-2012
drilling program initiatives in Wyoming.
Transportation contract. In December 2005, the
Company agreed to become an anchor shipper on REX, thereby
securing pipeline infrastructure to provide sufficient capacity
for the Company to transport a portion of its natural gas
production away from southwest Wyoming, as well as to provide
for reasonable basis differentials for the Company’s
natural gas in the future. The Company’s commitment
involves capacity of 200 MMBtu per day of natural gas for a
term of 10 years (beginning in the first quarter of 2008),
and the Company is obligated to pay REX certain demand charges
related to its rights to hold this firm transportation capacity
as an anchor shipper. The pipeline will be completed in two
phases: REX-West (Wyoming to Missouri — in service)
and REX-East (Missouri to Ohio — under construction).
Based on current assumptions, including current projections
regarding the cost of the expansion and the participation of
other shippers in the expansion, the Company currently projects
that demand charges related to the remaining term of the
contract will total approximately $562.1 million.
There have been and will continue to be, numerous other proposed
pipeline projects to transport growing Rockies and Wyoming
natural gas production to a variety of geographically diverse
markets in different parts of North America. Many such proposals
have been presented to the Company in recent months, which, if
constructed, would provide the Company with additional outlets
and market access for its natural gas production from southwest
Wyoming. The Company continuously evaluates such proposals and
may make additional commitments to one or more such pipeline
projects in the future.
Other. 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 MEASUREMENTS: |
On September 15, 2006, the FASB issued
SFAS No. 157, “Fair Value Measurement”. We
adopted SFAS No. 157 effective January 1, 2008.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the measurement date and establishes a three level hierarchy
for measuring fair value. The statement requires fair value
measurements be classified and disclosed in one of the following
categories:
Level 1: Quoted prices
(unadjusted) in active markets for identical assets and
liabilities that we have the ability to access at the
measurement date.
Level 2: Inputs other than quoted
prices included within Level 1 that are either directly or
indirectly observable for the asset or liability, including
quoted prices for similar assets or liabilities in active
markets, quoted prices for identical or similar assets or
liabilities in inactive markets, inputs other than quoted prices
that are observable for the asset or liability, and inputs that
are derived from observable market data by
70
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
correlation or other means. Instruments categorized in
Level 2 include non-exchange traded derivatives such as
over-the-counter forwards and swaps.
Level 3: Unobservable inputs for
the asset or liability, including situations where there is
little, if any, market activity for the asset or liability.
The valuation assumptions utilized to measure the fair value of
the Company’s commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level our assets
and liabilities, including both current and non-current
portions, measured at fair value on a recurring basis, as of
December 31, 2008:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
|
Assets — Current:
|
||||||||||||||||
|
Derivatives
|
$ | — | $ | 39,939 | $ | — | $ | 39,939 | ||||||||
|
Liabilities — Current:
|
||||||||||||||||
|
Derivatives
|
$ | — | $ | 1,712 | $ | — | $ | 1,712 | ||||||||
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
Fair
Market Value of Financial Instruments
The estimated fair value of financial instruments is the amount
at which the instrument could be exchanged currently between
willing parties. The carrying amounts reported in the
consolidated balance sheet for cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value
due to the immediate or short-term maturity of these financial
instruments. We use available marketing data and valuation
methodologies to estimate the fair value of debt. This
disclosure is presented in accordance with SFAS No. 107,
“Disclosures about Fair Value of Financial
Instruments” and does not impact our financial position,
results of operations or cash flows.
| December 31, 2008 | December 31, 2007 | |||||||||||||||
|
Carrying |
Estimated |
Carrying |
Estimated |
|||||||||||||
| Amount | Fair Value | Amount | Fair Value | |||||||||||||
|
Long-Term Debt
|
||||||||||||||||
|
5.45% Notes due 2015
|
$ | 100,000 | $ | 93,836 | $ | — | $ | — | ||||||||
|
5.92% Notes due 2018
|
200,000 | 180,729 | — | — | ||||||||||||
|
Credit Facility
|
270,000 | 270,000 | 290,000 | 290,000 | ||||||||||||
|
Long-Term Debt
|
$ | 570,000 | $ | 544,565 | $ | 290,000 | $ | 290,000 | ||||||||
| 14. | SIGNIFICANT CUSTOMERS: |
The Company’s 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 Company’s overall exposure to credit risk
because customers may be similarly affected by changes in
economic and other conditions. The Company performs a credit
analysis of customers prior to making any sales to new customers
or increasing credit for existing customers. Based upon this
credit analysis, the Company may require a standby letter of
credit or a financial guarantee.
