e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31,
2010
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number
001-33614
ULTRA PETROLEUM CORP.
(Exact name of registrant as
specified in its charter)
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Yukon Territory, Canada
(State or other jurisdiction
of
incorporation or organization)
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N/A
(I.R.S. employer
identification number)
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363 North Sam Houston Parkway East,
Suite 1200, Houston, Texas
(Address of principal
executive offices)
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77060
(Zip
code)
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(281) 876-0120
(Registrants
telephone number, including area code)
Securities
registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Shares, without par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. YES þ NO o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. YES o NO þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. YES þ NO o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). YES þ NO o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, 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):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
(Do not check if a smaller reporting company)
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Smaller reporting
company o
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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
$6,747,137,694 as of June 30, 2010 (based on the last
reported sales price of $44.25 of such stock on the New York
Stock Exchange on such date).
The number of common shares, without par value, of Ultra
Petroleum Corp., outstanding as of February 16, 2011 was
152,573,843.
Documents incorporated by reference: The definitive Proxy
Statement for the 2011 Annual Meeting of Stockholders, which
will be filed with the Securities and Exchange Commission within
120 days after December 31, 2010, is incorporated by
reference in Part III of this
Form 10-K.
TABLE OF
CONTENTS
Certain
Definitions
Terms
used to describe quantities of oil and natural gas and
marketing
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Bbl One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
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Bcf One billion cubic feet of natural gas.
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Bcfe One billion cubic feet of natural gas
equivalent.
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BOE One barrel of oil equivalent, converting
natural gas to oil at the ratio of 6 Mcf of natural gas to
1 Bbl of oil.
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BTU British Thermal Unit.
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Condensate An oil-like liquid produced in
association with natural gas production that condenses from
natural gas as it is produced and delivered into a separator or
similar equipment and collected in tanks at each well prior to
the delivery of such natural gas to the natural gas gathering
pipeline system.
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MBbl One thousand barrels of crude oil or
other liquid hydrocarbons.
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Mcf One thousand cubic feet of natural gas.
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Mcfe One thousand cubic feet of natural gas
equivalent, converting oil or condensate to natural gas at the
ratio of 1 Bbl of oil or condensate to 6 Mcf of
natural gas. This conversion ratio, which is typically used in
the oil and gas industry, represents the approximate energy
equivalent of a barrel of oil or condensate to an Mcf of
natural gas. The sales price of one barrel of oil or condensate
has been much higher than the sales price of six Mcf of natural
gas over the last several years, so a six to one conversion
ratio does not represent the economic equivalency of six Mcf of
natural gas to one barrel of oil or condensate.
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MMBbl One million barrels of crude oil or
other liquid hydrocarbons.
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MMcf One million cubic feet of natural gas.
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MBOE One thousand BOE.
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MMBOE One million BOE.
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MMBTU One million British Thermal Units.
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Terms
used to describe the Companys interests in wells and
acreage
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Gross oil and natural gas wells or acres The
Companys gross wells or gross acres represent the total
number of wells or acres in which the Company owns a working
interest.
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Net oil and natural gas wells or acres
Determined by multiplying gross oil
and natural gas wells or acres by the working interest that the
Company owns in such wells or acres represented by the
underlying properties.
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Prospect A location where hydrocarbons such
as oil and gas are believed to be present in quantities which
are economically feasible to produce.
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Terms
used to assign a present value to the Companys
reserves
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Standardized measure of discounted future net cash flows,
after income taxes The present value, discounted
at 10%, of the after tax future net cash flows attributable to
estimated net proved reserves. The Company calculates this
amount by assuming that it will sell the oil and natural gas
production attributable to the proved reserves estimated in its
independent engineers reserve report for the oil and
natural gas spot prices based on the average price during the
12-month
period before the ending date of the period covered by the
report determined as an unweighted, arithmetic average of the
first-day-of-the-month
price for each month within such period, 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 Companys
proved reserves.
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Standardized measure of discounted future net cash flows
before income taxes The discounted present value
of proved reserves is identical to the standardized measure
described above, except that estimated future income taxes are
not deducted in calculating future net cash flows. The Company
discloses the discounted present value without deducting
estimated income taxes to provide what it believes is a better
basis for comparison of its reserves to the producers who may
have different income tax rates.
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Terms
used to classify the Companys reserve
quantities
The Securities and Exchange Commission (SEC)
definition of proved oil and natural gas reserves, per
Regulation S-X,
is as follows:
Economically producible A resource that
generates revenue that exceeds (or is reasonably expected to
exceed) costs of the operation.
Estimated ultimate recovery (EUR)
The sum of reserves remaining as of a given date and cumulative
production as of that date.
Proved oil and gas reserves Proved oil and
natural gas reserves are those quantities of oil and gas, which,
by analysis of available geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward from known
reservoirs and under existing economic conditions, operating
methods, and government regulation before the time
at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation.
The project to extract the hydrocarbons must have commenced or
the operator must be reasonably certain that it will commence
the project within a reasonable time.
The area of the reservoir considered as proved includes all of
the following:
a. The area identified by drilling and limited fluid
contacts, if any,
b. Adjacent undrilled portions of the reservoir that can,
with reasonable certainty, be judged to be continuous with it
and to contain economically producible oil or gas on the basis
of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons as seen
in a well penetration unless geoscience, engineering, or
performance data and reliable technology establish a lower
contact with reasonable certainty.
Where direct observation from well penetrations has defined a
highest known oil elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the
structurally higher portions of the reservoir only if
geoscience, engineering, or performance data and reliable
technology establish the higher contact with reasonable
certainty.
Reserves that can be produced economically through application
of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when
both of the following occur:
a. Successful testing by a pilot project in an area of the
reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based.
b. The project has been approved for development by all
necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which
economic producibility from a reservoir is to be determined. The
price is the average price during the
12-month
period before the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
Proved developed oil and gas reserves Proved
oil and gas reserves that can be expected to be recovered:
a. Through existing wells with existing equipment and
operating methods or in which the cost of the required equipment
is relatively minor compared with the cost of a new well.
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b. Through installed extraction equipment and
infrastructure operational at the time of the reserves estimate
if the extraction is by means not involving a well.
Proved undeveloped oil and gas reserves
Proved oil and gas reserves that are expected to
be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage shall be limited
to those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence
using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances.
Undrilled locations can be classified as having undeveloped
reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless
the specific circumstances justify a longer time.
Under no circumstances are estimates for proved undeveloped
reserves attributable to any acreage for which an application of
fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective
by actual projects in the same reservoir or an analogous
reservoir, or by other evidence using reliable technology
establishing reasonable certainty.
Reasonable certainty If deterministic methods
are used, a high degree of confidence that the quantities will
be recovered. If probabilistic methods are used, at least a
90 percent probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of
confidence exists if the quantity is much more likely to be
achieved than not, and, as changes due to increased availability
of geoscience (geological, geophysical, and geochemical),
engineering, and economic data are made to estimated ultimate
recovery (EUR) with time, reasonably certain EUR is much more
likely to increase or remain constant than to decrease.
Reliable technology A grouping of one or more
technologies (including computational methods) that has been
field tested and demonstrated to provide reasonably certain
results with consistency and repeatability in the formation
being evaluated or in an analogous formation.
Resources Quantities of oil and gas estimated
to exist in naturally occurring accumulations. A portion of the
resources may be estimated to be recoverable, and another
portion may be considered to be unrecoverable. Resources include
both discovered and undiscovered accumulations.
Terms
used to describe the legal ownership of the Companys oil
and natural gas properties
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Revenue interest The amount of the interest
owned in the proceeds derived from a producing well less all
royalty interests.
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Working interest A real property interest
entitling the owner to receive a specified percentage of the
proceeds of the sale of oil and natural gas production or a
percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and
produce such oil and natural gas. A working interest owner who
owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or
disapprove the appointment of an operator and drilling and other
major activities in connection with the development and
operation of a property.
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Terms
used to describe seismic operations
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Seismic data Oil and natural gas companies
use seismic data as their principal source of information to
locate oil and natural gas deposits, both to aid in exploration
for new deposits and to manage or enhance production from known
reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are
reflected back to the surface by underground formations, where
they are detected by geophones which digitize and record the
reflected waves. Computers are then used to process the raw data
to develop an image of underground formations.
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2-D
seismic data
2-D seismic
survey data has been the standard acquisition technique used to
image geologic formations over a broad area.
2-D seismic
data is collected by a single line of energy sources which
reflect seismic waves to a single line of geophones. When
processed,
2-D seismic
data produces an image of a single vertical plane of
sub-surface
data.
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3-D
seismic data
3-D seismic
data is collected using a grid of energy sources, which are
generally spread over several miles. A
3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube
of information that can be divided into various planes, thus
improving visualization. Consequently,
3-D seismic
data is generally considered a more reliable indicator of
potential oil and natural gas reservoirs in the area evaluated.
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Other
Terms
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All-in costs The sum of costs per Mcfe
relating to lease operating expenses, severance taxes, gathering
costs, transportation charges, depletion, depreciation and
amortization, interest expense and general and administrative
expenses.
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Reserve replacement ratio The sum of the
estimated net proved reserves added through discoveries,
extensions, infill drilling and acquisitions (which may include
or exclude reserve revisions of previous estimates) for a
specified period of time divided by production for that same
period of time.
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Finding and development costs Finding and
development costs, including revisions, are calculated by
dividing the sum of property acquisition costs, exploration
costs and development costs for the year, by the total of
reserve extensions, discoveries, purchases and all revisions for
the year.
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PART I
General
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 incorporated on November 14, 1979, under the laws of
the Province of British Columbia, Canada. Ultra remains a
Canadian company, but since March 2000, has operated under the
laws of The Yukon Territory, Canada pursuant to Section 190
of the Business Corporations Act (Yukon Territory). The
Companys operations are primarily located in the Green
River Basin of southwest Wyoming and in the north-central
Pennsylvania area of the Appalachian Basin.
The Companys annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
and current reports on
Form 8-K,
as well as any amendments to such reports and all other filings
pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 are available free of charge to the public
on the Companys website at www.ultrapetroleum.com. To
access the Companys SEC filings, select SEC
Filings under the Investor Relations tab on the
Companys website. You may also request a copy of these
filings at no cost by making written or telephone requests for
copies to Ultra Petroleum Corp., Manager, Investor Relations,
363 N. Sam Houston Pkwy. E., Suite 1200, Houston,
TX 77060,
(281) 876-0120.
Any materials that the Company has filed with the SEC may be
read and/or
copied at the SECs Public Reference Room at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
The SEC maintains an internet site that contains reports, proxy
and information statements, and other information regarding the
Company. The SECs website address is www.sec.gov.
Oil and
Gas Properties Overview
Ultras current operations in southwest Wyoming are focused
on developing the Companys position in a tight gas sand
trend located in the Green River Basin with targets in 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. As
of December 31, 2010, Ultra owned interests in
approximately 94,000 gross (54,000 net) acres in Wyoming
covering approximately 190 square miles.
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Ultras current operations in north-central Pennsylvania
are focused on assessing, exploring and developing its position
in the Marcellus Shale and deeper horizons. At December 31,
2010, the Company owned interests in approximately
495,000 gross (260,000 net) acres in Pennsylvania.
Business
Strategy
Ultras mission is to profitably grow an upstream oil and
gas company for the long-term benefit of its shareholders.
Ultras strategy includes building a robust portfolio of
high return investment opportunities, maintaining a disciplined
approach to capital investment, maximizing earnings and cash
flows by controlling costs and maintaining financial flexibility.
High Return Portfolio. Ultra maintains a
portfolio of properties that provide long-term growth through
development in areas that support sustainable, lower-risk,
repeatable, high return drilling projects. The Company
continually evaluates opportunities for the acquisition,
exploration and development of additional oil and natural gas
properties that afford risk-adjusted returns in excess of or
equal to its current set of investment alternatives.
Disciplined Capital Investment. The
Companys business strategy involves the regular review of
its investment opportunities in order to optimize return to its
shareholders. Over the past ten years, Ultra has consistently
delivered meaningful reserve and production growth while
providing significant returns to its shareholders. In 2010, oil
and natural gas production increased 19% over 2009 levels and
estimated proved reserves increased 13% to 4.4 Tcfe from
3.9 Tcfe with return on capital employed of 17% and return
on equity of 39%.
Low Cost Producer. Ultra strives to maintain
one of the lowest cost structures in the industry in terms of
both adding and producing oil and natural gas reserves. The
Company continues to focus on improving its drilling and
production results through the use of advanced technologies and
detailed technical analysis of its properties. For the year
ended 2010, the Companys all-in costs were $2.68 per Mcfe
with finding and development costs of $1.48 per Mcfe.
Financial Flexibility. Preserving financial
flexibility and a strong balance sheet are also strategic to
Ultras business philosophy. At December 31, 2010, the
Company had cash on hand of $70.8 million and outstanding
debt was $1.6 billion. Consistent with this strategy,
during 2010 the Company issued approximately $1.025 billion
of senior notes at an average interest rate of 5.05% and a
weighted average term of 10.6 years. As a result of the
issuance, the availability under the Companys revolving
credit facility increased to $500.0 million and the average
debt maturity profile lengthened to over nine years due to
adding tranches of 12 and 15 year debt while the
Companys weighted average cost of debt remains at
approximately 5.6%.
Green
River Basin, Wyoming
During 2010, the Company participated in the drilling of
217 wells in Wyoming and continued to improve its drilling
and completion efficiency on its operated wells as measured by
spud to total depth. During 2010, the average drilling days
decreased 30% from 2009 levels to 14 days from spud to
total depth. In addition, the Companys average well cost
decreased from $5.0 million per well during 2009 to
$4.7 million during 2010. This 6% reduction in costs is a
direct result of fewer drilling days, fewer rig moves associated
with pad drilling and lower cost of services. These cost
reductions were accomplished while simultaneously drilling
deeper wells and completing more frac stages per well.
During 2011, the Company plans to continue its ongoing
development program of its acreage position in the tight gas
sand trend in the Green River Basin in southwest Wyoming. The
Company expects that wells drilled during 2011 will target the
sands of the upper Cretaceous Lance Pool in the Pinedale and
Jonah fields.
Additionally, the Company plans to continue its assessment of
increased density drilling to more efficiently recover the vast
resources present in the area. Currently, essentially all of the
Pinedale field is approved by the WOGCC for 16 wells per
160-acre
government quarter section
(10-acre
equivalent). Pilot activities are planned to continue in 2011 in
areas approved for testing of well density of 32 wells per
160-acre
government quarter section
(5-acre
equivalent). 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).
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All of the Companys drilling activity is conducted
utilizing its extensive integrated geological and geophysical
data set. This data set is being utilized to map the potentially
productive intervals, to identify areas for future extension of
the Lance fairway and to identify deeper objectives which may
warrant drilling.
Pennsylvania
Ultra Petroleum continued the assessment of its acreage in
Pennsylvania during 2010. The Company participated in the
drilling of 116 horizontal Marcellus wells and acquired
76 square miles of 3D seismic data on its properties during
2010.
The Company is actively leveraging its Pinedale experience by
translating its Wyoming directional drilling, completion and
production knowledge to the Marcellus. During the year ended
December 31, 2010, the Company averaged 13.0 days rig
release to rig release for Ultra operated wells as compared to
15.5 days during 2009.
During 2011, the Company plans to expand its exploration and
development activities in the Middle Devonian Marcellus Shale
play on its acreage position in Pennsylvania. Ultras
current activities are located in Potter, Tioga, Clinton, Centre
and Lycoming counties. Activities include lease acquisition,
3-D seismic,
drilling, completion, infrastructure construction and production
operations. The Companys activities are focused in the
north-central counties of Pennsylvania where the Company
believes favorable Marcellus Shale properties exist for economic
development.
During 2010, a wholly-owned subsidiary of the Company acquired,
for $403.8 million in cash, non-producing mineral acres and
a small number of producing gas wells in the Pennsylvania
Marcellus Shale. Additionally, the Company purchased additional
undeveloped acreage in the Marcellus Shale for approximately
$63.4 million during 2010.
Marketing
and Pricing
Overview
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. An increasing portion of the Companys
revenues is associated with gas sales from wells operated by the
Company and others in the Appalachian Basin in Pennsylvania.
Historically, the Companys revenues have been 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 completion of the Rockies Express Pipeline
(REX), a substantial portion of the Companys
revenues are now determined by natural gas market prices in the
Midwestern and Eastern regions of the United States. Energy
commodity prices in general, and the Companys regional
natural gas prices in particular, have been highly volatile, and
such volatility is expected to continue in the future.
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
Companys 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 REX pipeline now operational into Ohio,
and with the addition of new gas production in Pennsylvania, the
Companys customer base has expanded to include a
significant number of new customers situated in the Midwestern
and Eastern regions of the United States. The sale of the
Companys natural gas is as produced. As such,
the Company does not maintain any significant inventories or
imbalances of natural gas.
Midstream services. For its natural gas
production in Wyoming, 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 service providers have
routinely expanded their
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facilities capacities in southwest Wyoming to accommodate
growing volumes from wells in which the Company owns an
interest. Such expansions are continuing and 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 from Wyoming.
In Pennsylvania, the Company and its partners are constructing
gas gathering pipelines and facilities, compression facilities
and pipeline delivery stations to gather production from its
newly completed natural gas wells. Construction on these
facilities is expected to continue throughout 2011, so the
Company can manage its midstream capacity to coincide with
increased capacity requirements from its drilling activities.
These facilities are gathering systems and related
infrastructure, and their construction is expected to continue
until the field is fully developed. To date, none of the
Companys natural gas production in Pennsylvania has
required processing, treating or blending in order to remove
natural gas liquids or other impurities and it is anticipated
that facilities of this type will not be required in the future
to accommodate the Companys production.
Pipeline infrastructure. The Company has taken
actions to facilitate the expansion of the pipeline
infrastructure available to move its natural gas supplies away
from southwest Wyoming, to provide sufficient capacity to
transport its natural gas production and to provide for
reasonable prices for its natural gas in the future. Such
actions include becoming an anchor shipper on REX, which begins
at the Opal Processing Plant in southwest Wyoming and traverses
Wyoming and several other states to an ultimate terminus in
eastern Ohio. The Company is obligated to pay REX certain demand
charges related to its rights to hold this firm transportation
capacity. The Companys original commitment involves
capacity of 200 MMMBtu per day of natural gas for a term of
10 years, commencing November 2009. Subsequently, the
Company entered into agreements to secure an additional capacity
of 50 MMMBtu per day on the REX pipeline system, for the
periods commencing January 2012 through December 2018. This
additional capacity will provide the Company with the ability to
move additional volumes from its producing wells in Wyoming to
markets in the eastern U.S.
Two new pipeline projects originating in Wyoming and designed to
transport natural gas to markets not currently accessible to
Wyoming producers have been approved and are positioned to
further increase takeaway capacity from the Rockies and Wyoming
in particular. The Ruby Pipeline has received final Certificate
of Authority and began construction during 2010. The Bison
Pipeline commenced delivery service in January 2011. These two
pipelines will add aggregate export pipeline capacity for
Rockies/Wyoming gas of approximately 1.7 Bcf per day, a 20%
increase over current levels. The Company evaluated and declined
the opportunity to commit to hold firm transportation rights on
these two new pipelines.
Basis differentials. 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
Companys ability to control. These factors include, among
others, weather, natural gas supplies, natural gas demand,
inventory levels in natural gas storage fields, 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 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
Companys gas to markets in other regions or states. These
differentials are also reflective of the general relative
abundance of, or lack of, export pipeline capacity to move gas
out of the Rockies. The Inside FERC First of Month Index for
Northwest Pipeline Rocky Mountains basis was
generally wide since 2006 but narrowed during the latter portion
of 2009 and has continued to narrow in 2010, primarily as a
result of the completion of the REX pipeline into Ohio, as well
as additional export capacity out of the Rocky Mountain region
in general. (See Pipeline Infrastructure above).
The table below provides a historical and future perspective on
average annual basis differentials for Wyoming natural gas (NW
Rockies) and premium markets in the Northeast (Dominion South).
The basis differential is
9
expressed as a percentage of the Henry Hub price as reported by
Platts M2M (Mark to Market) Report on December 31,
2010.
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2007
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2008
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2009
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2010
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2011
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2012
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2013
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NW Rockies
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58
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%
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|
|
69
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%
|
|
|
77
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%
|
|
|
90
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%
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|
|
91
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%
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|
|
92
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%
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|
|
93
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%
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Dominion South
|
|
|
105
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%
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|
|
105
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%
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|
|
107
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%
|
|
|
104
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%
|
|
|
104
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%
|
|
|
103
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%
|
|
|
102
|
%
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Derivatives
The Company, from time to time, in the regular course of its
business, hedges a portion of its natural gas production
primarily through the use of financial swaps with creditworthy
financial counterparties (See Note 13), or through the use
of fixed price, forward sales of physical gas. 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.
In response to the lower price environment resulting from the
supply/demand imbalance during 2010, the Company continued to
hedge a portion of its exposure to volatile natural gas prices
by entering into forward swaps for 2010 through 2012. This
strategy of hedging will result in greater price certainty for
the Companys production and helps protect the
Companys capital investment program for those years. For a
more detailed description of the Companys hedging
activities, see Item 7A. Quantitative and Qualitative
Disclosures About Market Risk.
The Companys hedging policy limits the amounts of
resources hedged to not more than 50% of its forecast production
without Board approval. As of January 1, 2008, 2009 and
2010, the quantities that the Company hedged for the succeeding
twelve month periods represented 48%, 53% and 46%, respectively,
of the Companys forecasted production for such periods.
During 2009, Ultras board approved hedges of 53% of
forecast 2009 production.
Oil
Marketing
The Company markets its Wyoming condensate to various
purchasers. The pricing realized from the sale of the
Companys condensate production was less volatile during
2010 than in recent years. The Companys condensate
realized pricing is typically based on New York Mercantile
Exchange crude futures daily settlement prices, less a
negotiated location/transportation discount or differential. All
of the Companys condensate sales are denominated in
U.S. dollars per barrel and are paid for on a monthly
basis. The Company routinely maintains only operating
inventories of condensate production and sells its product on an
as produced basis. A portion of the Companys
condensate sales are done by its operating partners in the
Pinedale Field.
Historically, the Companys condensate production was
gathered from its Wyoming well locations by tanker trucks and
then shipped to other locations for injection into crude oil
pipelines or other facilities. During 2010, the Company
initiated service on its final two, of four total, central
gathering facilities. These facilities are part of the
Companys liquids gathering system designed to gather
condensate and water from various leases and wells operated by
the Company as contemplated under the Supplemental Environment
Impact Statement (SEIS) and Record of Decision
(ROD) as discussed below in Environmental Matters.
The condensate and water are transported to central points in
the field where condensate can be loaded into trucks or
delivered into pipelines for delivery to the Companys
customers. Produced water is disposed of or recycled and re-used.
Significant
Counterparties
A significant counterparty is defined as one that individually
accounts for 10% or more of the Companys total revenues
during the year. In 2010, the Company had no single counterparty
that represented 10% or more of the Companys total
revenues.
The Company maintains credit policies intended to mitigate the
risk of uncollectible accounts receivable related to the sale of
natural gas and condensate as well as commodity derivatives. A
more complete description of the Companys credit policies
are described in Note 13. The Company did not have any
outstanding, uncollectible accounts for its natural gas sales at
December 31, 2010.
10
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 Companys exploration and development is taking
place. The BLM issues a 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 BLMs 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.
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
BLMs field manager may also impose additional limitations
and mitigation measures as are deemed reasonably necessary to
mitigate the impact of drilling and production operations in the
area.
To date, the Company has expended significant resources in order
to satisfy applicable environmental laws and regulations in the
Pinedale Anticline area and other areas of operation under the
jurisdiction of the BLM. The Companys future costs of
complying with these regulations may continue to be 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
11
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
Questars acreage. Questars 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 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 EIS, or 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 Companys 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 Qualitys (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 contaminants 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.
In July 2009, Ultra, along with Shell and Questar, were awarded
the BLMs 2009 Environmental Best Management Practices
Award for Responsible Stewardship of Air Resources in the PAPA.
12
Regulation
Oil
and Gas Regulation
The availability of a ready market for oil and natural gas
production depends upon numerous factors beyond the
Companys control. These factors may include, among other
things, state and federal regulation of oil and natural gas
production and transportation, including regulations governing
environmental quality and pollution control and 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.
Most states, and some counties and municipalities, in which the
Company operates also regulate one or more of the following:
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The location of wells;
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|
The method of drilling and casing wells;
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|
The surface use and restoration of properties upon which wells
are drilled;
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|
The plugging and abandoning of wells; and
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Notice to surface owners and other third parties.
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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, which can affect our operations. State laws also
regulate the size and shape of drilling and spacing units or
proration units governing the pooling of oil and gas properties.
States generally impose a production, ad valorem or severance
tax with respect to the production and sale of oil and gas
within its jurisdiction. States do not generally regulate
wellhead prices or engage in other, similar direct economic
regulation, but there can be no assurance they will not do so in
the future.
The Companys sales of natural gas are affected by the
availability, terms and costs of transportation both in the
gathering systems that transport the natural gas from the
wellhead to the interstate pipelines and in the interstate
pipelines themselves. The rates, terms and conditions applicable
to the interstate transportation of natural gas by pipelines are
regulated by the FERC under the Natural Gas Act, as well as
under Section 311 of the Natural Gas Policy Act. Since
1985, the FERC has issued and implemented regulations intended
to increase competition within the natural gas industry by
making natural gas transportation more accessible to natural gas
buyers and sellers on an open-access, non-discriminatory basis.
The Companys sales of oil are also affected by the
availability, terms and costs of transportation. The rates,
terms, and conditions applicable to the interstate
transportation of oil by pipelines are regulated by the FERC
under the Interstate Commerce Act. The FERC has implemented a
simplified and generally applicable ratemaking methodology for
interstate oil pipelines to fulfill the requirements of
Title XVIII of the Energy Policy Act of 1992 comprised of
an indexing system to establish ceilings on interstate oil
pipeline rates.
If the Company conducts operations on federal, tribal or state
lands, such operations must comply with numerous regulatory
restrictions, including various operational requirements and
restrictions, nondiscrimination statutes and royalty and related
valuation requirements. In addition, some operations must be
conducted pursuant to certain
on-site
security regulations, bonding requirements and applicable
permits issued by the Bureau of Land Management
(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
13
corporations lease can be canceled in a proceeding
instituted by the United States Attorney General. Although the
regulations of the BLM (which administers the Mineral Act)
provide for agency designations of non-reciprocal countries,
there are presently no such designations in effect. The Company
owns interests in numerous federal onshore oil and gas leases.
It is possible that holders of the Companys equity
interests may be citizens of foreign countries, which could be
determined to be citizens of a non-reciprocal country under the
Mineral Act.
Surface
Damage Acts
Several states, including Wyoming, and some tribal nations have
enacted surface damage statutes. These laws are designed to
compensate for damages caused by oil and gas development
operations. Most surface damage statutes contain entry and
negotiation requirements to facilitate contact between the
operator and surface owners. Some also contain binding
requirements for payments by the operator in connection with
development operations.
Environmental
Regulations
General. The Companys exploration,
drilling and production activities from wells and natural gas
facilities, including the operation and construction of
pipelines, plants and other facilities for transporting,
processing, treating or storing oil, natural gas and other
products are subject to stringent federal, state and local laws
and regulations relating to 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 them will not have a material effect upon
the Companys 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 or on or under locations
where such wastes have been taken for disposal. In addition,
many of these properties are or have been operated by third
parties over whom the Company has no control, nor has ever had
control as to such entities treatment of hydrocarbons or
other wastes or the manner in which such substances may have
been disposed of or released. State and federal laws applicable
to oil and natural gas wastes and properties have gradually
become stricter over time. Under current and evolving law,
including proposed amendments to the federal Safe Drinking Water
Act (SDWA) related to hydraulic fracturing
operations, it is possible the Company could be required to
remediate property, including ground water, containing or
impacted by operations by the Company or by such third party
operators, or 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) under the
federal Resource Conservation and Recovery Act
(RCRA) and some 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 are considering
adopting stricter disposal standards for non-hazardous wastes.
Furthermore, certain wastes generated by the Companys oil
and natural gas operations that are currently exempt from
treatment as Hazardous Wastes may in the future be designated as
Hazardous Wastes under the RCRA or other applicable statutes,
and therefore be subject to more rigorous and costly operating
and disposal requirements.
Superfund. Under 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 releases and
threats of releases to protect the public health or the
environment and to seek
14
to recover from the PRP the costs of such action. Although
CERCLA generally exempts petroleum from the
definition of Hazardous Substance, in the course of its
operations, the Company has generated and will generate wastes
that fall within CERCLAs definition of Hazardous
Substances. The Company may also be an owner or operator of
facilities on which Hazardous Substances have been released. The
Company may be responsible under CERCLA for all or part of the
costs to clean up facilities at which such substances have been
released and for natural resource damages, 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 PRPs related
to their ownership or operation of such property.
National Environmental Policy Act. 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 environmental impact statement (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 on the
Companys activities, including but not limited to the
restricting or prohibiting of drilling.
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. OPA assigns
liability, which generally is joint and several, without regard
to fault, to each liable party for oil removal costs and for 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, the Company could be liable for costs and damages.
Air Emissions. The Companys operations
are subject to local, state and federal regulations for the
control of emissions from sources of air pollution. Federal and
state laws 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 agencies can bring actions
for failure to comply with air pollution regulations or permits
and generally enforce compliance through administrative, civil
or criminal enforcement actions, which may result in fines,
injunctive relief and imprisonment.
Clean Water Act. The Clean Water Act
(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 of 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 and other oil and natural gas leases that have species,
such as raptors, that are listed and species, such as sage
grouse, that 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
15
habitat designation or the mere presence of threatened or
endangered species 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 the 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. Laws and
regulations relating to climate change and greenhouse gases
(GHGs), including methane and carbon dioxide, may be
adopted and could cause the Company to incur material expenses
in complying with them. In June 2010, EPA published its GHG
tailoring rule phasing in federal prevention of significant
deterioration (PDS) permit requirements for new sources and
modifications, and Title V operating permits for all
sources, that have the potential to emit specific quantities of
GHGs. These permitting provisions, when they become applicable
to our operations, could require controls or other measures to
reduce GHG emissions from new or modified sources, and the
Company could incur additional costs to satisfy those
requirements. In November 2010, EPA published a rule
establishing GHG reporting requirements for sources in the
petroleum and natural gas industry, requiring those sources to
monitor, maintain records on, and annually report their GHG
emissions, with the first annual report, for 2010, being due in
March 2011. Although the rule does not limit the amount of GHGs
that can be emitted, it could require us to incur significant
costs to monitor, keep records of, and report GHG emissions
associated with our operations.
In addition to possible federal regulation, a number of states,
individually and regionally, also are considering or have
implemented GHG regulatory programs. These or other 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 the Company
incurring material expenses to comply, e.g., by being required
to purchase or to surrender allowances for GHGs resulting from
its operations. These regulatory initiatives also could
adversely affect the marketability of the oil and natural gas
the Company produces. The Company is not now a covered
entity in respect to climate change legislation or
regulations.
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.
Employees
As of December 31, 2010, the Company had 108 full-time
employees, including officers.
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, 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
16
not prove correct over time. Predictions of future production
levels, prices and future operating costs 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.
The present value, discounted at 10%, of the pre-tax future net
cash flows attributable to our net proved reserves included in
this report should not be considered as the market value of the
reserves attributable to our properties. In accordance with SEC
requirements, we base the present value, discounted at 10%, of
the pre-tax future net cash flows attributable to our net proved
reserves on the average oil and natural gas prices during the
12-month
period before the ending date of the period covered by this
report determined as an unweighted, arithmetic average of the
first-day-of
the-month price for each month within such period, adjusted for
quality and transportation. The costs to produce the reserves
remain constant at the costs prevailing on the date of the
estimate. Actual current and future prices and costs may be
materially higher or lower. In addition, the 10% discount
factor, which the SEC requires us to use in calculating our
discounted future net revenues for reporting purposes, may not
be the most appropriate discount factor based on our cost of
capital from time to time
and/or the
risks associated with our business.
Competitive
industry conditions may negatively affect our ability to conduct
operations.
We compete with numerous other companies in virtually all facets
of our business. Our 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 of the Company permit. We also compete for the
materials, equipment and services that are necessary for the
exploration, development and operation of our properties. Our
ability to increase reserves in the future will be dependent on
our ability to select and acquire suitable prospects for future
exploration and development.
Factors that affect our ability to compete in the marketplace
include:
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our access to the capital necessary to drill wells and acquire
properties;
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our ability to acquire and analyze seismic, geological and other
information relating to a property;
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our ability to retain the personnel necessary to properly
evaluate seismic and other information relating to a property;
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our ability to procure materials, equipment and services
required to explore, develop and operate our properties; and
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our ability to access pipelines, and the locations of facilities
used to produce and transport oil and natural gas production.
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Factors
beyond our control affect our ability to effectively market
production and may ultimately affect our financial
results.
The ability to market oil and natural gas depends on numerous
factors beyond our control. These factors include:
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the extent of domestic production and imports of oil and natural
gas;
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the availability of pipeline capacity, including facilities
owned and operated by third parties;
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the proximity of natural gas production to those natural gas
pipelines;
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the effects of inclement weather;
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the demand for oil and natural gas by utilities and other end
users;
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the availability of alternative fuel sources;
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17
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state and federal regulations of oil and natural gas marketing
and transportation; and
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federal regulation of natural gas sold or transported in
interstate commerce.
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Because of these factors, we may be unable to market all of our
oil and natural gas that we produce. In addition, we may be
unable to obtain favorable prices for the oil and natural gas we
produce.
Our
derivative transactions may limit our gains and expose us to
other risks.
We enter into transactions with derivative instruments from time
to time to manage our exposure to commodity price risks. These
transactions limit our potential gains if commodity prices rise
above the levels established by our derivative instruments.
These transactions may also expose us to other risks of
financial losses, for example, if our production is less than we
anticipated at the time we entered into a derivative instrument
or if a counterparty to our derivative instruments fails to
perform the contracts.
The
adoption of derivatives legislation and regulations related to
derivative contracts could have an adverse impact on our ability
to hedge risks associated with our business.
During 2010, the President signed into law the Dodd
Frank Wall Street Reform and Consumer Protection Act (the
Act). Among other things, the Act requires the
Commodity Futures Trading Commission and the SEC to enact
regulations affecting derivative contracts, including the
derivative contracts we use to hedge our exposure to price
volatility. We cannot predict the content of these regulations
or the effect that these regulations will have on our hedging
activities. Of particular concern, the Act does not explicitly
exempt end users (such as us) from the requirements to post
margin in connection with hedging activities. If the regulations
ultimately adopted require that we post margin for our hedging
activities or impose other requirements that are more burdensome
than current regulations, our hedging would become more
expensive and we may decide to alter our hedging strategy.
A
decrease in oil and natural gas prices may adversely affect our
results of operations and financial condition.
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, which include, but are
not limited to: relatively minor changes in the supply of and
demand for oil and natural gas; market uncertainty; 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; the availability of alternate fuel sources; and
transportation interruption. Any substantial and extended
decline in the price of oil or natural gas could have an adverse
effect on the carrying value of our proved reserves, borrowing
capacity, our ability to obtain additional capital, and the
Companys revenues, profitability and cash flows from
operations.
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
substantial portion of our reserves and production is natural
gas. Prices for natural gas have been lower in recent years than
at various times in the past and may remain lower in the future.
Sustained low prices for natural gas may adversely effect our
operational and financial condition.
Natural gas prices have been lower in recent years than at
various times in the past. These lower prices may be the result
of increased supply resulting from among other things, increased
drilling in unconventional reservoirs
and/or lower
demand resulting from reduced economic activity associated with
the recent recession. Natural gas prices may remain at current
levels, or fall to lower levels, in the future. Approximately
96% of our estimated net proved reserves is natural gas, and 96%
of our production in 2010 was natural gas. Although we expect
operations
18
on properties we currently own to be profitable at natural gas
prices in effect during the past year, a period of sustained low
natural gas prices could have an adverse effect on our results
of operation and financial condition.
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
relating to environmental protection. These laws and regulations
may:
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require that we acquire permits before developing our properties;
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restrict the substances that can be released into the
environment in connection with drilling and production
activities;
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limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas; and
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require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells.
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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 accidental environmental damages. Accordingly, we
may be subject to liability in excess of our insurance coverage
or may be required to cease production from properties in the
event of environmental damages.
A significant percentage of our operations are conducted on
federal and state lands. These operations are subject to a wide
variety of regulations as well as other permits and
authorizations which must be obtained from and issued by state
and federal agencies. To conduct these operations, we may be
required to file applications for permits, seek agency
authorizations and comply with various other statutory and
regulatory requirements. Complying with any of these
requirements may adversely affect our ability to complete our
drilling programs at the costs and in the time periods
anticipated.
Climate
change legislation or regulations restricting emissions of
greenhouse gases could result in increased operating
costs and reduced demand for the oil and gas we
produce.
On December 15, 2009, the EPA officially published its
findings that emissions of carbon dioxide, methane and other
gases which the EPA refers to as greenhouse gases
(GHGs) create risks to public health and the
environment because emissions of such gases are, according to
the EPA, contributing to warming of the earths atmosphere
and other climatic changes. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of
GHGs under existing provisions of the federal Clean Air Act.
Accordingly, the EPA has proposed two sets of regulations that
would require a reduction in emissions of GHGs from motor
vehicles and could trigger permit review for GHG emissions from
certain stationary sources.
In addition, on October 30, 2009, the EPA published a final
rule requiring the reporting of GHG emissions from specified
large GHG emission sources in the United States beginning in
2011 for emissions occurring in 2010. On November 30, 2010,
the EPA published its amendments to the GHG reporting rule to
include onshore and offshore oil and natural gas production
facilities and onshore oil and natural gas processing,
transmission, storage and distribution facilities, which may
include facilities we operate. Reporting of GHG emissions from
such facilities will be required on an annual basis beginning in
2012 for emissions occurring in 2011. We will have to incur
costs associated with this reporting obligation.
In addition, the United States Congress recently considered
legislation to reduce emissions of GHGs and almost one-half of
the states have already taken legal measures to reduce GHG
emission levels, often involving the planned development of GHG
emission inventories
and/or
regional cap and trade programs. Most of these cap and trade
programs require major sources of emissions or major producers
of fuels to acquire and surrender emission allowances. The
number of allowances available for purchase is reduced each year
in an effort to reduce overall GHG emissions. The cost of these
allowances could escalate significantly over time. The adoption
and
19
implementation of any legislation or regulatory programs
imposing reporting obligations on, or limiting emissions of GHGs
from, our equipment and operations could require us to incur
costs to reduce emissions of GHGs associated with our operations
or could adversely affect demand for the oil and natural gas
that we produce.
Potential
physical effects of climate change could adversely affect our
operations and cause us to incur significant costs in preparing
for or responding to those effects.
In an interpretative guidance on climate change disclosures, the
SEC indicates that climate change could have an effect on the
severity of weather (including hurricanes and floods), sea
levels, the arability of farmland, and water availability and
quality. If such effects were to occur, our exploration and
production operations have the potential to be adversely
affected. Potential adverse effects could include disruption of
our production activities, including, for example, damages to
our facilities from powerful winds or increases in our costs of
operation or reductions in the efficiency of our operations, as
well as potentially increased costs for insurance coverages in
the aftermath of such effects. Significant physical effects of
climate change could also have an indirect effect on our
financing and operations by disrupting the transportation or
process related services provided by midstream companies,
service companies or suppliers with whom we have a business
relationship. We may not be able to recover through insurance
some or any of the damages, losses or costs that may result from
potential physical effects of climate change.