71
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ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A significant customer is defined as one that individually
accounts for 10% or more of the Company’s total revenues
during 2008. In 2008, sales to Nicor Enerchange were
$115.7 million and sales to Tenaska were
$117.9 million, which accounted for 10.7% and 10.9% of the
Company’s total 2008 revenues, respectively. At
December 31, 2008, the Company had outstanding receivables
(which were all paid in full in January 2009) from these
two significant customers totaling $15.9 million.
| 15. | SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): |
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Total | ||||||||||||||||
|
2008
|
||||||||||||||||||||
|
Revenues from continuing operations
|
$ | 271,137 | $ | 308,240 | $ | 297,627 | $ | 207,396 | $ | 1,084,400 | ||||||||||
|
Gain (loss) on commodity derivatives
|
(27,673 | ) | (11,596 | ) | 58,117 | 14,368 | 33,216 | |||||||||||||
|
Expenses from continuing operations
|
107,922 | 112,346 | 110,308 | 111,818 | 442,394 | |||||||||||||||
|
Interest expense, net
|
5,122 | 4,416 | 5,091 | 6,229 | 20,858 | |||||||||||||||
|
Income before income tax provision
|
130,420 | 179,882 | 240,345 | 103,717 | 654,364 | |||||||||||||||
|
Income tax provision
|
47,021 | 63,489 | 91,370 | 38,624 | 240,504 | |||||||||||||||
|
Income from continuing operations
|
83,399 | 116,393 | 148,975 | 65,093 | 413,860 | |||||||||||||||
|
Revenues from discontinued operations
|
(103 | ) | 743 | — | — | 640 | ||||||||||||||
|
Expenses from discontinued operations
|
— | — | — | — | — | |||||||||||||||
|
Income tax (benefit) provision — discontinued
operations
|
(36 | ) | 261 | — | — | 225 | ||||||||||||||
|
Net income
|
83,332 | $ | 116,875 | $ | 148,975 | $ | 65,093 | $ | 414,275 | |||||||||||
|
Basic Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 0.55 | $ | 0.76 | $ | 0.98 | $ | 0.43 | $ | 2.72 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.00 | $ | 0.00 | $ | 0.00 | $ | 0.00 | ||||||||||
|
Net income per common share
|
$ | 0.55 | $ | 0.76 | $ | 0.98 | $ | 0.43 | $ | 2.72 | ||||||||||
|
Fully Diluted Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 0.53 | $ | 0.74 | $ | 0.95 | $ | 0.42 | $ | 2.65 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.00 | $ | 0.00 | $ | 0.00 | $ | 0.00 | $ | 0.00 | ||||||||||
|
Net income per common share
|
$ | 0.53 | $ | 0.74 | $ | 0.95 | $ | 0.42 | $ | 2.65 | ||||||||||
72
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ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Total | ||||||||||||||||
|
2007
|
||||||||||||||||||||
|
Revenues from continuing operations
|
$ | 156,576 | $ | 130,871 | $ | 117,216 | $ | 161,975 | $ | 566,638 | ||||||||||
|
Gain (loss) on commodity derivatives
|
— | — | — | — | — | |||||||||||||||
|
Expenses from continuing operations