Federal
legislation and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
Hydraulic fracturing is used to stimulate production of
hydrocarbons, particularly natural gas, from tight formations.
The process involves the injection of water, sand and chemicals
under pressure into formations to fracture the surrounding rock
and stimulate production. The process is typically regulated by
state oil and gas commissions but is not subject to regulation
at the federal level. The EPA has commenced a study of the
potential environmental impacts of hydraulic fracturing
activities, with results of the study anticipated to be
available by late 2012, and a committee of the U.S. House
of Representatives is also conducting an investigation of
hydraulic fracturing practices. Legislation has been introduced
before Congress to provide for federal regulation of hydraulic
fracturing and to require disclosure of the chemicals used in
the fracturing process. In addition, some states have adopted,
and other states are considering adopting, regulations that
could restrict hydraulic fracturing in certain circumstances.
Pennsylvania has adopted a variety of regulations limiting how
and where fracturing can be performed. Wyoming has adopted
regulations requiring us to provide detailed information about
wells we hydraulically fracture in that state. Any other new
laws or regulations that significantly restrict hydraulic
fracturing could make it more difficult or costly for us to
perform hydraulic fracturing activities and thereby affect our
determination of whether a well is commercially viable. In
addition, if hydraulic fracturing is regulated at the federal
level, our fracturing activities could become subject to
additional permit requirements or operational restrictions and
also to associated permitting delays and potential increases in
costs. We have conducted hydraulic fracturing operations on most
of our existing wells, and we anticipate conducting hydraulic
fracturing operations on substantially all of our future wells.
As a result, restrictions on hydraulic fracturing could reduce
the amount of oil and natural gas that we are ultimately able to
produce in commercial quantities.
We may
not be able to obtain funding on acceptable terms or at
all.
Global financial markets and economic conditions have been
disrupted and volatile due to a variety of factors. As a result,
the cost of raising money in the debt and equity capital markets
and the availability of funds from those markets is
unpredictable. Although we successfully raised money during
2010, we may not be successful in the future. 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 and 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.
20
We may
not be able to replace our reserves or generate cash flows if we
are unable to raise capital. We will be required to make
substantial capital expenditures to develop our existing
reserves and to discover new oil and gas reserves.
Our ability to continue exploration and development of our
properties and to replace reserves may be dependent upon our
ability to continue to raise significant additional financing,
including debt financing or obtain other potential arrangements
with industry partners in lieu of raising financing. Any
arrangements that may be entered into could be expensive to us.
There can be no assurance that we will be able to raise
additional capital in light of factors such as the market demand
for our securities, the state of financial markets for
independent oil and gas companies (including the markets for
debt), oil and natural gas prices and general market conditions.
See Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources for a discussion of our capital budget.
We expect to continue using our bank credit facility to borrow
funds to supplement our available cash flow. The 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 Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
Our
operations may be interrupted by severe weather or drilling
restrictions.
Our operations are conducted primarily in the Rocky Mountain
region of the United States and in the north-central
Pennsylvania area of the Appalachian Basin. The weather in these
areas 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
operations are subject to disruption from winter storms and
severe cold, which can limit operations involving fluids and
impair access to our facilities.
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
21
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 and possible liabilities. If oil or
natural gas is encountered, there can be no assurance that it
can be produced in quantities sufficient to justify the cost of
continuing such operations or that it can be marketed
satisfactorily.
Our
decision to drill a prospect is subject to a number of factors
which may alter our drilling schedule or our plans to drill at
all.
A prospect is an area in 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 our prospects depends on many factors, including but not
limited to: 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; the availability and cost of
capital; changes in the estimates of costs to drill or complete
wells; decisions of our joint working interest owners; and
regulatory and permitting requirements. It is possible that
these factors and others 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 write
down 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. Discounted future net
revenues are estimated using oil and natural gas spot prices
based on the average price during the preceding
12-month
period determined as an unweighted, arithmetic average of the
first-day-of-the-month
price for each month within such period, except for changes
which are fixed and determinable by existing contracts. The net
book value is compared to the ceiling on a quarterly basis. The
excess, if any, of the net book value above the ceiling is
required to be written off as an expense. Under SEC full cost
accounting rules, any write-off recorded may not be reversed
even if higher oil and natural gas prices increase the ceiling
applicable to future periods. Future price decreases could
result in reductions in the carrying value of such assets and an
equivalent charge to earnings.
We
have limited control over activities conducted on properties we
do not operate.
We own interests in properties that are operated by third
parties. The success and timing of drilling and other
development activities on our non-operated properties depend on
a number of factors that are beyond our control. Because we have
only a limited ability to influence and control the operations
of our non-operated properties, we can give no assurances that
we will realize our targeted returns with respect to those
properties.
We may
fail to fully identify problems with any properties we
acquire.
We acquired a portion of our acreage position in Pennsylvania
through property acquisitions and acreage trades, and we may
acquire additional acreage in Pennsylvania or other regions in
the future. Although we conduct a review of properties we
acquire which we believe is consistent with industry practices,
we can give no assurance that we have identified or will
identify all existing or potential problems associated with such
properties or that we will be able to mitigate any problems we
do identify.
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. Except for
statements of historical facts, all statements included in this
document, including those statements preceded by, followed by or
that otherwise include the words
22
believe, expects,
anticipates, intends,
estimates, projects, target,
goal, plans, objective,
should, or similar expressions or variations on such
expressions are forward-looking statements. The Company can give
no assurances that the assumptions upon which such
forward-looking statements are based will prove to be correct.
Forward-looking statements include statements regarding:
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our oil and natural gas reserve quantities, and the discounted
present value of those reserves;
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the amount and nature of our capital expenditures;
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drilling of wells;
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the timing and amount of future production and operating costs;
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business strategies and plans of management; and
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prospect development and property acquisitions.
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Some of the risks which could affect our future results and
could cause results to differ materially from those expressed in
our forward-looking statements include:
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any future global economic downturn;
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general economic conditions, including the availability of
credit and access to existing lines of credit;
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the volatility of oil and natural gas prices;
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the uncertainty of estimates of oil and natural gas reserves;
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the impact of competition;
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the availability and cost of seismic, drilling and other
equipment;
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operating hazards inherent in the exploration for and production
of oil and natural gas;
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difficulties encountered during the exploration for and
production of oil and natural gas;
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difficulties encountered in delivering oil and natural gas to
commercial markets;
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changes in customer demand and producers supply;
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the uncertainty of our ability to attract capital and obtain
financing on favorable terms;
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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;
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actions of operators of our oil and natural gas
properties; and
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weather conditions.
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The information contained in this report, including the
information set forth under the heading Risk
Factors, identifies additional factors that could affect
our operating results and performance. We urge you to carefully
consider these factors and the other cautionary statements in
this report. Our forward-looking statements speak only as of the
date made, and we have no obligation to update these
forward-looking statements.
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Item 1B.
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Unresolved
Staff Comments.
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The Company has one unresolved Staff comment related to its
Form 10-K
for its fiscal year ended December 31, 2009.
Item 1208(b) of
Regulation S-K
requires disclosure if material, of the minimum remaining
terms of leases and concessions. In its 2009
Form 10-K,
the Company did not disclose the minimum remaining terms of its
leases. The Company believes the minimum remaining terms of its
leases that were not held by production at December 31,
2009 is not material because at that time it had no proved
reserves and zero value attributable to such leases. In the
current report on
Form 10-K,
the Company discusses the minimum remaining terms of its leases
in Item 2. Properties, Oil and Gas Acreage.
23
Location
and Characteristics
The Company owns oil and natural gas leases in both Wyoming and
Pennsylvania. The leases in Wyoming are primarily federal leases
with 10-year
lease terms until establishment of production. Production
extends the lease terms until cessation of that production. In
Pennsylvania, the leases are from private individuals and
companies, as well as from the Commonwealth of Pennsylvania. The
leases in Pennsylvania are mostly undeveloped at this time and
typically have primary lease terms of five years until
establishment of production.
Exploration and development wells are identified with new
criteria as of December 31, 2009. In SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting (SEC Release
No. 33-8995),
additional clarity is provided regarding the certainty of
reserve forecasts for individual wells and the characterization
of this certainty within the modernized reserve reporting
framework. As a result, this clarification provides for the
Company to modify its criteria for reserve reporting and
classification. Accordingly, many wells that were previously
characterized as exploratory simply due to prior classification
as proved undeveloped reserves are more accurately characterized
as developmental in nature due to the clarification of
reasonable certainty under the new criteria.
Green
River Basin, Wyoming
As of December 31, 2010, the Company owned developed oil
and natural gas leases totaling approximately 94,000 gross
(54,000 net) acres in the southwest Wyomings Green River
Basin. Most of this acreage covers Pinedale and Jonah Fields in
Sublette County, with some smaller undeveloped acreage blocks
located north and west of Pinedale. Of the total acreage
position in Wyoming, approximately 22,000 gross (10,000
net) acres were developed, and 72,000 gross (44,000 net)
acres were undeveloped. The developed portion represents 38% of
the Companys total developed net acreage while the
undeveloped portion represents approximately 15% of the
Companys total undeveloped net acreage.
Lease maintenance costs in Wyoming were approximately
$0.5 million for the year ended December 31, 2010. The
Company currently owns 39 leases totaling 76,000 gross
(37,000 net) acres currently held by production and activities
(HBP) in Wyoming. The HBP acreage includes all of
the Companys leases within the productive area of the
Pinedale and Jonah fields.
Development Wells. During 2010, the Company
participated in the drilling of 168 gross (90.62 net)
productive development wells on the Green River Basin
properties. At year end 2010, there were 36 gross (17.78
net) additional development wells that commenced during the year
and were either still drilling or had operations suspended at a
depth short of total depth.
Exploratory Wells. During 2010, the Company
participated in the drilling of a total of 13 gross (3.91
net) productive exploratory wells on the Green River Basin
properties. At December 31, 2010, there were no 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.
Pennsylvania
As of December 31, 2010, the Company owned oil and gas
leases covering 495,000 gross (260,000) acres in the
Pennsylvania portion of the Appalachian Basin. This acreage is
located in the heart of northeast Pennsylvanias Marcellus
Shale Gas Trend, principally in Potter, Tioga, Lycoming, Centre
and Clinton counties. Of the total acreage position as of
December 31, 2010, approximately 28,000 gross (16,000
net) acres were developed, and 467,000 gross (244,000 net)
acres were undeveloped. The developed portion represents 62% of
the Companys total developed net acreage position while
the undeveloped portion represents 85% of the Companys
total undeveloped net acreage position. The Company operates
approximately 87,000 gross (50,000 net) acres of the total
position.
Lease maintenance costs in Pennsylvania were approximately
$21.4 million for the year ended December 31, 2010.
The Company owns approximately 240,000 gross (129,000 net)
acres currently held by production or activities in Pennsylvania.
24
Development Wells. During 2010, the Company
participated in the drilling of 30 gross (19.00 net)
productive development wells in Pennsylvania, all of which were
horizontal wells. At year end 2010, there was 1 gross (0.5
net) additional development well that commenced during the year
and was either still drilling or had operations suspended at a
depth short of total depth.
Exploratory Wells. During the year ended
December 31, 2010, the Company participated in the drilling
of a total of 141 gross (80.00 net) wells on the
Pennsylvania properties. Of that total, 80 gross (49.0 net)
were horizontal wells and 61 gross (31.0 net) were vertical
wells. At December 31, 2010, there were 10 gross (5.02
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.
Seismic Activity. The Company acquired
76 square miles of 3D seismic data on its properties during
2010. The survey covers lands located in Tioga County and brings
the Companys total 3D seismic coverage Pennsylvania to
315 square miles. Of this, 285 square miles of data is
owned with other parties, and 30 square miles is owned
solely by the Company.
Oil and
Gas Reserves
The following table sets forth the Companys quantities of
proved reserves for the years ended December 31, 2010,
2009, and 2008 as estimated by independent petroleum engineers
Netherland, Sewell & Associates, Inc. The table
summarizes the Companys 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, 2010, 2009 and 2008. In accordance with
Ultras three-year planning and budgeting cycle, proved
undeveloped reserves included in this table include only
economic locations that are forecast to be drilled before
January 1, 2014. As of December 31, 2010, proved
undeveloped reserves represent 60.3% of the Companys total
proved reserves. We have substantially more locations than we
can drill in the next three years based on our planning and
budgeting process. We continually attempt to identify and
schedule for drilling during the next three years the proved
undeveloped locations that we believe will yield the highest
return on capital invested. Additional information, changes in
economics and acquisitions may cause us to alter the drilling
locations included in our proved undeveloped reserves from time
to time in order to permit us to develop what we identify as the
highest return opportunities within the capital budget and other
resources available to us.
Our policies and practices regarding internal controls over the
recording of reserves is structured to objectively and
accurately estimate our oil and gas reserves quantities and
present values in compliance with the SECs regulations and
GAAP. The Director Reservoir Engineering &
Planning is primarily responsible for overseeing the preparation
of the Companys reserve estimates by our independent
engineers, Netherland, Sewell & Associates, Inc. The
Director has a Bachelor and Master of Science degree in
Petroleum Engineering and is a licensed Professional Engineer
with over 15 years of experience. The Companys
internal controls over reserve estimates include reconciliation
and review controls, including an independent internal review of
assumptions used in the estimation.
All of the information regarding reserves in this annual report
is derived from the report of Netherland, Sewell &
Associates, Inc. The report of Netherland, Sewell &
Associates, Inc. is included as an Exhibit to this annual
report. The principal engineer at Netherland, Sewell &
Associates, Inc. responsible for preparing our reserve estimates
has a Bachelor of Science degree in Mechanical Engineering and
is a licensed Professional Engineer with over 25 years of
experience, including significant experience throughout the
Rocky Mountain basins.
In estimating proved reserves and future revenue as of
December 31, 2010, the Companys independent reserve
engineer, Netherland, Sewell & Associates, Inc., used
technical and economic data including, but not limited to, well
logs, geologic maps, seismic data, well test data, production
data, historical price and cost information and property
ownership interests. The reserves were estimated using
deterministic methods; these estimates were prepared in
accordance with generally accepted petroleum engineering and
evaluation principles. Standard engineering and geoscience
methods, such as performance analysis, volumetric analysis and
analogy, that were considered to be appropriate and necessary to
establish reserve quantities and reserve categorization that
conform to SEC definitions and guidelines, were also used. In
evaluating the information at their disposal, Netherland,
Sewell & Associates, Inc. excluded from their
consideration all matters as to which the controlling
interpretation may be legal or accounting, rather
25
than engineering and geoscience. As in all aspects of oil and
natural gas evaluation, there are uncertainties inherent in the
interpretation of engineering and geoscience data; therefore,
Netherland, Sewell & Associates, Inc.s
conclusions necessarily represent only informed professional
judgment.
As a result of Ultras drilling activities in 2010,
278.6 Bcfe (12%) of reserves classified as proved
undeveloped at January 1, 2010 were converted into proved
developed reserves. The Company did not have any material
changes to proved undeveloped volumes due to revisions during
the year ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
1,678,697
|
|
|
|
1,541,813
|
|
|
|
1,412,562
|
|
Oil (MBbl)
|
|
|
11,013
|
|
|
|
11,627
|
|
|
|
11,462
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
2,521,458
|
|
|
|
2,194,788
|
|
|
|
1,943,225
|
|
Oil (MBbl)
|
|
|
20,671
|
|
|
|
17,558
|
|
|
|
15,546
|
|
Total Proved Reserves (MMcfe)(1)
|
|
|
4,390,259
|
|
|
|
3,911,711
|
|
|
|
3,517,830
|
|
Estimated future net cash flows, before income tax
|
|
$
|
10,879,719
|
|
|
$
|
6,704,601
|
|
|
$
|
10,040,263
|
|
Standardized measure of discounted future net cash
|
|
|
|
|
|
|
|
|
|
|
|
|
flows, before income taxes(2)
|
|
$
|
4,993,576
|
|
|
$
|
2,887,125
|
|
|
$
|
4,443,867
|
|
Future income tax
|
|
$
|
1,468,008
|
|
|
$
|
860,425
|
|
|
$
|
1,426,181
|
|
Standardized measure of discounted future net cash
|
|
|
|
|
|
|
|
|
|
|
|
|
flows, after income tax
|
|
$
|
3,525,568
|
|
|
$
|
2,026,700
|
|
|
$
|
3,017,686
|
|
Calculated average price(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas ($/Mcf)
|
|
$
|
4.05
|
|
|
$
|
3.04
|
|
|
$
|
4.71
|
|
Oil ($/Bbl)
|
|
$
|
68.93
|
|
|
$
|
52.18
|
|
|
$
|
30.10
|
|
|
|
|
(1) |
|
Oil and condensate are converted to natural gas at the ratio of
one barrel of oil or condensate to six Mcf of natural gas. This
conversion ratio, which is typically used in the oil and gas
industry, represents the approximate energy equivalent of a
barrel of oil or condensate to an Mcf of natural gas. The sales
price of one barrel of oil or condensate has been much higher
than the sales price of six Mcf of natural gas over the last
several years, so a six to one conversion ratio does not
represent the economic equivalency of six Mcf of natural gas to
one barrel of oil or condensate. |
|
(2) |
|
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-Generally Accepted Accounting
Principle 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 Generally Accepted
Accounting Principle (GAAP) financial measure
(standardized measure of discounted future net cash flows, after
income taxes). Management believes that the presentation of the
standardized measure of future net cash flows before income
taxes provides useful information to investors because it is
widely used by professional analysts and sophisticated investors
in evaluating oil and gas companies. Because many factors that
are unique to each individual company may impact the amount of
future income taxes to be paid, the use of the pre-tax measure
provides greater comparability when evaluating companies. It is
relevant and useful to investors for evaluating the relative
monetary significance of the Companys oil and natural gas
properties. Further, investors may utilize the measure as a
basis for comparison of the relative size and value of the
Companys reserves to other companies. The standardized
measure of discounted future net cash flows, before income
taxes, is not a measure of financial or operating performance
under GAAP, nor is it intended to represent the current market
value of the estimated oil and natural gas reserves owned by the
Company. Standardized measure of discounted future net cash
flows, before income taxes, should not be considered in
isolation or as a substitute for the standardized measure of
discounted future net cash flows as defined under GAAP. |
|
(3) |
|
Reserves estimated by our independent engineers at
December 31, 2010 and 2009, reflect oil and natural gas
spot prices based on the average prices during the
12-month
period before the ending date of the period covered |
26
|
|
|
|
|
by this report determined as an unweighted, arithmetic average
of the
first-day-of-the-month
price for each month within such period. |
|
|
|
Reserves estimated by our independent engineers at
December 31, 2008, reflect oil and natural gas spot prices
on the last day of the year. |
Since January 1, 2010, 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.
Production
Volumes, Average Sales Prices and Average Production
Costs
The following table sets forth certain information regarding the
production volumes and average sales prices received for and
average production costs associated with the Companys sale
of oil and natural gas for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per unit data)
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
205,613
|
|
|
|
172,189
|
|
|
|
138,564
|
|
Oil (Bbl)
|
|
|
1,334
|
|
|
|
1,320
|
|
|
|
1,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfe)
|
|
|
213,619
|
|
|
|
180,110
|
|
|
|
145,293
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
886,396
|
|
|
$
|
601,023
|
|
|
$
|
986,374
|
|
Oil sales
|
|
|
92,990
|
|
|
|
65,739
|
|
|
|
98,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
979,386
|
|
|
$
|
666,762
|
|
|
$
|
1,084,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs(a)
|
|
$
|
45,938
|
|
|
$
|
40,679
|
|
|
$
|
36,997
|
|
Severance/production taxes
|
|
|
95,914
|
|
|
|
66,970
|
|
|
|
119,502
|
|
Gathering
|
|
|
50,126
|
|
|
|
45,155
|
|
|
|
37,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total lease operating expenses
|
|
$
|
191,978
|
|
|
$
|
152,804
|
|
|
$
|
194,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf, including realized gains (losses) on
commodity derivatives)(b)
|
|
$
|
4.88
|
|
|
$
|
4.88
|
|
|
$
|
7.26
|
|
Natural gas ($/Mcf, excluding realized gains (losses) on
commodity derivatives)(b)
|
|
$
|
4.31
|
|
|
$
|
3.49
|
|
|
$
|
7.11
|
|
Natural gas ($/Mcf, excluding financial commodity derivatives)(c)
|
|
$
|
4.31
|
|
|
$
|
3.49
|
|
|
$
|
7.11
|
|
Oil ($/Bbl)
|
|
$
|
69.69
|
|
|
$
|
49.80
|
|
|
$
|
87.40
|
|
Operating costs per Mcfe Total Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
0.22
|
|
|
$
|
0.23
|
|
|
$
|
0.25
|
|
Severance/production taxes
|
|
$
|
0.45
|
|
|
$
|
0.37
|
|
|
$
|
0.82
|
|
Gathering
|
|
$
|
0.23
|
|
|
$
|
0.25
|
|
|
$
|
0.26
|
|
Transportation charges
|
|
$
|
0.30
|
|
|
$
|
0.32
|
|
|
$
|
0.32
|
|
DD&A
|
|
$
|
1.13
|
|
|
$
|
1.12
|
|
|
$
|
1.27
|
|
General & administrative
|
|
$
|
0.11
|
|
|
$
|
0.11
|
|
|
$
|
0.12
|
|
Interest
|
|
$
|
0.23
|
|
|
$
|
0.21
|
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per Mcfe
|
|
$
|
2.68
|
|
|
$
|
2.61
|
|
|
$
|
3.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Production costs include lifting costs and remedial workover
expenses. |
|
(b) |
|
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 8 to the Companys Consolidated Financial
Statements included in this report). 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. |
27
|
|
|
(c) |
|
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provided operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with settlements for production months through December
2010. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas
index prices as published by independent third parties or
natural gas futures settlement prices as traded on the New York
Mercantile Exchange (NYMEX). |
|
|
|
Prior to the first quarter of 2009, the Company sold a portion
of its production pursuant to fixed price forward natural gas
sales contracts. During 2008, the Company sold 32.7 MMMBtu
(23%) pursuant to these fixed price forward natural gas sales
contracts. The average price it received for production sold
pursuant to term fixed price contracts was $6.84 per MMBtu in
2008. The average spot price (as measured by the Inside FERC
First of Month Index for Northwest Pipeline Rocky
Mountains) was $6.25 per MMBtu in 2008. If the Company had sold
the production that was sold under the fixed price contracts at
spot market prices during these periods, it may have received
more or less than these prices, because the amount of production
sold could have influenced the spot market prices in the areas
in which the Company produces and because the Company is able to
select among several market indices when selling its production. |
Delivery
Commitments
With respect to the Companys natural gas production, from
time to time the Company enters into transactions to deliver
specified quantities of gas to its customers. As of
February 16, 2011, the Company had long-term natural gas
delivery commitments of 11.6 MMMBtu in 2011,
31.7 MMMBtu in 2012 and 2.7 MMMBtu in 2013 under
existing agreements. None of these commitments require the
Company to deliver gas produced specifically from any of the
Companys properties, and all of these commitments are
priced on a floating basis with reference to an index price.
These amounts are well below the Companys forecasted 2011
and anticipated 2012 and 2013 production from its available
reserves. In addition, none of the Companys reserves are
subject to any priorities or curtailments that may affect
quantities delivered to its customers, any priority allocations
or price limitations imposed by federal or state regulatory
agencies or any other factors beyond the Companys control
that may affect its ability to meet its contractual obligations
other than those discussed in Item 1A. Risk
Factors. The Company believes that its production and
reserves are adequate to meet its delivery commitments. If for
some reason the Companys production is not sufficient to
satisfy its delivery commitments, the Company expects to be able
to purchase natural gas production in the market to satisfy its
commitments.
With respect to the Companys oil production, the Company
does not have any arrangements that commit the Company to
deliver a fixed or determinable quantity of oil in the near
future.
Productive
Wells
As of December 31, 2010 the Companys total gross and
net wells were as follows:
|
|
|
|
|
|
|
|
|
Productive Wells*
|
|
Gross Wells
|
|
Net Wells
|
|
Natural Gas and Condensate
|
|
|
1,697.0
|
|
|
|
836.0
|
|
|
|
|
* |
|
Productive wells are producing wells, shut-in wells the Company
deems capable of production, wells that are 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
The primary terms of the Companys oil and gas leases
expire at various dates. Much of the Companys undeveloped
acreage is held by production, which means that the Company will
maintain its rights in these leases as long as oil or natural
gas is produced from the acreage by it or by other parties
holding interests in producing wells
28
on those leases. In some cases, if production from a lease
ceases, the lease will expire, and in some cases, if production
from a lease ceases, the Company may maintain the lease by
additional operations on the acreage.
The Company does not believe the remaining terms of its leases
is material. At December 31, 2010 the Company had
38,000 net acres of leases in Pennsylvania that expire in
2011, and it expects to maintain over 90% of those leases by
production, operations, extensions or renewals. The Company does
not expect to lose material lease acreage because of failure to
drill due to inadequate capital, equipment or personnel. The
Company has, based on its evaluation of prospective economics,
allowed acreage to expire and it may allow additional acreage to
expire in the future.
As of December 31, 2010 the Company had total gross and net
developed and undeveloped oil and natural gas leasehold acres in
the United States as set forth below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Wyoming
|
|
|
22,000
|
|
|
|
10,000
|
|
|
|
72,000
|
|
|
|
44,000
|
|
Pennsylvania
|
|
|
28,000
|
|
|
|
16,000
|
|
|
|
467,000
|
|
|
|
244,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All States
|
|
|
50,000
|
|
|
|
26,000
|
|
|
|
539,000
|
|
|
|
288,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
Activities
As of December 31, 2009, SEC Release
No. 33-8995
provides additional clarity regarding the criteria for
determining the development status of wells such that
exploration and development wells are identified with new
criteria. The Company implemented the new criteria as of
December 31, 2009, and previous years do not reflect the
updated guidelines.
For each of the three fiscal years ended December 31, 2010,
2009 and 2008 the number of gross and net wells drilled by the
Company was as follows:
Wyoming
Green River Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
168.00
|
|
|
|
90.62
|
|
|
|
155.00
|
|
|
|
76.09
|
|
|
|
120.00
|
|
|
|
61.98
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
168.00
|
|
|
|
90.62
|
|
|
|
155.00
|
|
|
|
76.09
|
|
|
|
120.00
|
|
|
|
61.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At year end, there were 36 gross (17.78 net) additional
development wells that were either drilling or had operations
suspended. This includes wells in both the Pinedale and Jonah
fields.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
13.00
|
|
|
|
3.91
|
|
|
|
8.00
|
|
|
|
2.80
|
|
|
|
108.00
|
|
|
|
59.50
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
13.00
|
|
|
|
3.91
|
|
|
|
8.00
|
|
|
|
2.80
|
|
|
|
108.00
|
|
|
|
59.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At year end, there were no additional exploratory wells that
were either drilling or had operations suspended. This includes
wells in both the Pinedale and Jonah fields.
29
Pennsylvania
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
30.00
|
|
|
|
19.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
30.00
|
|
|
|
19.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At year end, there was 1 gross (0.5 net) additional
development well that was either drilling or had operations
suspended.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
141.00
|
|
|
|
80.00
|
|
|
|
35.00
|
|
|
|
21.00
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
141.00
|
|
|
|
80.00
|
|
|
|
35.00
|
|
|
|
21.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At year end, there were 10 gross (5.02 net) additional
exploratory wells that were either drilling or had operations
suspended.
|
|
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 or predict the ultimate disposition
of these matters, the Company believes that the resolution of
all such pending or threatened litigation is not likely to have
a material adverse effect on the Companys financial
position, or results of operations.
|
|
Item 4.
|
[Removed
and Reserved].
|
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
The Companys common stock trades on the New York Stock
Exchange (NYSE) 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.
The following stock price performance graph is intended to allow
review of stockholder returns, expressed in terms of the
appreciation of the Companys common stock relative to two
broad-based stock performance indices. The information is
included for historical comparative purposes only and should not
be considered indicative of future stock performance. The graph
compares the yearly percentage change in the cumulative total
stockholder return on the Companys common stock with the
cumulative total return of the NYSE Composite Index and of the
Dow Jones U.S. Exploration and Production TSM Index
(formerly Dow Jones Secondary Oils Stock Index) from
December 31, 2005 through December 31, 2010. This
marks a successful transition from the Standard &
Poors Composite 500 Stock Index and takes into
consideration the name change of the Dow Jones Wilshire
Exploration and Production Index.
|
|
|
|
|
|
|
|
|
2010
|
|
High
|
|
Low
|
|
1st quarter
|
|
$
|
53.90
|
|
|
$
|
42.67
|
|
2nd quarter
|
|
$
|
53.85
|
|
|
$
|
40.40
|
|
3rd quarter
|
|
$
|
47.70
|
|
|
$
|
37.10
|
|
4th quarter
|
|
$
|
50.22
|
|
|
$
|
39.14
|
|
30
|
|
|
|
|
|
|
|
|
2009
|
|
High
|
|
Low
|
|
1st quarter
|
|
$
|
42.16
|
|
|
$
|
30.02
|
|
2nd quarter
|
|
$
|
51.88
|
|
|
$
|
34.89
|
|
3rd quarter
|
|
$
|
53.28
|
|
|
$
|
33.75
|
|
4th quarter
|
|
$
|
57.21
|
|
|
$
|
44.63
|
|
As of February 16, 2011, the last reported sales price of
the common stock on the NYSE was $47.53 per share and, there
were approximately 382 holders of record of the common stock.
The graph below matches the cumulative
5-year total
return of holders of Ultra Petroleum Corps common stock
with the cumulative total returns of the NYSE Composite index
and the Dow Jones US Exploration & Production TSM
index. The graph assumes that the value of the investment in the
companys common stock and in each of the indexes
(including reinvestment of dividends) was $100 on 12/31/2005 and
tracks it through
12/31/2010.
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among
Ultra Petroleum Corp, the NYSE Composite Index
and the Dow Jones US Exploration & Production TSM Index
|
|
|
* |
|
$100 invested on 12/31/05 in stock or index, including
reinvestment of dividends.
Fiscal year ending December 31. |
Copyright©
2011 Dow Jones & Co. All rights reserved.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/05
|
|
|
12/06
|
|
|
12/07
|
|
|
12/08
|
|
|
12/09
|
|
|
12/10
|
Ultra Petroleum Corp
|
|
|
|
100.00
|
|
|
|
|
85.56
|
|
|
|
|
128.14
|
|
|
|
|
61.85
|
|
|
|
|
89.35
|
|
|
|
|
85.61
|
|
NYSE Composite
|
|
|
|
100.00
|
|
|
|
|
120.47
|
|
|
|
|
131.15
|
|
|
|
|
79.67
|
|
|
|
|
102.20
|
|
|
|
|
115.87
|
|
Dow Jones US Exploration & Production TSM
|
|
|
|
100.00
|
|
|
|
|
105.08
|
|
|
|
|
147.43
|
|
|
|
|
86.94
|
|
|
|
|
123.04
|
|
|
|
|
145.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The stock price performance included in this graph is not
necessarily indicative of future stock price performance.
31
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.
|
|
Item 6.
|
Selected
Financial Data.
|
The selected consolidated financial information presented below
for the years ended December 31, 2010, 2009, 2008, 2007 and
2006 is derived from the Consolidated Financial Statements of
the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
886,396
|
|
|
$
|
601,023
|
|
|
$
|
986,374
|
|
|
$
|
509,140
|
|
|
$
|
470,324
|
|
Oil sales
|
|
|
92,990
|
|
|
|
65,739
|
|
|
|
98,026
|
|
|
|
57,498
|
|
|
|
38,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
979,386
|
|
|
|
666,762
|
|
|
|
1,084,400
|
|
|
|
566,638
|
|
|
|
508,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses and taxes
|
|
|
191,978
|
|
|
|
152,804
|
|
|
|
194,243
|
|
|
|
115,371
|
|
|
|
92,688
|
|
Transportation charges
|
|
|
64,965
|
|
|
|
58,011
|
|
|
|
46,310
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
241,796
|
|
|
|
201,826
|
|
|
|
184,795
|
|
|
|
135,470
|
|
|
|
79,675
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
11,407
|
|
|
|
8,871
|
|
|
|
11,230
|
|
|
|
7,543
|
|
|
|
12,259
|
|
Stock compensation
|
|
|
12,944
|
|
|
|
10,901
|
|
|
|
5,816
|
|
|
|
5,718
|
|
|
|
2,626
|
|
Interest expense
|
|
|
49,032
|
|
|
|
37,167
|
|
|
|
21,276
|
|
|
|
17,760
|
|
|
|
3,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
572,122
|
|
|
|
1,506,580
|
|
|
|
463,670
|
|
|
|
281,862
|
|
|
|
191,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on commodity derivatives
|
|
|
325,452
|
|
|
|
146,517
|
|
|
|
33,216
|
|
|
|
|
|
|
|
|
|
Litigation expense
|
|
|
(9,902
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense) , net
|
|
|
260
|
|
|
|
(2,888
|
)
|
|
|
833
|
|
|
|
1,087
|
|
|
|
1,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
315,810
|
|
|
|
143,629
|
|
|
|
34,049
|
|
|
|
1,087
|
|
|
|
1,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
723,074
|
|
|
|
(696,189
|
)
|
|
|
654,779
|
|
|
|
285,863
|
|
|
|
319,443
|
|
Income tax provision (benefit)
|
|
|
258,615
|
|
|
|
(245,136
|
)
|
|
|
240,504
|
|
|
|
105,621
|
|
|
|
122,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income from continuing operations
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
|
$
|
180,242
|
|
|
$
|
196,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations (including pre-tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
gain on sale of $98,066 in 2007)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82,794
|
|
|
|
34,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
|
$
|
263,036
|
|
|
$
|
231,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income per common share from continuing operations
|
|
$
|
3.05
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.72
|
|
|
$
|
1.19
|
|
|
$
|
1.28
|
|
Income per common share from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.54
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
3.05
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.72
|
|
|
$
|
1.73
|
|
|
$
|
1.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income per common share from continuing operations
|
|
$
|
3.01
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.65
|
|
|
$
|
1.14
|
|
|
$
|
1.22
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
Income per common share from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.52
|
|
|
$
|
0.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share fully diluted
|
|
$
|
3.01
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.65
|
|
|
$
|
1.66
|
|
|
$
|
1.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
824,728
|
|
|
$
|
592,641
|
|
|
$
|
840,803
|
|
|
$
|
427,949
|
|
|
$
|
437,333
|
|
Investing activities
|
|
$
|
(1,529,099
|
)
|
|
$
|
(820,611
|
)
|
|
$
|
(915,319
|
)
|
|
$
|
(507,070
|
)
|
|
$
|
(453,882
|
)
|
Financing activities
|
|
$
|
760,951
|
|
|
$
|
228,067
|
|
|
$
|
78,041
|
|
|
$
|
75,179
|
|
|
$
|
(12,845
|
)
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
70,834
|
|
|
$
|
14,254
|
|
|
$
|
14,157
|
|
|
$
|
10,632
|
|
|
$
|
14,574
|
|
Working capital (deficit)
|
|
$
|
(56,967
|
)
|
|
$
|
(137,450
|
)
|
|
$
|
(149,355
|
)
|
|
$
|
(67,505
|
)
|
|
$
|
55,036
|
|
Oil and gas properties
|
|
$
|
3,075,670
|
|
|
$
|
1,794,603
|
|
|
$
|
2,350,526
|
|
|
$
|
1,574,529
|
|
|
$
|
1,006,998
|
|
Total assets
|
|
$
|
3,595,615
|
|
|
$
|
2,060,005
|
|
|
$
|
2,558,162
|
|
|
$
|
1,751,582
|
|
|
$
|
1,258,299
|
|
Total long-term debt
|
|
$
|
1,560,000
|
|
|
$
|
795,000
|
|
|
$
|
570,000
|
|
|
$
|
290,000
|
|
|
$
|
165,000
|
|
Other long-term obligations
|
|
$
|
52,575
|
|
|
$
|
35,858
|
|
|
$
|
46,206
|
|
|
$
|
26,672
|
|
|
$
|
25,262
|
|
Deferred income taxes, net
|
|
$
|
420,711
|
|
|
$
|
239,217
|
|
|
$
|
503,597
|
|
|
$
|
341,406
|
|
|
$
|
252,808
|
|
Total shareholders equity
|
|
$
|
1,138,976
|
|
|
$
|
648,197
|
|
|
$
|
1,090,786
|
|
|
$
|
857,546
|
|
|
$
|
631,258
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the consolidated financial statements and related notes of
the Company, which are included in this report in Item 8,
and the information set forth in Risk Factors under
Item 1A. Except as otherwise indicated, all amounts are
expressed in U.S. dollars.
Overview
Ultra Petroleum Corp. is an independent exploration and
production company focused on developing its long-life natural
gas reserves in the Green River Basin of Wyoming the
Pinedale and Jonah Fields and is in the early
exploration and development stages in the Appalachian Basin of
Pennsylvania. The Company operates in one industry segment,
natural gas and oil exploration and development, with one
geographical segment, the United States.
The Company currently conducts operations exclusively in the
United States. Substantially all of its oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented reflect only the Companys proportionate
interest in such activities. Inflation has not had a material
impact on the Companys results of operations and is not
expected to have a material impact on the Companys results
of operations in the future.
The Company currently generates its revenue, earnings and cash
flow primarily from the production and sales of natural gas and
condensate from its property in southwest Wyoming. An increasing
portion of the Companys revenues is associated with gas
sales from wells located in the Appalachian Basin in
Pennsylvania.
The price of natural gas is a critical factor to the
Companys business and the price of natural gas has
historically been volatile. Volatility could be detrimental to
the Companys financial performance. The Company seeks to
limit the impact of this volatility on its results by entering
into swap agreements
and/or fixed
price forward physical delivery contracts for natural gas. The
average price realization for the Companys natural gas
during 2010 was $4.88 per Mcf, including realized gains and
losses on commodity derivatives. During the quarter ended
December 31, 2010, the average price realization for the
Companys natural gas was $4.54 per Mcf, including realized
gains and losses on commodity derivatives. The Companys
average price realization for natural gas,
33
excluding realized gains and losses on commodity derivatives,
was $4.31 per Mcf and $3.83 per Mcf for the year and quarter
ended December 31, 2010, respectively. (See Note 8).
Mission
and Strategy
Ultras mission is to profitably grow an upstream oil and
gas company for the long-term benefit of its shareholders.
Ultras strategy includes building a robust portfolio of
high return investment opportunities, maintaining a disciplined
approach to capital investment, maximizing earnings and cash
flows by controlling costs and maintaining financial flexibility.
High Return Portfolio. Ultra maintains a
portfolio of properties that provide long-term growth through
development in areas that support sustainable, lower-risk,
repeatable, high return drilling projects. The Company
continually evaluates opportunities for the acquisition,
exploration and development of additional oil and natural gas
properties that afford risk-adjusted returns in excess of or
equal to its current set of investment alternatives.
Disciplined Capital Investment. The
Companys business strategy involves the regular review of
its investment opportunities in order to optimize return to its
shareholders. Over the past ten years, Ultra has consistently
delivered meaningful reserve and production growth while
providing significant returns to its shareholders.
Low Cost Producer. Ultra strives to maintain
one of the lowest cost structures in the industry in terms of
both adding and producing oil and natural gas reserves. The
Company continues to focus on improving its drilling and
production results through the use of advanced technologies and
detailed technical analysis of its properties.
Financial Flexibility. Preserving financial
flexibility and a strong balance sheet are also strategic to
Ultras business philosophy. Maintaining financial
discipline enables the Company to capitalize on the flexibility
of its portfolio.