|
61,530 | 63,259 | 61,386 | 77,927 | 264,102 | |||||||||||||||
|
Interest expense, net
|
2,373 | 3,913 | 5,347 | 5,040 | 16,673 | |||||||||||||||
|
Income before income tax provision
|
92,673 | 63,699 | 50,483 | 79,008 | 285,863 | |||||||||||||||
|
Income tax provision
|
32,030 | 23,949 | 17,727 | 31,915 | 105,621 | |||||||||||||||
|
Income from continuing operations
|
60,643 | 39,750 | 32,756 | 47,093 | 180,242 | |||||||||||||||
|
Revenues from discontinued operations
|
19,617 | 25,951 | 19,254 | 98,066 | 162,888 | |||||||||||||||
|
Expenses from discontinued operations
|
9,683 | 12,399 | 12,110 | 420 | 34,612 | |||||||||||||||
|
Income tax provision — discontinued operations
|
3,985 | 4,235 | 2,500 | 34,762 | 45,482 | |||||||||||||||
|
Net income
|
$ | 66,592 | $ | 49,067 | $ | 37,400 | $ | 109,977 | $ | 263,036 | ||||||||||
|
Basic Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 0.40 | $ | 0.26 | $ | 0.22 | $ | 0.31 | $ | 1.19 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.04 | $ | 0.06 | $ | 0.03 | $ | 0.42 | $ | 0.54 | ||||||||||
|
Net income per common share
|
$ | 0.44 | $ | 0.32 | $ | 0.25 | $ | 0.73 | $ | 1.73 | ||||||||||
|
Fully Diluted Earnings per Share:
|
||||||||||||||||||||
|
Income per common share from continuing operations
|
$ | 0.38 | $ | 0.25 | $ | 0.21 | $ | 0.30 | $ | 1.14 | ||||||||||
|
Income per common share from discontinued operations
|
$ | 0.04 | $ | 0.06 | $ | 0.03 | $ | 0.40 | $ | 0.52 | ||||||||||
|
Net income per common share
|
$ | 0.42 | $ | 0.31 | $ | 0.24 | $ | 0.70 | $ | 1.66 | ||||||||||
Revenues from discontinued operations for the fourth quarter of
2007 include the pre-tax gain on sale associated with the China
properties in the amount of $98.1 million.
| 16. | DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): |
The following information about the Company’s 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, 2008, 2007, 2006 and 2005 are based upon
estimates prepared by Netherland, Sewell & Associates,
Inc. and estimates provided by Ryder Scott Company as of
December 31, 2006
73
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and 2005. The estimates for properties in the United States were
prepared by Netherland, Sewell & Associates, Inc. in
reports dated February 6, 2009, February 4, 2008,
January 30, 2007 and January 27, 2006, respectively.
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, 2008, 2007 and 2006. All such
reserves are located in the Green River Basin, Wyoming,
Pennsylvania and Bohai Bay in China. Since January 1, 2008,
no crude oil or natural gas reserve information has been filed
with, or included in any report to, any federal authority or
agency other than the SEC and the Energy Information
Administration (“EIA”) of the U.S. Department of
Energy. We file Form 23, including reserve and other
information, with the EIA.