2010
Operating Highlights
The Company has consistently delivered meaningful reserve and
production growth over the past ten years and management
believes it has the ability to continue growing production by
drilling already identified locations on its core properties.
|
|
|
|
|
Achieved production of 213.6 Bcfe, a 19% increase as
compared to 2009;
|
|
|
|
Proved reserves increased 13% to 4.4 Tcfe from
3.9 Tcfe in 2009;
|
|
|
|
Finding and development costs of $1.48 per Mcfe;
|
|
|
|
Reserve replacement ratio of 324%;
|
|
|
|
Reduced average drilling time to 14 days per well in
Wyoming, spud to total depth, a 30% reduction from 2009;
|
|
|
|
Increased drilling efficiencies reducing completed well costs in
Wyoming to $4.7 million per well, a 6% reduction from 2009
levels;
|
|
|
|
95% of wells drilled in Wyoming in less than 20 days;
|
|
|
|
Averaged 13.0 days rig release to rig release per well in
Pennsylvania;
|
|
|
|
Initiated production from 77 gross (51 net) horizontal
wells in Pennsylvania;
|
|
|
|
All in costs of $2.68 per Mcfe and,
|
|
|
|
Return on capital employed of 17% and return on equity of 39%.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
2001
|
|
Production Bcfe
|
|
|
213.6
|
|
|
|
180.1
|
|
|
|
145.3
|
|
|
|
121.3
|
|
|
|
91.6
|
|
|
|
73.8
|
|
|
|
49.5
|
|
|
|
28.9
|
|
|
|
17.4
|
|
|
|
12.2
|
|
34
2010
Financial Highlights
Significant 2010 financial highlights include:
|
|
|
|
|
Generated $824.7 million of cash flow from operating
activities compared with $592.6 million in 2009 due
primarily to increased production volumes during 2010;
|
|
|
|
Completed two Senior Note offerings generating proceeds of
approximately $1.025 billion with a weighted average
interest rate of 5.05% and a weighted average maturity of
10.6 years;
|
|
|
|
As of December 31, 2010, the Company had entered into
commodity derivative contracts for 2011 and 2012 representing
148.2 MMBtu and 51.2 MMBtu at weighted average prices
of $5.37 per MMBtu and $5.00 per MMBtu, respectively,
in order to manage price risk on a portion of its natural gas
production.
|
|
|
|
Subsequent to December 31, 2010, the Company entered into
additional commodity derivative contracts for 2011 and 2012
representing 19.3 MMBtu and 47.6 MMBtu at weighted
average prices of $4.63 per MMBtu and $5.04 per MMBtu,
repsectively.
|
Critical
Accounting Policies
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. 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 related
to 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.
Oil and Gas Reserves. On January 6, 2010,
the FASB issued an Accounting Standards Update (ASU)
updating oil and gas reserve estimation and disclosure
requirements. The ASU amends FASB ASC 932 to align the reserve
calculation and disclosure requirements with the requirements in
SEC Release
No. 33-8995.
SEC Release
No. 33-8995,
amends oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
revising oil and gas reserves estimation and disclosure
requirements. The rules include changes to pricing used to
estimate reserves, the ability to include non-traditional
resources in reserves, the use of new technology for determining
reserves and permitting disclosure of probable and possible
reserves. 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. Accordingly, the Company adopted the update to FASB
ASC 932 as of December 31, 2009.
In accordance with our three-year planning and budgeting cycle,
proved undeveloped reserves included in the current, as well as
previous reserve estimates, include only economic well locations
that are forecast to be drilled within a three-year period. As a
result of our self-imposed three-year limit on proved
undeveloped reserves inventory, we have not booked any proved
undeveloped reserves beyond five years. As a result, it is the
Companys opinion that the proved reserves included in this
report would not be significantly different if they were filed
under the previous guidelines.
The Company utilizes reliable technology such as seismic data
and interpretation, wireline formation tests, geophysical logs
and core data to assess its resources. However, none of these
technologies have contributed to a material addition to the
proved reserves in this report. The proved reserves estimates
are prepared by Netherland, Sewell and Associates, an
independent, third-party engineering firm.
Estimates of proved crude oil and natural gas reserves
significantly affect the Companys depreciation, depletion
and amortization (DD&A) expense. For example,
if estimates of proved reserves decline, the Companys
DD&A rate will increase, resulting in a decrease in net
income. A decline in estimates of proved reserves may result
from a number of factors including lower prices, evaluation of
additional operating history, mechanical problems on our wells
and catastrophic events. Lower prices also make it uneconomical
to drill wells or produce from fields with high operating costs.
35
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.
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized in the appropriate full cost pool.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. 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 the average of prices in effect on the first
day of the month for the preceding twelve month period. 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.
During the first quarter of 2009, the Company recorded a
$1.0 billion ($673.0 million net of tax) non-cash
write-down of the carrying value of the Companys proved
oil and gas properties as of March 31, 2009, as a result of
the ceiling test limitation, which is reflected as write-down of
proved oil and gas properties in the accompanying consolidated
statements of operations. The Company did not have any
write-downs related to the full cost ceiling limitation in 2010
or 2008.
Asset Retirement Obligation. The
Companys asset retirement obligations (ARO)
consist primarily of estimated costs of dismantlement, removal,
site reclamation and similar activities associated with its oil
and natural gas properties. FASB ASC Topic 410, Asset Retirement
and Environmental Obligations (FASB ASC 410)
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 costs, including revisions
thereto, are charged to expense through DD&A.
Entitlements Method of Accounting for Oil and Natural Gas
Sales. The Company generally sells natural gas
and condensate 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 collectability is reasonably assured. The
Company accounts for oil and natural gas sales using the
entitlements method. Under the entitlements method,
revenue is recorded based
36
upon the Companys ownership share of volumes sold,
regardless of whether it has taken its ownership share of such
volumes. The Company records a receivable or a liability to the
extent it receives less or more than its share of the volumes
and related revenue.
Make-up
provisions and ultimate settlements of volume imbalances are
generally governed by agreements between the Company and its
partners with respect to specific properties or, in the absence
of such agreements, through negotiation. The value of volumes
over- or under-produced can change based on changes in commodity
prices. The Company prefers the entitlements method of
accounting for oil and natural gas sales because it allows for
recognition of revenue based on its actual share of jointly
owned production, results in better matching of revenue with
related operating expenses, and provides balance sheet
recognition of the estimated value of product imbalances.
Valuation of Deferred Tax Assets. The Company
uses the asset and liability method of accounting for income
taxes. Under this method, future income tax assets and
liabilities are determined based on differences between the
financial statement carrying values and their respective income
tax basis (temporary differences).
To assess the realization of deferred tax assets, management
considers whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The
ultimate realization of deferred tax assets is dependent upon
the generation of future taxable income during the periods in
which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities,
projected future taxable income and tax planning strategies in
making this assessment.
Derivative Instruments and Hedging
Activities. Currently, the Company largely relies
on commodity derivative contracts (generally, financial swaps)
to manage its exposure to commodity price risk. Additionally,
and from time to time, the Company enters into physical, fixed
price forward natural gas sales in order to mitigate its
commodity price exposure on a portion of its natural gas
production. These fixed price forward gas sales are considered
normal sales in the ordinary course of business and outside the
scope of FASB ASC Topic 815, Derivatives and Hedging (FASB
ASC 815).
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 previously followed hedge accounting for its natural gas
hedges. Under this prior 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 (loss). 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
Operations as an unrealized gain or loss on commodity
derivatives. There was no resulting effect on overall cash flow,
total assets, total liabilities or total stockholders
equity (See Note 6).
Fair Value Measurements. The Company follows
FASB ASC Topic 820, Fair Value Measurements and Disclosures
(FASB ASC 820. Under FASB ASC 820, fair value is
defined 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
Companys 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).
See Note 9 for additional information.
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 FASB ASC 820 and we aligned the
categories below with the Level 1, 2, and 3 fair value
measurements as defined by FASB
37
ASC 820. The balance of net unrealized gains and losses
recognized for our energy-related derivative instruments at
December 31, 2010 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 derivative asset
|
|
$
|
|
|
|
$
|
133,991
|
|
|
$
|
|
|
|
$
|
133,991
|
|
Long-term derivative asset
|
|
$
|
|
|
|
$
|
2,066
|
|
|
$
|
|
|
|
$
|
2,066
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
718
|
|
|
$
|
|
|
|
$
|
718
|
|
Long-term derivative liability
|
|
$
|
|
|
|
$
|
5,337
|
|
|
$
|
|
|
|
$
|
5,337
|
|
|
|
|
(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, managements judgment is
based on interpretation of laws and regulations, which can be
interpreted differently by regulators
and/or
courts of law. The Companys management closely monitors
known and potential legal, environmental and other contingencies
and periodically determines when the Company should record
losses for these items based on information available to the
Company.
Share-Based Payment Arrangements. The Company
follows FASB ASC Topic 718, Compensation Stock
Compensation (FASB ASC 718) 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. Share-based compensation expense recognized under FASB
ASC 718 for the years ended December 31, 2010, 2009
and 2008 was $12.9 million, $10.9 million and
$5.8 million, respectively. See Note 7 for additional
information.
Results
of Operations Year Ended December 31, 2010 vs.
Year Ended December 31, 2009
During the year ended December 31, 2010, production
increased on a gas equivalent basis to 213.6 Bcfe from
180.1 Bcfe for the same period in 2009 attributable to the
Companys successful drilling activities during 2010.
Realized natural gas prices, including realized gain and loss on
commodity derivatives, remained flat at $4.88 per Mcf during the
years ended December 31, 2010 and 2009. During the year
ended December 31, 2010, the Companys average price
for natural gas was $4.31 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $3.49 per Mcf for
the same period in 2009. The increase in production contributed
to a 47% increase in revenues for the year ended
December 31, 2010 to $979.4 million as compared to
$666.8 million in 2009.
Lease operating expense (LOE) increased to
$45.9 million for the year ended December 31, 2010
compared to $40.7 million during the same period in 2009
due primarily to increased well counts resulting from the
Companys drilling program. On a unit of production basis,
LOE costs decreased to $0.22 per Mcfe at December 31, 2010
compared to $0.23 per Mcfe at December 31, 2009 as a result
of increased production volumes.
During the year ended December 31, 2010, production taxes
were $95.9 million compared to $67.0 million during
the same period in 2009, or $0.45 per Mcfe, compared to $0.37
per Mcfe. The increase in per unit taxes is attributable to
increased sales revenues as a result of higher realized gas
prices (excluding realized gain on commodity derivatives) during
the year ended December 31, 2010 as compared to the same
period in 2009. Production taxes are calculated based on a
percentage of revenue from production and were 9.8% of revenues
for the year ended 2010 and 10.0% for the same period in 2009.
38
Gathering fees increased to $50.1 million for the year
ended December 31, 2010 compared to $45.2 million
during the same period in 2009 largely due to increased
production volumes. On a per unit basis, gathering fees
decreased to $0.23 per Mcfe for the year ended December 31,
2010 as compared to $0.25 per Mcfe for the same period in 2009.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred firm transportation charges totaling $65.0 million
for the period ended December 31, 2010 as compared to
$58.0 million for the same period in 2009 in association
with REX Pipeline transportation charges. On a per unit basis,
transportation charges decreased to $0.30 per Mcfe (on total
company volumes) for the period ended December 31, 2010 as
compared to $0.32 for the same period in 2009 due to the
increase in total company production volumes during the period
ended December 31, 2010 and partially offset by increased
transportation rates as a result of further eastern expansion of
REX.
DD&A increased to $241.8 million during the period
ended December 31, 2010 from $201.8 million for the
same period in 2009, attributable to increased production
volumes. On a unit of production basis, DD&A increased to
$1.13 per Mcfe at December 31, 2010 from $1.12 at
December 31, 2009.
General and administrative expenses increased to
$24.4 million for the period ended December 31, 2010
compared to $19.8 million for the same period in 2009. The
increase in general and administrative expenses is primarily
attributable to increased headcount and related compensation. On
a per unit basis, general and administrative expenses remained
flat at $0.11 per Mcfe for the years ended December 31,
2010 and 2009.
Interest expense increased to $49.0 million during the
period ended December 31, 2010 compared to
$37.2 million during the same period in 2009 as a result of
increased borrowings during the period ended December 31,
2010. For the year ended December 31, 2010, the Company
capitalized $21.2 million in interest associated with
unevaluated oil and gas properties that are excluded from
amortization and actively being evaluated as well as work in
process relating to gathering systems that are not currently in
service. There was no interest capitalized during the year ended
December 31, 2009. At December 31, 2010, the Company
had $1.6 billion in borrowings outstanding.
Other expense for the year ended December 31, 2009 includes
rig termination payments of $2.9 million that were not
incurred during 2010.
During the year ended December 31, 2010, the Company
recognized litigation expenses of $9.9 million related to
the resolution of litigation matters.
During the year ended December 31, 2010, the Company
recognized $116.8 million related to realized gain on
commodity derivatives as compared to $239.4 million during
the year ended December 31, 2009. The realized gain or loss
on commodity derivatives relates to actual amounts received or
paid under the Companys derivative contracts.
At December 31, 2010, the Company recognized
$208.6 million related to unrealized gain on commodity
derivatives as compared to $92.8 million related to
unrealized loss on commodity derivatives at December 31,
2009. The unrealized gain or loss on commodity derivatives
represents the change in the fair value of these derivative
instruments.
The Company recognized income before income taxes of
$723.1 million for the year ended December 31, 2010
compared with a loss of $696.2 million for the same period
in 2009. The increase in earnings is primarily a result of the
non-cash write-down of oil and gas properties associated with
the ceiling test limitation during the first quarter of 2009,
increased production during 2010 and unrealized gains on
commodity derivatives during the period ended December 31,
2010 as compared to the same period in 2009.
The income tax provision recognized for the year ended
December 31, 2010 was $258.6 million compared with an
income tax benefit of $245.1 million for the year ended
December 31, 2009 due to a net loss during the year ended
December 31, 2009 primarily as a result of the non-cash
write-down of oil and gas properties associated with the ceiling
test limitation.
39
For the year ended December 31, 2010, the Company
recognized net income of $464.5 million or $3.01 per
diluted share as compared with a net loss of $451.1 million
or ($2.98) per diluted share for the same period in 2009. The
increase is primarily attributable to the non-cash write-down of
oil and gas properties associated with the ceiling test
limitation during the first quarter of 2009, increased
production during 2010 and unrealized gains on commodity
derivatives during the year ended December 31, 2010 as
compared to the same period in 2009.
Results
of Operations Year Ended December 31, 2009 vs.
Year Ended December 31, 2008
During the year ended December 31, 2009, production
increased on a gas equivalent basis to 180.1 Bcfe from
145.3 Bcfe for the same period in 2008 attributable to the
Companys successful drilling activities during 2009.
Realized natural gas prices, including realized gain and loss on
commodity derivatives, decreased 33% to $4.88 per Mcf during the
year ended December 31, 2009 as compared to $7.26 per Mcf
for the same period in 2008. During the year ended
December 31, 2009, the Companys average price for
natural gas was $3.49 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $7.11 per Mcf for
the same period in 2008. The decrease in average natural gas
prices partially offset by the increase in production
contributed to a 39% decrease in revenues for the year ended
December 31, 2009 to $666.8 million as compared to
$1.1 billion in 2008.
Lease operating expense (LOE) increased to
$40.7 million for the year ended December 31, 2009
compared to $37.0 million during the same period in 2008
due primarily to increased well counts resulting from the
Companys drilling program. On a unit of production basis,
LOE costs decreased to $0.23 per Mcfe at December 31, 2009
compared to $0.25 per Mcfe at December 31, 2008 as a result
of increased production volumes and a higher mix of Ultra
operated production during the year ended December 31, 2009.
During the year ended December 31, 2009, production taxes
were $67.0 million compared to $119.5 million during
the same period in 2008, or $0.37 per Mcfe, compared to $0.82
per Mcfe. The decrease in per unit taxes is attributable to
decreased sales revenues as a result of lower realized gas
prices during the year ended December 31, 2009 as compared
to the same period in 2008. Production taxes are calculated
based on a percentage of revenue from production and were 10.0%
of revenues for the year ended 2009 and 11.0% for the same
period in 2008.
Gathering fees increased to $45.2 million for the year
ended December 31, 2009 compared to $37.7 million
during the same period in 2008 largely due to increased
production volumes. On a per unit basis, gathering fees
decreased to $0.25 per Mcfe for the year ended December 31,
2009 as compared to $0.26 per Mcfe for the same period in 2008.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred firm transportation charges totaling $58.0 million
for the period ended December 31, 2009 as compared to
$46.3 million for the same period in 2008 in association
with REX Pipeline transportation charges. On a per unit basis,
transportation charges remained flat at $0.32 per Mcfe (on total
company volumes) for the periods ended December 31, 2009
and 2008.
DD&A increased to $201.8 million during the period
ended December 31, 2009 from $184.8 million for the
same period in 2008, attributable to increased production
volumes, partially offset by a lower depletion rate due mainly
to a lower depletable base as a result of the ceiling test
limitation during the first quarter of 2009. On a unit of
production basis, DD&A decreased to $1.12 per Mcfe at
December 31, 2009 from $1.27 at December 31, 2008. The
Company recorded a $1.0 billion non-cash write-down of the
carrying value of the Companys proved oil and gas
properties at March 31, 2009 as a result of the ceiling
test limitation. The write-down reduced earnings in the first
quarter of 2009 and results in a lower DD&A rate in future
periods.
General and administrative expenses increased to
$19.8 million for the period ended December 31, 2009
compared to $17.0 million for the same period in 2008. The
increase in general and administrative expenses is primarily
attributable to increased headcount and related compensation. On
a per unit basis, general and administrative expenses decreased
to $0.11 per Mcfe for the year ended December 31, 2009 as
compared to $0.12 per Mcfe for the same period in 2008.
Interest expense increased to $37.2 million during the
period ended December 31, 2009 compared to
$21.3 million during the same period in 2008 as a result of
increased borrowings during the period ended December 31,
2009. At December 31, 2009, the Company had
$795.0 million in borrowings outstanding.
40
Other expense increased to $2.9 million as of
December 31, 2009 primarily as a result of rig termination
payments during the period ended December 31, 2009.
During the year ended December 31, 2009, the Company
recognized $239.4 million related to realized gain on
commodity derivatives as compared to $19.0 million during
the year ended December 31, 2008. The realized gain or loss
on commodity derivatives relates to actual amounts received or
paid under the Companys derivative contracts.
During the year ended December 31, 2009, the Company
recognized $92.8 million related to unrealized loss on
commodity derivatives as compared to $14.2 million related
to unrealized gain on commodity derivatives during the year
ended December 31, 2008. The unrealized gain or loss on
commodity derivatives represents the change in the fair value of
these derivative instruments.
The Company recognized a loss before income taxes of
$696.2 million for the year ended December 31, 2009
compared with income of $654.4 million for the same period
in 2008. The decrease in earnings is primarily a result of the
non-cash write-down of oil and gas properties associated with
the ceiling test limitation, decreased natural gas prices
partially offset by increased production and realized gains on
commodity derivatives during the period ended December 31,
2009 as compared to the same period in 2008.
The income tax benefit recognized for the year ended
December 31, 2009 was $245.1 million compared with an
income tax provision of $240.5 million for the year ended
December 31, 2008 due to a net loss during the year ended
December 31, 2009 primarily as a result of the non-cash
write-down of oil and gas properties associated with the ceiling
test limitation.
For the year ended December 31, 2009, the Company
recognized a net loss of $451.1 million or ($2.98) per
diluted share as compared with net income of $414.3 million
or $2.65 per diluted share for the same period in 2008. The
decrease is primarily attributable to the non-cash write-down of
oil and gas properties associated with the ceiling test
limitation, decreased natural gas prices partially offset by
increased production and realized gains on commodity derivatives
during the year ended December 31, 2009 as compared to the
same period in 2008.