| 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, 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 | ) | (69,499,600 | ) | 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 | ||||||||||||||||||
|
Extensions, discoveries and additions
|
6,091,000 | 747,914,000 | — | — | 6,091,000 | 747,914,000 | ||||||||||||||||||
|
Sales
|
— | — | (2,833,400 | ) | — | (2,833,400 | ) | — | ||||||||||||||||
|
Production
|
(870,100 | ) | (109,177,600 | ) | (1,153,300 | ) | — | (2,023,400 | ) | (109,177,600 | ) | |||||||||||||
|
Revisions
|
(232,000 | ) | (54,182,200 | ) | — | — | (232,000 | ) | (54,182,200 | ) | ||||||||||||||
|
Reserves, December 31, 2007
|
22,831,500 | 2,842,654,900 | — | — | 22,831,500 | 2,842,654,900 | ||||||||||||||||||
|
Extensions, discoveries and additions
|
6,536,100 | 803,199,500 | — | — | 6,536,100 | 803,199,500 | ||||||||||||||||||
|
Sales
|
— | — | — | — | — | — | ||||||||||||||||||
|
Production
|
(1,121,500 | ) | (138,563,700 | ) | — | — | (1,121,500 | ) | (138,563,700 | ) | ||||||||||||||
|
Revisions
|
(1,238,600 | ) | (151,503,000 | ) | — | — | (1,238,600 | ) | (151,503,000 | ) | ||||||||||||||
|
Reserves, December 31, 2008
|
27,007,500 | 3,355,787,700 | — | — | 27,007,500 | 3,355,787,700 | ||||||||||||||||||
|
Proved developed reserves:
|
||||||||||||||||||||||||
|
December 31, 2006
|
6,522,000 | 842,969,000 | 2,686,000 | — | 9,208,000 | 842,969,000 | ||||||||||||||||||
|
December 31, 2007
|
8,764,000 | 1,084,224,000 | — | — | 8,764,000 | 1,084,224,000 | ||||||||||||||||||
|
December 31, 2008
|
11,462,000 | 1,412,562,000 | — | — | 11,462,000 | 1,412,562,000 | ||||||||||||||||||
| C. | STANDARDIZED MEASURE: |
The following table sets forth a standardized measure of the
estimated discounted future net cash flows attributable to the
Company’s proved natural gas reserves. Natural gas prices
have fluctuated widely in recent years.
74
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The calculated weighted average sales prices utilized for the
purposes of estimating the Company’s proved reserves and
future net revenues were $4.71, $6.13, and $4.50 per Mcf of
natural gas at December 31, 2008, 2007 and 2006,
respectively. The calculated weighted average oil price at
December 31, 2008, 2007, and 2006 for Wyoming was $30.10,
$86.91 and $59.95, respectively. The calculated weighted average
crude oil price at December 31, 2006 for China was a Duri
price of $46.57. 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
Company’s proved reserves and the tax basis of proved
properties and available operating loss carryovers.
| United States | China | Total | ||||||||||
|
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 | ||||||
|
As of December 31, 2007
|
||||||||||||
|
Future cash inflows
|
$ | 19,411,520 | $ | — | $ | 19,411,520 | ||||||
|
Future production costs
|
(4,233,952 | ) | — | (4,233,952 | ) | |||||||
|
Future development costs
|
(2,100,647 | ) | — | (2,100,647 | ) | |||||||
|
Future income taxes
|
(4,414,331 | ) | — | (4,414,331 | ) | |||||||
|
Future net cash flows
|
8,662,590 | — | 8,662,590 | |||||||||
|
Discounted at 10%
|
(4,793,188 | ) | — | (4,793,188 | ) | |||||||
|
Standardized measure of discounted future net cash flows
|
$ | 3,869,402 | $ | — | $ | 3,869,402 | ||||||
|
As of December 31, 2008
|
||||||||||||
|
Future cash inflows
|
$ | 16,608,609 | $ | — | $ | 16,608,609 | ||||||
|
Future production costs
|
(4,217,034 | ) | — | (4,217,034 | ) | |||||||
|
Future development costs
|
(2,351,312 | ) | — | (2,351,312 | ) | |||||||
|
Future income taxes
|
(3,222,246 | ) | — | (3,222,246 | ) | |||||||
|
Future net cash flows
|
6,818,017 | — | 6,818,017 | |||||||||
|
Discounted at 10%
|
(3,800,331 | ) | — | (3,800,331 | ) | |||||||
|
Standardized measure of discounted future net cash flows
|
$ | 3,017,686 | $ | — | $ | 3,017,686 | ||||||
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.
75
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| D. | SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: |
| December 31, 2008 | December 31, 2007 | December 31, 2006 | ||||||||||
|
Standardized measure, beginning
|
$ | 3,869,402 | $ | 1,871,553 | $ | 3,576,494 | ||||||
|
Net revisions of previous quantity estimates
|
(247,791 | ) | (126,447 | ) | (185,419 | ) | ||||||
|
Extensions, discoveries and other changes
|
1,313,391 | 1,784,862 | 755,149 | |||||||||
|
Sales of reserves in place
|
— | (46,451 | ) | — | ||||||||
|
Changes in future development costs
|
(327,325 | ) | (254,538 | ) | (193,004 | ) | ||||||
|
Sales of oil and gas, net of production costs
|
(890,157 | ) | (496,556 | ) | (482,659 | ) | ||||||
|
Net change in prices and production costs
|
(1,971,128 | ) | 1,607,811 | (2,915,081 | ) | |||||||
|
Development costs incurred during the period that reduce future
development costs
|
503,582 | 315,523 | 243,933 | |||||||||
|
Accretion of discount
|
584,119 | 269,046 | 544,558 | |||||||||
|
Net changes in production rates and other
|
(362,018 | ) | 11,007 | (395,071 | ) | |||||||
|
Net change in income taxes
|
545,611 | (1,066,408 | ) | 922,653 | ||||||||
|
Aggregate changes
|
(851,716 | ) | 1,997,849 | (1,704,941 | ) | |||||||
|
Standardized measure, ending
|
$ | 3,017,686 | $ | 3,869,402 | $ | 1,871,553 | ||||||
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.
76
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| E. | COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (US$000): |
UNITED
STATES
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Acquisition costs — unproved properties
|
$ | 18,766 | $ | 7,780 | $ | 11,351 | ||||||
|
Exploration
|
395,970 | 385,238 | 152,922 | |||||||||
|
Development
|
534,914 | 304,782 | 317,118 | |||||||||
|
Total
|
$ | 949,650 | $ | 697,800 | $ | 481,391 | ||||||
CHINA
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Acquisition costs — unproved properties
|
$ | — | $ | 10,356 | $ | 7,152 | ||||||
|
Exploration
|
— | — | — | |||||||||
|
Development
|
— | 4,094 | 15,339 | |||||||||
|
Total
|
$ | — | $ | 14,450 | $ | 22,491 | ||||||
TOTAL
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Acquisition costs — unproved properties
|
$ | 18,766 | $ | 18,136 | $ | 18,503 | ||||||
|
Exploration
|
395,970 | 385,238 | 152,922 | |||||||||
|
Development
|
534,914 | 308,876 | 332,457 | |||||||||
|
Total
|
$ | 949,650 | $ | 712,250 | $ | 503,882 | ||||||
| F. | RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: |
UNITED
STATES
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Oil and gas revenue
|
$ | 1,084,400 | $ | 566,638 | $ | 508,659 | ||||||
|
Production expenses and taxes
|
(194,243 | ) | (115,371 | ) | (92,688 | ) | ||||||
|
Depletion and depreciation
|
(184,795 | ) | (135,470 | ) | (79,675 | ) | ||||||
|
Income taxes
|
(235,095 | ) | (104,553 | ) | (111,722 | ) | ||||||
|
Total
|
$ | 470,267 | $ | 211,244 | $ | 224,574 | ||||||
77
Table of Contents
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
CHINA
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Oil and gas revenue
|
$ | — | $ | 64,822 | $ | 84,008 | ||||||
|
Production expenses and taxes
|
— | (19,532 | ) | (17,320 | ) | |||||||
|
Depletion and depreciation
|
— | (14,981 | ) | (13,822 | ) | |||||||
|
Income taxes
|
— | (10,454 | ) | (18,941 | ) | |||||||
|
Total
|
$ | — | $ | 19,855 | $ | 33,925 | ||||||
TOTAL
| Years Ended | ||||||||||||
|
December 31, |
December 31, |
December 31, |
||||||||||
| 2008 | 2007 | 2006 | ||||||||||
|
Oil and gas revenue
|
$ | 1,084,400 | $ | 631,460 | $ | 592,667 | ||||||
|
Production expenses and taxes
|
(194,243 | ) | (134,903 | ) | (110,008 | ) | ||||||
|
Depletion and depreciation
|
(184,795 | ) | (150,451 | ) | (93,497 | ) | ||||||
|
Income taxes
|
(235,095 | ) | (115,007 | ) | (130,663 | ) | ||||||
|
Total
|
$ | 470,267 | $ | 231,099 | $ | 258,499 | ||||||
| G. | CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: |
|
December 31, |
December 31, |
|||||||
| 2008 | 2007 | |||||||
|
Developed Properties:
|
||||||||
|
Acquisition, equipment, exploration, drilling and environmental
costs — Domestic
|
$ | 2,809,082 | $ | 1,868,564 | ||||
|
Less accumulated depletion, depreciation and
amortization — Domestic
|
(514,100 | ) | (330,813 | ) | ||||
| 2,294,982 | 1,537,751 | |||||||
|
Unproven Properties:
|
||||||||
|
Acquisition and exploration costs — Domestic
|
55,544 | 36,778 | ||||||
| $ | 2,350,526 | $ | 1,574,529 | |||||
78
Table of Contents
| Item 9. | Change in and Disagreements with Accountants on Accounting and Financial Disclosures. |
None.