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. GAAP. In addition, application of generally
accepted accounting principles 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.
LIQUIDITY
AND CAPITAL RESOURCES
During the year ended December 31, 2010, the Company relied
on cash provided by operations along with borrowings under the
senior credit facility and the issuance of the 2010 Senior Notes
to finance its capital expenditures. The Company participated in
the drilling of 399 wells in Wyoming and Pennsylvania
during 2010. For the year ended December 31, 2010, total
capital expenditures were $1.6 billion ($403.8 million
to acquire additional acreage in the Pennsylvania Marcellus
Shale, $1.2 billion related to oil and gas exploration and
development expenditures and $76.7 million related to
gathering system expenditures).
At December 31, 2010, the Company reported a cash position
of $70.8 million compared to $14.3 million at
December 31, 2009. Working capital deficit at
December 31, 2010 was $57.0 million compared to a
deficit of $137.5 million at December 31, 2009. At
December 31, 2010, there were no outstanding borrowings
under the bank credit facility and $500.0 million of
available borrowing capacity under the credit facility. In
addition, the Company had $1.6 billion outstanding in
senior notes (See Note 6). Other long-term obligations of
$52.6 million at December 31, 2010 is comprised of
items payable in more than one year, primarily related to
production taxes and asset retirement obligations.
The Companys positive cash provided by operating
activities, along with availability under the senior credit
facility, are projected to be sufficient to fund the
Companys budgeted capital investment program for 2011,
which is currently projected to be approximately
$1.1 billion. Of the $1.1 billion budget, the Company
plans to allocate approximately 55% to Wyoming, 35% to
Pennsylvania and the remainder to midstream, land and other.
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
41
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 the Companys 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 the Companys consolidated
leverage ratio (125 basis points per annum as of
December 31, 2010). The Company also pays commitment fees
on the unused commitment under the facility based on a grid of
our consolidated leverage ratio.
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 the Companys debt rating is below
investment grade, the maintenance of an annual ratio of the net
present value of the Companys oil and gas properties to
total funded debt of at least 1.75 to 1.00. At December 31,
2010, the Company was in compliance with all of its debt
covenants under the credit facility. (See Note 6).
Senior Notes: On January 28, 2010 and
October 12, 2010, Ultra Resources, Inc. issued
$500.0 million and $525.0 million Senior Notes
(the 2010 Senior Notes), respectively, pursuant to a
Second and Third Supplement to the Master Note Purchase
Agreement between the Company and the purchasers of the Notes.
The Senior Notes rank pari passu with the Companys bank
credit facility. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation.
The Senior Notes are pre-payable in whole or in part at any time
and are subject to representations, warranties, covenants and
events of default customary for a senior note financing. At
December 31, 2010, the Company was in compliance with all
of its debt covenants under the Senior Notes. (See Note 6).
Operating Activities. During the year ended
December 31, 2010, net cash provided by operating
activities was $824.7 million, a 39% increase from
$592.6 million for the same period in 2009. The increase in
net cash provided by operating activities was largely
attributable to increased production during the year ended
December 31, 2010 as compared to the same period in 2009.
Investing Activities. During the year ended
December 31, 2010, net cash used in investing activities
was $1.5 billion as compared to $820.6 million for the
same period in 2009. The increase in net cash used in investing
activities is largely due to increased capital investments
associated with the Companys drilling activities in 2010
as compared to 2009 as well as the increased investments
associated with the Pennsylvania Marcellus Shale acquisition in
2010 and partially offset by the timing of payments associated
with capital costs incurred during one year and paid during the
following year.
Financing Activities. During the year ended
December 31, 2010, net cash provided by financing
activities was $761.0 million as compared to
$228.1 million for the same period in 2009. The increase in
cash provided by net financing activities is largely due to
increased borrowings, primarily attributable to the 2010 Senior
Notes offerings totaling approximately $1.025 billion
during 2010 as compared to 2009.
Outlook
We believe we are well positioned for the current economic
environment because of our status as a low cost operator in the
industry combined with our financial flexibility. In 2010, the
Company established new production records while maintaining a
low cost structure which contributes to the consistency of the
Companys returns and growth.
Although our net cash provided by operating activities was
negatively affected by continued low natural gas prices, we
believe that we will continue to generate positive cash flow
from operations, which, along with our available cash, will
provide sufficient liquidity to fund our capital investments and
operations over the next twelve months. We expect to rely on our
available cash, our existing credit facility and the cash we
generate from our operations to meet our obligations. While we
continue to monitor the overall health of the credit markets, a
renewed, long-term disruption in the credit markets could make
financing more expensive or unavailable, which could have a
material adverse effect on our operations.
42
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of December 31, 2010.
Contractual
Obligations
The following table summarizes our contractual obligations as of
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 and
|
|
|
|
Total
|
|
|
2011
|
|
|
2012-2014
|
|
|
2015-2016
|
|
|
Beyond
|
|
|
|
(Amounts in thousands of U.S. dollars)
|
|
|
Long-term debt (See Note 6)
|
|
$
|
1,560,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
162,000
|
|
|
$
|
1,398,000
|
|
Transportation contract (REX)
|
|
|
789,314
|
|
|
|
78,110
|
|
|
|
307,513
|
|
|
|
302,768
|
|
|
|
100,923
|
|
Drilling contracts
|
|
|
98,355
|
|
|
|
69,449
|
|
|
|
28,906
|
|
|
|
|
|
|
|
|
|
Office space lease
|
|
|
2,455
|
|
|
|
769
|
|
|
|
1,640
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
2,450,124
|
|
|
$
|
148,328
|
|
|
$
|
338,059
|
|
|
$
|
464,814
|
|
|
$
|
1,498,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation contract. The Company is 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. REX begins at the Opal Processing Plant in southwest
Wyoming and traverses Wyoming and several other states to an
ultimate terminus in eastern Ohio. The Companys commitment
involves a capacity of 200 MMMBtu per day of natural gas
for a term of 10 years commencing in November 2009, 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.
During the first quarter of 2009, the Company entered into
agreements to secure an additional capacity of 50 MMMBtu
per day on the REX pipeline system, beginning in January 2012
through December 2018. This additional capacity will provide the
Company with the ability to move additional volumes from its
producing wells in Wyoming to markets in the eastern U.S.
Drilling contracts. As of December 31,
2010, the Company had committed to drilling obligations with
certain rig contractors that will continue into 2012. The
drilling rigs were contracted to fulfill the
2010-2012
drilling program initiatives in Wyoming.
Office space lease. The Companys
maintains office space in Colorado, Texas, Wyoming and
Pennsylvania with total remaining commitments for office leases
of $2.5 million at December 31, 2010
($0.8 million in 2011 and $1.6 million in one to three
years).
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
Wyoming natural gas production. Historically, prices received
for natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
The Companys hedging policy limits the amounts of
resources hedged to not more than 50% of its forecast production
without Board approval. As a result of its hedging activities,
the Company may realize prices that are less than or greater
than the spot prices that it would have received otherwise.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provided operational flexibility to curtail gas
production in the event of declines in natural gas prices. The
contracts were converted at no cost to the Company and the
conversion of these contracts to derivative instruments was
effective upon entering into these transactions in March 2009,
with settlements for production months through December 2010.
The natural gas
43
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
independent third parties or natural gas futures settlement
prices as traded on the NYMEX.
From time to time, the Company also utilizes fixed price forward
gas sales to manage its commodity price exposure. These fixed
price forward gas sales are considered normal sales in the
ordinary course of business and outside the scope of FASB
ASC 815.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and do not impact operating cash
flows on the cash flow statement.
At December 31, 2010, 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. See Note 9 for the
detail of the asset and liability values of the following
derivatives. The Board has approved our hedging greater than 50%
of forecast 2011 production.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Reference
|
|
Remaining
|
|
Volume -
|
|
Average
|
|
Fair Value -
|
Type
|
|
Price
|
|
Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
170,000
|
|
|
$
|
5.08
|
|
|
$
|
57,558
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
195,000
|
|
|
$
|
5.81
|
|
|
$
|
75,987
|
|
Swap
|
|
NYMEX
|
|
Summer 2011
|
|
|
70,000
|
|
|
$
|
4.50
|
|
|
$
|
(272
|
)
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
140,000
|
|
|
$
|
5.00
|
|
|
$
|
(3,271
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to December 31, 2010 and through
February 16, 2011, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
|
|
|
|
|
|
|
|
|
Reference
|
|
Remaining
|
|
Volume -
|
|
Average
|
|
|
Type
|
|
Price
|
|
Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
|
|
Swap
|
|
NYMEX
|
|
Summer 2011
|
|
|
90,000
|
|
|
$
|
4.63
|
|
|
|
|
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
130,000
|
|
|
$
|
5.04
|
|
|
|
|
|
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 Operations for the years ended December 31,
2010, 2009 and 2008 (refer to Note 2 for details of
unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
Natural Gas Commodity Derivatives:
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
116,827
|
|
|
$
|
239,366
|
|
|
$
|
18,991
|
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
|
208,625
|
|
|
|
(92,849
|
)
|
|
|
14,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
325,452
|
|
|
$
|
146,517
|
|
|
$
|
33,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Operations. |
44
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for the preparation
and integrity of all information contained in this Annual
Report. The accompanying financial statements have been prepared
in conformity with accounting principles generally accepted in
the United States of America. The financial statements include
amounts that are managements best estimates and judgments.
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term
is defined in Exchange Act
Rules 13a-15(f).
Under the supervision and with the participation of our
management, including our chief executive officer and chief
financial officer, we conducted an evaluation of the
effectiveness of our internal control over financial reporting
based on the framework in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control
Integrated Framework, our management concluded that our internal
control over financial reporting was effective as of
December 31, 2010.
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.
45
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Ultra Petroleum Corp.
We have audited the accompanying consolidated balance sheets of
Ultra Petroleum Corp. as of December 31, 2010 and 2009, and
the related consolidated statements of operations,
shareholders equity, and cash flows for each of the three
years in the period ended December 31, 2010. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Ultra Petroleum Corp. at December 31,
2010 and 2009, and the consolidated results of its operations
and its cash flows for each of the three years in the period
ended December 31, 2010, in conformity with
U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial
statements, the Company has changed its reserve estimates and
related disclosures as a result of adopting new oil and gas
reserve estimation and disclosure requirements as of
December 31, 2009.
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, 2010, 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 24, 2011 expressed an unqualified
opinion thereon.
Houston, Texas
February 24, 2011
46
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of Ultra Petroleum Corp.
We have audited Ultra Petroleum Corp.s internal control
over financial reporting as of December 31, 2010, 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
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
companys internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, 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 companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, Ultra Petroleum Corp. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2010, 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, 2010 and 2009, and the related consolidated
statements of operations, shareholders equity, and cash
flows for each of the three years in the period ended
December 31, 2010 of Ultra Petroleum Corp. and our report
dated February 24, 2011 expressed an unqualified opinion
thereon.
Houston, Texas
February 24, 2011
47
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Amounts in thousands of U.S. dollars,
|
|
|
|
except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
886,396
|
|
|
$
|
601,023
|
|
|
$
|
986,374
|
|
Oil sales
|
|
|
92,990
|
|
|
|
65,739
|
|
|
|
98,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
979,386
|
|
|
|
666,762
|
|
|
|
1,084,400
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
45,938
|
|
|
|
40,679
|
|
|
|
36,997
|
|
Production taxes
|
|
|
95,914
|
|
|
|
66,970
|
|
|
|
119,502
|
|
Gathering fees
|
|
|
50,126
|
|
|
|
45,155
|
|
|
|
37,744
|
|
Transportation charges
|
|
|
64,965
|
|
|
|
58,011
|
|
|
|
46,310
|
|
Depletion, depreciation and amortization
|
|
|
241,796
|
|
|
|
201,826
|
|
|
|
184,795
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
|
|
|
|
General and administrative
|
|
|
24,351
|
|
|
|
19,772
|
|
|
|
17,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
523,090
|
|
|
|
1,469,413
|
|
|
|
442,394
|
|
Operating income (loss)
|
|
|
456,296
|
|
|
|
(802,651
|
)
|
|
|
642,006
|
|
Other income (expense), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(49,032
|
)
|
|
|
(37,167
|
)
|
|
|
(21,276
|
)
|
Gain on commodity derivatives
|
|
|
325,452
|
|
|
|
146,517
|
|
|
|
33,216
|
|
Litigation expense
|
|
|
(9,902
|
)
|
|
|
|
|
|
|
|
|
Other income (expense), net
|
|
|
260
|
|
|
|
(2,888
|
)
|
|
|
833
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
266,778
|
|
|
|
106,462
|
|
|
|
12,773
|
|
Income (loss) before income tax provision (benefit)
|
|
|
723,074
|
|
|
|
(696,189
|
)
|
|
|
654,779
|
|
Income tax provision (benefit)
|
|
|
258,615
|
|
|
|
(245,136
|
)
|
|
|
240,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
3.05
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
3.01
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic
|
|
|
152,346
|
|
|
|
151,367
|
|
|
|
152,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully
diluted
|
|
|
154,253
|
|
|
|
151,367
|
|
|
|
156,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
48
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Amounts in thousands of
|
|
|
|
U. S. dollars, except share data)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
70,834
|
|
|
$
|
14,254
|
|
Restricted cash
|
|
|
98
|
|
|
|
1,681
|
|
Oil and gas revenue receivable
|
|
|
95,142
|
|
|
|
82,326
|
|
Joint interest billing and other receivables
|
|
|
48,561
|
|
|
|
29,411
|
|
Derivative assets
|
|
|
133,991
|
|
|
|
4,398
|
|
Deferred tax assets
|
|
|
|
|
|
|
12,225
|
|
Inventory
|
|
|
2,760
|
|
|
|
4,498
|
|
Prepaid drilling costs and other current assets
|
|
|
9,663
|
|
|
|
4,948
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
361,049
|
|
|
|
153,741
|
|
Oil and gas properties, net, using the full cost method of
accounting:
|
|
|
|
|
|
|
|
|
Proved
|
|
|
2,589,423
|
|
|
|
1,794,603
|
|
Unproved
|
|
|
486,247
|
|
|
|
|
|
Property, plant and equipment
|
|
|
149,104
|
|
|
|
73,435
|
|
Long-term derivative assets
|
|
|
2,066
|
|
|
|
2,554
|
|
Restricted cash
|
|
|
|
|
|
|
28,257
|
|
Deferred financing costs and other
|
|
|
7,726
|
|
|
|
7,415
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,595,615
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
210,311
|
|
|
$
|
119,111
|
|
Production taxes payable
|
|
|
53,382
|
|
|
|
60,820
|
|
Interest payable
|
|
|
26,878
|
|
|
|
12,011
|
|
Derivative liabilities
|
|
|
718
|
|
|
|
35,033
|
|
Deferred tax liabilities
|
|
|
42,685
|
|
|
|
|
|
Capital cost accrual
|
|
|
84,042
|
|
|
|
64,216
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
418,016
|
|
|
|
291,191
|
|
Long-term debt
|
|
|
1,560,000
|
|
|
|
795,000
|
|
Deferred income tax liabilities
|
|
|
420,711
|
|
|
|
239,217
|
|
Long-term derivative liabilities
|
|
|
5,337
|
|
|
|
50,542
|
|
Other long-term obligations
|
|
|
52,575
|
|
|
|
35,858
|
|
Commitments and contingencies (Note 12)
|
|
|
|
|
|
|
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Common stock no par value; authorized
unlimited; issued and outstanding 152,567,813 and
151,759,343, at December 31, 2010 and 2009, respectively
|
|
|
426,779
|
|
|
|
377,339
|
|
Treasury stock
|
|
|
|
|
|
|
(10,525
|
)
|
Retained earnings
|
|
|
712,197
|
|
|
|
281,383
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
1,138,976
|
|
|
|
648,197
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity
|
|
$
|
3,595,615
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
49
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Issued and
|
|
|
Common
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
|
|
|
Shareholders
|
|
|
|
Outstanding
|
|
|
Stock
|
|
|
Earnings
|
|
|
Income/(Loss)
|
|
|
Stock
|
|
|
Equity
|
|
|
|
(Amounts in thousands of U.S. dollars, except share data)
|
|
|
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 re-issued 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options exercised
|
|
|
666
|
|
|
|
1,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,430
|
|
Employee stock plan grants
|
|
|
85
|
|
|
|
|
|
|
|
3,397
|
|
|
|
|
|
|
|
|
|
|
|
3,397
|
|
Shares re-issued from treasury
|
|
|
|
|
|
|
(1,430
|
)
|
|
|
(33,785
|
)
|
|
|
|
|
|
|
35,215
|
|
|
|
|
|
Net share settlements
|
|
|
(225
|
)
|
|
|
|
|
|
|
(11,293
|
)
|
|
|
|
|
|
|
|
|
|
|
(11,293
|
)
|
Fair value of employee stock plan grants
|
|
|
|
|
|
|
16,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,294
|
|
Tax benefit of stock options exercised
|
|
|
|
|
|
|
14,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,213
|
|
Comprehensive earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
|
|
|
|
|
|
|
|
(451,053
|
)
|
|
|
|
|
|
|
|
|
|
|
(451,053
|
)
|
Reclassification of derivative fair value into earnings, net of
taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,577
|
)
|
|
|
|
|
|
|
(15,577
|
)
|
Total comprehensive earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(466,630
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009
|
|
|
151,759
|
|
|
$
|
377,339
|
|
|
$
|
281,383
|
|
|
$
|
|
|
|
$
|
(10,525
|
)
|
|
$
|
648,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options exercised
|
|
|
1,206
|
|
|
|
6,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,561
|
|
Employee stock plan grants
|
|
|
105
|
|
|
|
4,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,841
|
|
Shares re-issued from treasury
|
|
|
|
|
|
|
(587
|
)
|
|
|
(9,938
|
)
|
|
|
|
|
|
|
10,525
|
|
|
|
|
|
Net share settlements
|
|
|
(502
|
)
|
|
|
|
|
|
|
(23,707
|
)
|
|
|
|
|
|
|
|
|
|
|
(23,707
|
)
|
Fair value of employee stock plan grants
|
|
|
|
|
|
|
21,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,103
|
|
Tax benefit of stock options exercised
|
|
|
|
|
|
|
17,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,522
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
464,459
|
|
|
|
|
|
|
|
|
|
|
|
464,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010
|
|
|
152,568
|
|
|
$
|
426,779
|
|
|
$
|
712,197
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,138,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
50
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
Cash provided by (used in):
|
|
(Amounts in thousands of U.S. dollars)
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) for the period
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
241,796
|
|
|
|
201,826
|
|
|
|
184,795
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
|
|
|
|
Deferred and current non-cash income taxes
|
|
|
253,926
|
|
|
|
(253,966
|
)
|
|
|
235,031
|
|
Unrealized (gain) loss on commodity derivatives
|
|
|
(208,625
|
)
|
|
|
92,849
|
|
|
|
(14,225
|
)
|
Excess tax benefit from stock based compensation
|
|
|
(17,522
|
)
|
|
|
(14,213
|
)
|
|
|
(78,840
|
)
|
Stock compensation
|
|
|
12,944
|
|
|
|
10,901
|
|
|
|
5,816
|
|
Other
|
|
|
734
|
|
|
|
1,023
|
|
|
|
11
|
|
Net changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
1,583
|
|
|
|
1,046
|
|
|
|
(137
|
)
|
Accounts receivable
|
|
|
(31,966
|
)
|
|
|
14,974
|
|
|
|
9,139
|
|
Other current assets
|
|
|
|
|
|
|
(2,913
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
(229
|
)
|
|
|
4,268
|
|
|
|
(5,543
|
)
|
Other non-current assets
|
|
|
(1,176
|
)
|
|
|
(2,905
|
)
|
|
|
|
|
Accounts payable, production taxes and accrued liabilities
|
|
|
99,410
|
|
|
|
(32,773
|
)
|
|
|
86,487
|
|
Other long-term obligations
|
|
|
6,035
|
|
|
|
(13,638
|
)
|
|
|
14,833
|
|
Current taxes payable
|
|
|
3,359
|
|
|
|
215
|
|
|
|
(10,839
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
824,728
|
|
|
|
592,641
|
|
|
|
840,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
|
(403,806
|
)
|
|
|
|
|
|
|
|
|
Oil and gas property expenditures
|
|
|
(1,164,389
|
)
|
|
|
(673,518
|
)
|
|
|
(949,650
|
)
|
Gathering system expenditures
|
|
|
(76,703
|
)
|
|
|
(67,833
|
)
|
|
|
|
|
Proceeds from sale of oil and gas properties
|
|
|
68,420
|
|
|
|
|
|
|
|
|
|
Change in capital cost accrual
|
|
|
19,826
|
|
|
|
(56,327
|
)
|
|
|
32,097
|
|
Restricted cash
|
|
|
28,257
|
|
|
|
(28,257
|
)
|
|
|
|
|
Inventory
|
|
|
1,738
|
|
|
|
4,024
|
|
|
|
4,811
|
|
Other
|
|
|
(2,442
|
)
|
|
|
1,300
|
|
|
|
(2,577
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,529,099
|
)
|
|
|
(820,611
|
)
|
|
|
(915,319
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on long-term debt
|
|
|
1,000,000
|
|
|
|
817,000
|
|
|
|
662,000
|
|
Payments on long-term debt
|
|
|
(1,260,000
|
)
|
|
|
(827,000
|
)
|
|
|
(682,000
|
)
|
Proceeds from issuance of Senior Notes
|
|
|
1,025,000
|
|
|
|
235,000
|
|
|
|
300,000
|
|
Deferred financing costs
|
|
|
(4,425
|
)
|
|
|
(1,283
|
)
|
|
|
(1,578
|
)
|
Repurchased shares/net share settlements
|
|
|
(23,707
|
)
|
|
|
(11,293
|
)
|
|
|
(298,307
|
)
|
Excess tax benefit from stock based compensation
|
|
|
17,522
|
|
|
|
14,213
|
|
|
|
78,840
|
|
Proceeds from exercise of options
|
|
|
6,561
|
|
|
|
1,430
|
|
|
|
19,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
760,951
|
|
|
|
228,067
|
|
|
|
78,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash during the period
|
|
|
56,580
|
|
|
|
97
|
|
|
|
3,525
|
|
Cash and cash equivalents, beginning of period
|
|
|
14,254
|
|
|
|
14,157
|
|
|
|
10,632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
70,834
|
|
|
$
|
14,254
|
|
|
$
|
14,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
53,291
|
|
|
$
|
30,579
|
|
|
$
|
16,092
|
|
Income taxes
|
|
$
|
2,537
|
|
|
$
|
11,403
|
|
|
$
|
16,322
|
|
See accompanying notes to consolidated financial statements.