| Item 9A. | Controls and Procedures. |
Management’s
Report on Assessment of Internal Control Over Financial
Reporting
Management’s Report on Assessment of Internal Control Over
Financial Reporting is included on page 44 of this
form 10-K.
Changes
in Internal Control Over Financial Reporting
There were no changes in our internal control over financial
reporting during the quarter ended December 31, 2008 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, 2008. 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 SEC’s
rules and forms and communicated to our management as
appropriate to allow timely decisions regarding required
disclosure.
| 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 Company’s definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2008.
The Company has adopted a code of ethics that applies to the
Company’s Chief Executive Officer, Chief Financial Officer
and Chief Accounting Officer. The full text of such code of
ethics is posted on the Company’s 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 Company’s definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2008.
| 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 Company’s definitive proxy
statement, which will be filed not later than 120 days
after December 31, 2008 and is incorporated herein by
reference.
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Table of Contents
| Item 13. | Certain Relationships and Related Transactions, and Director Independence. |
The information required by this item is incorporated herein by
reference to the Company’s definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2008.
| Item 14. | Principal Accounting Fees and Services. |
The information required by this item is incorporated herein by
reference to the Company’s definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2008.
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 Company’s 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 Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001). | ||
| 3 | .3 | Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005) | ||
| 4 | .1 | Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001). | ||
| 4 | .2 | Form 8-A filed with the Securities and Exchange Commission on July 23, 2007. | ||
| 10 | .1 | Credit Agreement dated as of April 30, 2007 among Ultra Resources, Inc., JPMorgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities Inc. as Sole Bookrunner and Sole Lead Arranger, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2007). | ||
| 10 | .2 | Share Purchase Agreement dated September 26, 2007 between UP Energy Corporation and SPC E&P (China) Pte. Ltd. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on September 26, 2007). | ||
| 10 | .3 | Precedent Agreement between Rockies Express Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Report of Form 8-K filed on February 9, 2006). | ||
| 10 | .4 | 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 Company’s Report on Form 8-K filed on February 9, 2006). | ||
| 10 | .5 | Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-132443), filed with the SEC on March 15, 2006). | ||
| 10 | .6 | Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13278), filed with the SEC on March 15, 2001). | ||
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Table of Contents
|
Exhibit |
||||
|
Number
|
Description
|
|||
| 10 | .7 | Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on April 2, 2001). | ||
| 10 | .8 | Employment Agreement between Ultra Petroleum Corp. and Michael D. Watford dated August 6, 2007 (incorporated by reference from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2007). | ||
| 10 | .9 | Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008). | ||
| *10 | .10 | Base Contract for Sale and Purchase of Natural Gas dated November 1, 2004 between Ultra Resources, Inc. and Tenaska Marketing Ventures. | ||
| *10 | .11 | Base Contract for Sale and Purchase of Natural Gas dated November 1, 2007 between Ultra Resources, Inc. and Nicor Enerchange, LLC. | ||
| 21 | .1 | Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| *23 | .1 | Consent of Netherland, Sewell & Associates, Inc. | ||
| *23 | .2 | Consent of Ryder Scott Company. | ||
| *23 | .3 | Consent of Ernst & Young 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. | ||
| *100 | .INS | XBRL Instance Document | ||
| *100 | .SCH | XBRL Taxonomy Extension Schema Document | ||
| *100 | .CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||
| *100 | .LAB | XBRL Taxonomy Extension Label Linkbase Document | ||
| *100 | .PRE | XBRL Taxonomy Extension Presentation Linkbase Document | ||
| * | Filed herewith |
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Table of Contents
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 20, 2009
|
Signature
|
Title
|
Date
|
||||
|
/s/ Michael
D. Watford Michael D. Watford |
Chairman of the Board, Chief Executive Officer, and President (principal executive officer) |
February 20, 2009 | ||||
|
/s/ Marshall
D. Smith Marshall D. Smith |
Chief Financial Officer (principal financial officer) |
February 20, 2009 | ||||
|
/s/ Garland
R. Shaw Garland R. Shaw |
Corporate Controller (principal accounting officer) |
February 20, 2009 | ||||
|
/s/ W.
Charles Helton W. Charles Helton |
Director | February 20, 2009 | ||||
|
/s/ Stephen
J. McDaniel Stephen J. McDaniel |
Director | February 20, 2009 | ||||
|
/s/ Robert
E. Rigney Robert E. Rigney |
Director | February 20, 2009 | ||||
|
/s/ Roger
A. Brown Roger A. Brown |
Director | February 20, 2009 | ||||
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Table of Contents
EXHIBIT INDEX
|
Exhibit |
||||
|
Number
|
Description
|
|||
| 3 | .1 | Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Company’s 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 Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001). | ||
| 3 | .3 | Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005) | ||
| 4 | .1 | Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001). | ||
| 4 | .2 | Form 8-A filed with the Securities and Exchange Commission on July 23, 2007. | ||
| 10 | .1 | Credit Agreement dated as of April 30, 2007 among Ultra Resources, Inc., JPMorgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities Inc. as Sole Bookrunner and Sole Lead Arranger, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2007). | ||
| 10 | .2 | Share Purchase Agreement dated September 26, 2007 between UP Energy Corporation and SPC E&P (China) Pte. Ltd. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on September 26, 2007). | ||
| 10 | .3 | Precedent Agreement between Rockies Express Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Report of Form 8-K filed on February 9, 2006). | ||
| 10 | .4 | 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 Company’s Report on Form 8-K filed on February 9, 2006). | ||
| 10 | .5 | Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-132443), filed with the SEC on March 15, 2006). | ||
| 10 | .6 | Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13278), filed with the SEC on March 15, 2001). | ||
| 10 | .7 | Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on April 2, 2001). | ||
| 10 | .8 | Employment Agreement between Ultra Petroleum Corp. and Michael D. Watford dated August 6, 2007 (incorporated by reference from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2007). | ||
| 10 | .9 | Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008). | ||
| *10 | .10 | Base Contract for Sale and Purchase of Natural Gas dated November 1, 2004 between Ultra Resources, Inc. and Tenaska Marketing Ventures. | ||
| *10 | .11 | Base Contract for Sale and Purchase of Natural Gas dated November 1, 2007 between Ultra Resources, Inc. and Nicor Enerchange, LLC. | ||
| 21 | .1 | Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| *23 | .1 | Consent of Netherland, Sewell & Associates, Inc. | ||
| *23 | .2 | Consent of Ryder Scott Company . | ||
| *23 | .3 | Consent of Ernst & Young 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. | ||
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Table of Contents
|
Exhibit |
||||
|
Number
|
Description
|
|||
| *100 | .INS | XBRL Instance Document | ||
| *100 | .SCH | XBRL Taxonomy Extension Schema Document | ||
| *100 | .CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||
| *100 | .LAB | XBRL Taxonomy Extension Label Linkbase Document | ||
| *100 | .PRE | XBRL Taxonomy Extension Presentation Linkbase Document | ||
| * | Filed herewith |
84