51
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(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 Companys
principal business activities are in the Green River Basin of
southwest Wyoming and the north-central Pennsylvania area of the
Appalachian Basin.
|
|
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 and Ultra Resources,
Inc. 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.
Long-term restricted cash represents cash set aside in an escrow
account in connection with the purchase of additional acreage in
the Marcellus Shale, which closed on February 22, 2010.
(d) Property, plant and
equipment: Capital assets are recorded at cost
and depreciated using the declining-balance method based on a
seven-year useful life. Gathering system expenditures are
recorded at cost and depreciated using the straight-line method
based on a 30 year useful life.
(e) Oil and natural gas properties: On
January 6, 2010, the FASB issued an ASU updating oil and
gas reserve estimation and disclosure requirements. The ASU
amends FASB ASC 932 to align the reserve calculation and
disclosure requirements with the requirements in SEC Release
No. 33-8995.
SEC Release
No. 33-8995,
amends oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
revising oil and gas reserves estimation and disclosure
requirements. The rules include changes to pricing used to
estimate reserves, the ability to include non-traditional
resources in reserves, the use of new technology for determining
reserves and permitting disclosure of probable and possible
reserves. 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. Accordingly, the Company adopted the update to FASB
ASC 932 as of December 31, 2009. The implementation of
this rule did not result in material additions to the
Companys proved reserves included in this report.
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 proved 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.
52
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized.
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 the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
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
results in a lower DD&A rate 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.
(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, 2010,
inventory of $2.8 million primarily includes the cost of
pipe and production equipment that will be utilized during the
2011 drilling program.
(g) Derivative Instruments and Hedging
Activities: Currently, the Company largely relies
on commodity derivative contracts to manage its exposure to
commodity price risk. The natural gas reference prices of these
commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties or natural gas futures settlement prices as traded on
the New York Mercantile Exchange (NYMEX).
Additionally, and from time to time, the Company enters into
physical, fixed price forward natural gas sales in order to
mitigate its commodity price exposure on a portion of its
natural gas production. These fixed price forward gas sales are
considered normal sales in the ordinary course of business and
outside the scope of FASB ASC Topic 815, Derivatives and Hedging
(FASB ASC 815). The Company does not offset the
value of its derivative arrangements with the same counterparty.
(See Note 8).
(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 described in FASB
ASC Topic 740, Income Taxes. In addition, 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 stockholders 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.
53
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table provides a reconciliation of components of
basic and diluted net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net income (loss)
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
|
|
|
152,346
|
|
|
|
151,367
|
|
|
|
152,075
|
|
Effect of dilutive instruments
|
|
|
1,907
|
|
|
|
|
(1)
|
|
|
4,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
|
|
154,253
|
|
|
|
151,367
|
|
|
|
156,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
3.05
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
3.01
|
|
|
$
|
(2.98
|
)
|
|
$
|
2.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
1,214
|
|
|
|
|
(1)
|
|
|
418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Due to the net loss for the year ended December 31, 2009,
2.2 million shares for options and restricted stock units
were anti-dilutive and excluded from the computation of loss per
share. |
(j) Use of estimates: Preparation of
consolidated financial statements in accordance with
U.S. GAAP 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 measures and recognizes
compensation expense for all share-based payment awards made to
employees and directors, including employee stock options, based
on estimated fair values in accordance with FASB ASC Topic 718,
Compensation Stock Compensation.
(l) Fair Value Accounting: The Company
follows FASB ASC Topic 820, Fair Value Measurements and
Disclosures (FASB ASC 820), which defines fair
value, establishes a framework for measuring fair value under
GAAP, and expands disclosures about fair value measurements.
This statement applies under other accounting topics that
require or permit fair value measurements. The implementation
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. For
those non-financial assets and liabilities measured or disclosed
at fair value on a non-recurring basis, primarily our asset
retirement obligation, this respective subtopic of FASB
ASC 820, was effective January 1, 2009. Implementation
of this portion of the standard did not have a material impact
on consolidated results of operations, financial position or
liquidity. See Note 9 for additional information.
(m) Asset Retirement Obligation: The
initial estimated retirement obligation of properties is
recognized as a liability with an associated increase in oil and
gas properties for the asset retirement cost. Accretion expense
is recognized over the estimated productive life of the related
assets. If the fair value of the estimated asset retirement
obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions
in estimated liabilities can result from revisions of estimated
inflation rates, changes in service and equipment costs and
changes in the estimated timing of settling asset retirement
obligations.
(n) Revenue Recognition: Natural gas
revenues are recorded based on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Companys net revenue interest. The Company
initially records its entitled share of revenues based on
estimated production volumes. Subsequently,
54
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 immediately after
production at various locations at which time title and risk of
loss pass to the buyer. Gas imbalances occur when the Company
sells more or less than its entitled ownership percentage of
total gas production. Any amount received in excess of the
Companys share is treated as a liability. If the Company
receives less than its entitled share, the underproduction is
recorded as a receivable. At December 31, 2010 and 2009,
the Company had a net natural gas imbalance liability of
$0.9 million and $2.9, respectively.
(o) Capitalized Interest: Interest is
capitalized on the cost of unevaluated gas and oil properties
that are excluded from amortization and actively being evaluated
as well as on work in process relating to gathering systems that
are not currently in service.
(p) Reclassifications: Certain amounts in
the financial statements of prior periods have been reclassified
to conform to the current period financial statement
presentation.
|
|
2.
|
OTHER
COMPREHENSIVE INCOME:
|
Other comprehensive income (loss) is a term used to define
revenues, expenses, gains and losses that under generally
accepted accounting principles impact Shareholders Equity,
excluding transactions with shareholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net income (loss)
|
|
$
|
464,459
|
|
|
$
|
(451,053
|
)
|
|
$
|
414,275
|
|
Unrealized gain on derivative instruments*
|
|
|
|
|
|
|
(24,002
|
)
|
|
|
16,368
|
|
Tax expense on unrealized gain on derivative instruments
|
|
|
|
|
|
|
8,425
|
|
|
|
(5,745
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
$
|
464,459
|
|
|
$
|
(466,630
|
)
|
|
$
|
424,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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 8). The net gain or loss in accumulated other
comprehensive income at November 3, 2008 remained on the
balance sheet and the respective months gains or losses
were reclassified from accumulated other comprehensive income to
earnings as the counterparty settlements affected earnings
(January through December 2009). 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. |
|
|
3.
|
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.
The following table summarizes the activities for the
Companys asset retirement obligations for the years ended:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Asset retirement obligations at beginning of period
|
|
$
|
17,372
|
|
|
$
|
14,079
|
|
Accretion expense
|
|
|
2,099
|
|
|
|
1,495
|
|
Liabilities incurred
|
|
|
8,564
|
|
|
|
3,398
|
|
Liabilities settled
|
|
|
(17
|
)
|
|
|
(80
|
)
|
Revisions of estimated liabilities
|
|
|
34
|
|
|
|
(1,520
|
)
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at end of period
|
|
|
28,052
|
|
|
|
17,372
|
|
Less: current asset retirement obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term asset retirement obligations
|
|
$
|
28,052
|
|
|
$
|
17,372
|
|
|
|
|
|
|
|
|
|
|
55
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
4.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
4,575,222
|
|
|
$
|
3,544,519
|
|
Less: Accumulated depletion, depreciation and amortization(3)
|
|
|
(1,985,799
|
)
|
|
|
(1,749,916
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,589,423
|
|
|
|
1,794,603
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized(1),(2)
|
|
|
486,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs oil and gas properties
|
|
$
|
3,075,670
|
|
|
$
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On a unit basis, DD&A from continuing operations was $1.13,
$1.12 and $1.27 per Mcfe for the years ended December 31,
2010, 2009 and 2008, respectively. |
|
|
|
(1) |
|
In 2010, a wholly-owned subsidiary of the Company acquired, for
$403.8 million in cash, non-producing mineral acres and a
small number of producing gas wells in the Pennsylvania
Marcellus Shale. Additionally, the Company purchased additional
undeveloped acreage in the Marcellus Shale for approximately
$63.4 million during 2010. |
|
(2) |
|
Interest is capitalized on the cost of unevaluated oil and
natural gas properties that are excluded from amortization and
actively being evaluated as well as on work in process relating
to gathering systems that are not currently in service. For the
year ended December 31, 2010, total interest on outstanding
debt was $70.2 million of which, $21.2 million was
capitalized on the cost of unevaluated oil and natural gas
properties and work in process relating to gathering systems
that are not currently in service. For the year ended
December 31, 2009, there was no interest capitalized. |
|
(3) |
|
During the first quarter of 2009, the Company recorded a
$1.0 billion non-cash write-down of the carrying value of
the Companys proved oil and gas properties as of
March 31, 2009, as a result of the ceiling test limitation,
which is reflected as write-down of proved oil and gas
properties in the accompanying consolidated statements of
operations. The March 31, 2009 ceiling test limitation was
calculated prior to the adoption of SEC Release
No. 33-8995
and was based on prices in effect on the last day of the
reporting period, March 31, 2009. The Company did not have
any write-downs related to the full cost ceiling limitation in
2010. |
Of the total net unevaluated costs excluded from amortization at
December 31, 2010, approximately $486.2 million is
related to the acquisition of undeveloped properties in the
Companys Appalachian properties in Pennsylvania. The
timing and amount of costs to be included in future amortization
computations related to the Companys Appalachian
properties will depend on the results of drilling and other
assessments. The Company is, therefore, unable to estimate when
these costs will be included in the amortization computation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Prior
|
|
|
Acquisition costs
|
|
$
|
612,040
|
|
|
$
|
521,149
|
|
|
|
36,432
|
|
|
|
17,650
|
|
|
|
36,809
|
|
Exploration costs
|
|
|
19,075
|
|
|
|
2,985
|
|
|
|
2,829
|
|
|
|
2,284
|
|
|
|
10,977
|
|
Capitalized interest
|
|
|
19,610
|
|
|
|
19,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
(71,677
|
)
|
|
|
(68,420
|
)
|
|
|
(3,257
|
)
|
|
|
|
|
|
|
|
|
Less transfers to proved
|
|
|
(92,801
|
)
|
|
|
(44,621
|
)
|
|
|
(36,004
|
)
|
|
|
(1,168
|
)
|
|
|
(11,008
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
486,247
|
|
|
$
|
430,703
|
|
|
$
|
|
|
|
$
|
18,766
|
|
|
$
|
36,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
5.
|
PROPERTY,
PLANT AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
Net Book
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Value
|
|
|
Gathering systems
|
|
$
|
144,940
|
|
|
|
(3,123
|
)
|
|
|
141,817
|
|
|
$
|
67,408
|
|
Computer equipment
|
|
|
2,188
|
|
|
|
(1,195
|
)
|
|
|
993
|
|
|
|
778
|
|
Office equipment
|
|
|
450
|
|
|
|
(326
|
)
|
|
|
124
|
|
|
|
102
|
|
Leasehold improvements
|
|
|
464
|
|
|
|
(313
|
)
|
|
|
151
|
|
|
|
108
|
|
Land
|
|
|
2,437
|
|
|
|
|
|
|
|
2,437
|
|
|
|
2,437
|
|
Other
|
|
|
6,481
|
|
|
|
(2,899
|
)
|
|
|
3,582
|
|
|
|
2,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net
|
|
$
|
156,960
|
|
|
$
|
(7,856
|
)
|
|
$
|
149,104
|
|
|
$
|
73,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historically, the Companys condensate production was
gathered from its Wyoming well locations by tanker trucks and
then shipped to other locations for injection into crude oil
pipelines or other facilities. During 2010, the Company
initiated service on its final two, of four total, central
gathering facilities. These facilities are part of the
Companys liquids gathering system designed to gather
condensate and water from various leases and wells operated by
the Company. The condensate and water are transported to central
points in the field where condensate can be loaded into trucks
or delivered into pipelines for delivery to the Companys
customers. Produced water is disposed of or recycled and re-used.
In Pennsylvania, the Company and its partners continue
constructing gas gathering pipelines and facilities, compression
facilities and pipeline delivery stations to gather production
from its newly completed natural gas wells. Construction on
these facilities is expected to continue throughout 2011
allowing the Company to manage its midstream capacity to
coincide with increased capacity requirements from its drilling
activities. These facilities are gathering systems and related
infrastructure, and their construction is expected to continue
until the field is fully developed. To date, none of the
Companys natural gas production in Pennsylvania has
required processing, treating or blending in order to remove
natural gas liquids or other impurities and it is anticipated
that facilities of this type will not be required in the future
to accommodate the Companys production.
|
|
6.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Bank indebtedness
|
|
$
|
|
|
|
$
|
260,000
|
|
Senior notes
|
|
|
1,560,000
|
|
|
|
535,000
|
|
Other long-term obligations
|
|
|
52,575
|
|
|
|
35,858
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,612,575
|
|
|
$
|
830,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Maturities of Debt at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
2016 and
|
|
|
|
|
2011
|
|
|
2012-2014
|
|
|
2015
|
|
|
Beyond
|
|
|
Total
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
100,000
|
|
|
$
|
1,460,000
|
|
|
$
|
1,560,000
|
|
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
57
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 the Companys 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
(125 basis points per annum as of December 31, 2010).
The Company also pays commitment fees on the unused commitment
under the facility based on a grid of our consolidated leverage
ratio.
At December 31, 2010, the Company had no outstanding
borrowings and $500.0 million of available borrowing
capacity under the 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 the Companys debt rating is below
investment grade, the maintenance of an annual ratio of the net
present value of the Companys oil and gas properties to
total funded debt of at least 1.75 to 1.00. At December 31,
2010, the Company was in compliance with all of its debt
covenants under the credit facility.
Senior Notes: On January 28, 2010 and
October 12, 2010, Ultra Resources, Inc., issued
$500.0 million and $525.0 million of Senior Notes,
respectively, pursuant to a Second and Third Supplement,
respectively, to the Master Note Purchase Agreement between the
Company and the purchasers of the Notes.
The Senior Notes rank pari passu with the Companys bank
credit facility. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation.
Proceeds from the sale of the Senior Notes were used to repay
bank debt or for general corporate purposes, but did not reduce
the borrowings available to the Company under the revolving
credit facility. The Senior Notes are pre-payable in whole or in
part at any time and are subject to representations, warranties,
covenants and events of default customary for a senior note
financing. At December 31, 2010, the Company was in
compliance with all of its debt covenants under the Senior Notes.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable and our asset retirement obligations.
|
|
7.
|
SHARE
BASED COMPENSATION:
|
The Company sponsors a share based compensation plan: the 2005
Stock Incentive Plan (the 2005 Plan). The plan is
administered by the Compensation Committee of the Board of
Directors (the Committee). The share based
compensation plan is an important component of the total
compensation package offered to the Companys key service
providers, and reflects the importance that the Company places
on motivating and rewarding superior results.
The 2005 Plan was adopted by the Companys Board of
Directors on January 1, 2005 and approved by the
Companys 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 Companys 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. 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.
58
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Valuation
and Expense Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Total cost of share-based payment plans
|
|
$
|
21,805
|
|
|
$
|
18,872
|
|
|
$
|
10,355
|
|
Amounts capitalized in fixed assets
|
|
$
|
8,861
|
|
|
$
|
7,971
|
|
|
$
|
4,539
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
12,944
|
|
|
$
|
10,901
|
|
|
$
|
5,816
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
4,595
|
|
|
$
|
3,826
|
|
|
$
|
2,041
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model. The
Companys employee stock options have various restrictions
including vesting provisions and restrictions on transfers and
hedging, among others, and are often exercised prior to their
contractual maturity. Expected volatilities used in the fair
value estimates are based on historical volatility of the
Companys stock. The Company uses historical data to
estimate share option exercises, expected term and employee
departure behavior used in the Black-Scholes pricing model.
Groups of employees (executives and non-executives) that have
similar historical behavior are considered separately for
purposes of determining the expected term used to estimate fair
value. The assumptions utilized result from differing pre- and
post-vesting behaviors among executive and non-executive groups.
The risk-free rate for periods within the contractual term of
the share option is based on the U.S. Treasury yield curve
in effect at the time of grant. There were no stock options
granted during the year ended December 31, 2010.
Securities
Authorized for Issuance Under Equity Compensation
Plans
As of December 31, 2010, the Company had the following
securities issuable pursuant to outstanding award agreements or
reserved for issuance under the Companys previously
approved stock incentive plans. Upon exercise, shares issued
will be newly issued shares or shares issued from treasury.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to
|
|
|
Weighted
|
|
|
Under Equity
|
|
|
|
be Issued
|
|
|
Average
|
|
|
Compensation Plans
|
|
|
|
Upon Exercise of
|
|
|
Exercise Price of
|
|
|
(Excluding Securities
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Reflected in the
|
|
Plan Category
|
|
Options
|
|
|
Options
|
|
|
First Column)
|
|
|
Equity compensation plans approved by security holders
|
|
|
2,230
|
|
|
$
|
38.56
|
|
|
|
3,706
|
|
Equity compensation plans not approved by security holders
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,230
|
|
|
$
|
38.56
|
|
|
|
3,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise Price
|
|
|
|
Options
|
|
|
(US$)
|
|
|
Balance, December 31, 2007
|
|
|
7,589
|
|
|
$
|
0.25
|
|
|
|
to
|
|
|
$
|
67.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
299
|
|
|
$
|
51.14
|
|
|
|
to
|
|
|
$
|
98.87
|
|
Forfeited
|
|
|
(80
|
)
|
|
$
|
51.60
|
|
|
|
to
|
|
|
$
|
85.05
|
|
Exercised
|
|
|
(3,595
|
)
|
|
$
|
0.25
|
|
|
|
to
|
|
|
$
|
67.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
4,213
|
|
|
$
|
0.25
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise Price
|
|
|
|
Options
|
|
|
(US$)
|
|
|
Forfeited
|
|
|
(43
|
)
|
|
$
|
51.60
|
|
|
|
to
|
|
|
$
|
78.55
|
|
Exercised
|
|
|
(666
|
)
|
|
$
|
0.25
|
|
|
|
to
|
|
|
$
|
33.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
3,504
|
|
|
$
|
1.49
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(68
|
)
|
|
$
|
51.60
|
|
|
|
to
|
|
|
$
|
76.01
|
|
Exercised
|
|
|
(1,206
|
)
|
|
$
|
1.49
|
|
|
|
to
|
|
|
$
|
45.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
2,230
|
|
|
$
|
3.91
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables summarize information about the stock
options outstanding at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
Aggregate
|
|
Range of Exercise Price
|
|
Outstanding
|
|
|
Contractual Life
|
|
|
Exercise Price
|
|
|
Intrinsic Value
|
|
|
$ 3.91 - $ 4.83
|
|
|
57
|
|
|
|
2.17
|
|
|
$
|
4.67
|
|
|
$
|
2,457
|
|
$11.68 - $19.18
|
|
|
534
|
|
|
|
3.19
|
|
|
$
|
13.07
|
|
|
$
|
18,530
|
|
$25.08 - $55.58
|
|
|
838
|
|
|
|
4.53
|
|
|
$
|
37.20
|
|
|
$
|
9,476
|
|
$46.05 - $65.04
|
|
|
207
|
|
|
|
5.51
|
|
|
$
|
57.02
|
|
|
$
|
34
|
|
$49.05 - $65.94
|
|
|
385
|
|
|
|
6.30
|
|
|
$
|
54.49
|
|
|
$
|
|
|
$51.14 - $98.87
|
|
|
209
|
|
|
|
7.39
|
|
|
$
|
70.72
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
Aggregate
|
|
Range of Exercise Price
|
|
Outstanding
|
|
|
Contractual Life
|
|
|
Exercise Price
|
|
|
Intrinsic Value
|
|
|
$ 3.91 - $ 4.83
|
|
|
57
|
|
|
|
2.17
|
|
|
$
|
4.67
|
|
|
$
|
2,457
|
|
$11.68 - $19.18
|
|
|
534
|
|
|
|
3.19
|
|
|
$
|
13.07
|
|
|
$
|
18,530
|
|
$25.08 - $55.58
|
|
|
838
|
|
|
|
4.53
|
|
|
$
|
37.20
|
|
|
$
|
9,476
|
|
$46.05 - $65.04
|
|
|
207
|
|
|
|
5.51
|
|
|
$
|
57.02
|
|
|
$
|
34
|
|
$49.05 - $65.94
|
|
|
385
|
|
|
|
6.30
|
|
|
$
|
54.49
|
|
|
$
|
|
|
$51.14 - $98.87
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
The aggregate intrinsic value in the preceding tables represents
the total pre-tax intrinsic value, based on the Companys
closing stock price of $47.77 on December 31, 2010, 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, 2010 was
1.3 million options.
The following table summarizes information about the
weighted-average grant-date fair value of share options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Share options granted
|
|
$
|
|
|
|
$
|
|
|
|
$
|
30.94
|
|
Non-vested share options at beginning of year
|
|
$
|
26.28
|
|
|
$
|
26.18
|
|
|
$
|
23.93
|
|
Non-vested share options at end of year
|
|
$
|
30.72
|
|
|
$
|
26.28
|
|
|
$
|
26.18
|
|
Options vested during the year
|
|
$
|
23.86
|
|
|
$
|
25.07
|
|
|
$
|
|
|
Options forfeited during the year
|
|
$
|
28.36
|
|
|
$
|
29.57
|
|
|
$
|
27.35
|
|
60
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The fair value of stock options that vested during the years
ended December 31, 2010 and 2009 was $9.8 million and
$3.9 million, respectively. There were no stock options
that vested during the year ended December 31, 2008. The
total intrinsic value of stock options exercised during the
years ended December 31, 2010, 2009 and 2008 was
$50.7 million, $33.2 million and $224.6 million,
respectively.
At December 31, 2010, there was $0.7 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
0.4 years.
PERFORMANCE
SHARE PLANS:
Long Term Incentive Plans. Each year since
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 specific corporate financial and operational goals are
achieved. Each LTIP covers a performance period of three years.
For 2008, the LTIP had two components: an LTIP Stock
Option Award and an LTIP Common Stock Award
consisting of performance-based restricted stock units. In 2009
and 2010, the Compensation Committee (the Committee)
approved awards consisting only of the LTIP Common Stock Award.
Under each LTIP, the Committee establishes a percentage of base
salary for each participant which is multiplied by the
participants base salary to derive a Long Term Incentive
Value. For each LTIP 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 Company performance is
below or above target levels. For the 2008, 2009 and 2010 LTIP
awards, the Committee established the following performance
measures: return on equity, reserve replacement ratio, and
production growth.
For the year ended December 31, 2010, the Company
recognized $8.6 million in pre-tax compensation expense
related to the 2008, 2009 and 2010 LTIP Common Stock Awards. For
the year ended December 31, 2009, the Company recognized
$5.8 million in pre-tax compensation expense related to the
2007, 2008 and 2009 LTIP Common Stock Awards. The amounts
recognized during the year ended December 31, 2010 assumes
that maximum performance objectives are attained. If the Company
ultimately attains these performance objectives, the associated
total compensation, estimated at December 31, 2010, for
each of the three year performance periods is expected to be
approximately $4.4 million, $24.0 million, and
$12.1 million related to the 2008, 2009 and 2010 LTIP
Common Stock Awards, respectively. The 2007 LTIP Common Stock
Award was paid in shares of the Companys stock to
employees during the first quarter of 2010 and totaled
$4.1 million.
Best in Class Program. In May 2008, the
Company established the 2008 Best in Class Program for all
permanent, full-time employees. Under the 2008 Best in
Class Program, participants are eligible to receive a
number of shares of the Companys common stock based on the
performance of the Company. As with the LTIP, the 2008 Best in
Class Program is measured over a three year performance
period. The 2008 Best in Class Program recognizes and
financially rewards the collective efforts of all of the
Companys 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 Companys 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 become payable and vest
upon distribution is based on the Companys performance
relative to the industry during a three year performance period
beginning January 1, 2008, and ending December 31,
2010. For each vested unit, the participant will receive one
share of common stock. The participant must be employed by the
Company on the date the awards are distributed in order to
receive the award.
61
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the year ended December 31, 2010, the Company
recognized $1.3 million in pre-tax compensation expense
related to the 2008 Best in Class Program. For the year
ended December 31, 2009 the Company recognized
$0.9 million in pre-tax compensation expense related to the
2008 Best in Class Program. The amount recognized for the
year ended December 31, 2010 and 2009 assumes that target
performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total
compensation related to the 2008 Best in Class Program is
estimated at $4.9 million as of December 31, 2010.
|
|
8.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
Wyoming natural gas production. Historically, prices received
for natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
The Companys hedging policy limits the amounts of
resources hedged to not more than 50% of its forecast production
without Board approval. As a result of its hedging activities,
the Company may realize prices that are less than or greater
than the spot prices that it would have received otherwise.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provided operational flexibility to curtail gas
production in the event of declines in natural gas prices. The
contracts were converted at no cost to the Company and the
conversion of these contracts to derivative instruments was
effective upon entering into these transactions in March 2009,
with settlements for production months through December 2010.
The natural gas reference prices of these commodity derivative
contracts are typically referenced to natural gas index prices
as published by independent third parties or natural gas futures
settlement prices as traded on the NYMEX.
From time to time, the Company also utilizes fixed price forward
gas sales to manage its commodity price exposure. These fixed
price forward gas sales are considered normal sales in the
ordinary course of business and outside the scope of FASB
ASC 815, Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and do not impact operating cash
flows on the cash flow statement.
At December 31, 2010, 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. The Board has approved
our hedging greater than 50% of forecast 2011 production. See
Note 9 for the detail of the asset and liability values of
the following derivatives.
62
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Remaining
|
|
|
|
|
|
Fair Value -
|
|
|
Reference
|
|
Contract
|
|
Volume -
|
|
Average
|
|
December 31,
|
Type
|
|
Price
|
|
Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
Asset/
|
|
|
|
|
|
|
|
|
|
|
(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
170,000
|
|
|
$
|
5.08
|
|
|
$
|
57,558
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
195,000
|
|
|
$
|
5.81
|
|
|
$
|
75,987
|
|
Swap
|
|
NYMEX
|
|
Summer 2011
|
|
|
70,000
|
|
|
$
|
4.50
|
|
|
$
|
(272
|
)
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
140,000
|
|
|
$
|
5.00
|
|
|
$
|
(3,271
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to December 31, 2010 and through
February 16, 2011, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Remaining
|
|
|
|
|
|
|
|
|
Reference
|
|
Contract
|
|
Volume -
|
|
Average
|
|
|
Type
|
|
Price
|
|
Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
|
|
Swap
|
|
NYMEX
|
|
Summer 2011
|
|
|
90,000
|
|
|
$
|
4.63
|
|
|
|
|
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
130,000
|
|
|
$
|
5.04
|
|
|
|
|
|
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 Operations for the years ended December 31,
2010, 2009 and 2008 (refer to Note 2 for details of
unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For The Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Natural Gas Commodity Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
116,827
|
|
|
$
|
239,366
|
|
|
$
|
18,991
|
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
|
208,625
|
|
|
|
(92,849
|
)
|
|
|
14,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
325,452
|
|
|
$
|
146,517
|
|
|
$
|
33,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Operations. |
|
|
9.
|
FAIR
VALUE MEASUREMENTS:
|
As required by the Fair Value Measurements and Disclosure Topic
of the FASB Accounting Standards Codification, we define 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. Fair value
measurements are 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 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.
63
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The valuation assumptions utilized to measure the fair value of
the Companys 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, 2010. The company has no derivative
instruments which qualify for cash flow hedge accounting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
133,991
|
|
|
$
|
|
|
|
$
|
133,991
|
|
Long-term derivative asset
|
|
$
|
|
|
|
$
|
2,066
|
|
|
$
|
|
|
|
$
|
2,066
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
718
|
|
|
$
|
|
|
|
$
|
718
|
|
Long-term derivative liability
|
|
$
|
|
|
|
$
|
5,337
|
|
|
$
|
|
|
|
$
|
5,337
|
|
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.
For those non-financial assets and liabilities measured or
disclosed at fair value on a non-recurring basis, primarily our
asset retirement obligation, this respective subtopic of FASB
ASC 820 was effective January 1, 2009. Implementation of
this portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity.
Fair
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. The carrying amount of floating-rate debt
approximates fair value because the interest rates are variable
and reflective of market rates. We use available market data and
valuation methodologies to estimate the fair value of our fixed
rate debt. This disclosure is presented in accordance with FASB
ASC Topic 825, Financial Instruments, and does not impact our
financial position, results of operations or cash flows.
In April 2009, the FASB updated the requirements for interim
disclosures about fair value of financial instruments requiring
an entity to provide disclosures about fair value of financial
instruments in interim financial information. The Company is
required to include disclosures about the fair value of its
financial instruments whenever it issues financial information
for interim reporting periods. In addition, the Company is
required to disclose in the body or in the accompanying notes of
its summarized financial information for interim reporting
periods and in its financial statements for annual reporting
periods, the fair value of all financial instruments for which
it is practicable to estimate that value, whether recognized or
not recognized in the statement of financial position. This
updated requirement for interim disclosures about fair value of
financial instruments is effective for periods ending after
June 15, 2009 and its adoption had no impact on the
Companys results of operations and financial condition but
requires additional disclosures about the fair value of
financial instruments in the financial statements.
64
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.45% Notes due 2015, issued 2008
|
|
$
|
100,000
|
|
|
$
|
108,572
|
|
|
$
|
100,000
|
|
|
$
|
108,128
|
|
7.31% Notes due 2016, issued 2009
|
|
|
62,000
|
|
|
|
72,153
|
|
|
|
62,000
|
|
|
|
72,684
|
|
4.98% Notes due 2017, issued 2010
|
|
|
116,000
|
|
|
|
119,385
|
|
|
|
|
|
|
|
|
|
5.92% Notes due 2018, issued 2008
|
|
|
200,000
|
|
|
|
212,660
|
|
|
|
200,000
|
|
|
|
212,946
|
|
7.77% Notes due 2019, issued 2009
|
|
|
173,000
|
|
|
|
203,051
|
|
|
|
173,000
|
|
|
|
205,609
|
|
5.50% Notes due 2020, issued 2010
|
|
|
207,000
|
|
|
|
206,233
|
|
|
|
|
|
|
|
|
|
4.51% Notes due 2020, issued 2010
|
|
|
315,000
|
|
|
|
284,207
|
|
|
|
|
|
|
|
|
|
5.60% Notes due 2022, issued 2010
|
|
|
87,000
|
|
|
|
84,818
|
|
|
|
|
|
|
|
|
|
4.66% Notes due 2022, issued 2010
|
|
|
35,000
|
|
|
|
30,989
|
|
|
|
|
|
|
|
|
|
5.85% Notes due 2025, issued 2010
|
|
|
90,000
|
|
|
|
87,211
|
|
|
|
|
|
|
|
|
|
4.91% Notes due 2025, issued 2010
|
|
|
175,000
|
|
|
|
152,064
|
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
|
|
|
|
|
|
|
|
|
260,000
|
|
|
|
260,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,560,000
|
|
|
$
|
1,561,343
|
|
|
$
|
795,000
|
|
|
$
|
859,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The consolidated income tax provision is comprised of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current
|
|
$
|
22,285
|
|
|
$
|
23,043
|
|
|
$
|
84,313
|
|
Deferred
|
|
|
236,330
|
|
|
|
(268,179
|
)
|
|
|
156,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision (benefit)
|
|
$
|
258,615
|
|
|
$
|
(245,136
|
)
|
|
$
|
240,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2010, 2009 and 2008, the Company realized tax benefits of
$17.5 million $14.2 million, and $78.8 million,
respectively, attributable to tax deductions associated with the
exercise of stock options. These benefits reduce the amount of
the Companys U.S. federal and state cash tax payments
and are recorded as a reduction of current taxes payable (though
not a reduction of the current provision) and as an increase in
shareholders equity.
The income tax provision (benefit) 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,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Income tax provision (benefit) computed at the U.S. statutory
rate
|
|
$
|
253,076
|
|
|
$
|
(243,666
|
)
|
|
$
|
229,028
|
|
State income tax provision net of federal benefit
|
|
|
3,608
|
|
|
|
(698
|
)
|
|
|
650
|
|
Withholding tax on share repurchase transactions
|
|
|
|
|
|
|
|
|
|
|
5,409
|
|
Foreign tax credit valuation allowance
|
|
|
|
|
|
|
|
|
|
|
1,692
|
|
Canadian net operating loss valuation allowance
|
|
|
(677
|
)
|
|
|
|
|
|
|
|
|
Tax effect of rate change
|
|
|
1,939
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
669
|
|
|
|
(772
|
)
|
|
|
3,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
258,615
|
|
|
$
|
(245,136
|
)
|
|
$
|
240,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During 2008, the Company incurred U.S. withholding taxes of
$5.4 million in connection with the repurchase of shares of
its common stock.
The tax effects of temporary differences that give rise to
significant components of the Companys deferred tax assets
and liabilities for continuing operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Deferred tax assets current:
|
|
|
|
|
|
|
|
|
Derivative instruments, net
|
|
$
|
255
|
|
|
$
|
10,753
|
|
Other
|
|
|
4,627
|
|
|
|
1,472
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets current
|
|
$
|
4,882
|
|
|
$
|
12,225
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities current:
|
|
|
|
|
|
|
|
|
Derivative instruments, net
|
|
$
|
(47,567
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities current
|
|
$
|
(47,567
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax (liability) asset current
|
|
$
|
(42,685
|
)
|
|
$
|
12,225
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets non-current:
|
|
|
|
|
|
|
|
|
U.S. federal tax credit carryforwards
|
|
|
13,714
|
|
|
|
15,162
|
|
Canadian net operating loss carryforwards
|
|
|
|
|
|
|
514
|
|
Derivative instruments, net
|
|
|
1,161
|
|
|
|
16,844
|
|
Incentive compensation/other, net
|
|
|
14,745
|
|
|
|
10,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,620
|
|
|
|
43,450
|
|
Valuation allowance Foreign Tax Credit (FTC)
|
|
|
(1,692
|
)
|
|
|
(1,692
|
)
|
Valuation allowance (Canadian Net Operating Loss (NOL))
|
|
|
|
|
|
|
(514
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets non-current
|
|
$
|
27,928
|
|
|
$
|
41,244
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities non-current:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
|
(448,298
|
)
|
|
|
(279,441
|
)
|
Other
|
|
|
(341
|
)
|
|
|
(1,020
|
)
|
|
|
|
|
|
|
|
|
|
Net non-current tax liabilities
|
|
$
|
(448,639
|
)
|
|
$
|
(280,461
|
)
|
|
|
|
|
|
|
|
|
|
Net non-current tax liability
|
|
$
|
(420,711
|
)
|
|
$
|
(239,217
|
)
|
|
|
|
|
|
|
|
|
|
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 the standard related to
accounting for uncertain tax positions. The amount of
unrecognized tax benefits did not change as of December 31,
2010.
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.
66
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2007.
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.
As of December 31, 2010, the Company had approximately
$12.0 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, 2010,
the Company has $1.7 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. Therefore, a valuation allowance has been
placed on the remaining foreign tax credit carryforwards.
The Company had Canadian net operating loss carryforwards of
approximately $2.7 million as of December 31, 2009.
The unexpired portion of the Canadian net operating loss
carryforward was fully utilized in 2010, and thus the valuation
allowance at December 31, 2009 has been removed and no
deferred tax asset related to the Canadian net operating loss
exists as of December 31, 2010.
The undistributed earnings of the Companys
U.S. subsidiaries are considered to be indefinitely
invested outside of Canada. Accordingly, no provision for
Canadian income taxes
and/or
withholding taxes has been provided thereon.
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,
2010 and 2009, the Company also recorded a total deferred tax
liability of $46.2 million and a deferred tax asset of
$27.6 million, respectively, attributable to the unrealized
gains and losses recorded in the statement of operations.
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 100% 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 Companys
contribution was $1.2 million, $1.1 million and
$0.9 million for the years ended December 31, 2010,
2009 and 2008, respectively.
|
|
12.
|
COMMITMENTS
AND CONTINGENCIES:
|
Transportation contract. The Company is 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. REX begins at the Opal Processing Plant in southwest
Wyoming and traverses Wyoming and several other states to an
ultimate terminus in eastern Ohio. The Companys commitment
involves a capacity of 200 MMMBtu per day of natural gas
for a term of 10 years commencing in November 2009, 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.
Subsequently, the Company entered into agreements to secure an
additional capacity of 50 MMMBtu per day on the REX
pipeline system, beginning in January 2012 through December
2018. This additional capacity will provide the Company with the
ability to move additional volumes from its producing wells in
Wyoming to markets in the eastern U.S.
67
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company currently projects that demand charges related to
the remaining term of the contract will total approximately
$789.3 million.
Drilling contracts. As of December 31,
2010, the Company had committed to drilling obligations with
certain rig contractors totaling $98.4 million
($69.4 million due in 2011, $28.9 million due in one
to two years). The commitments expire in 2012 and were entered
into to fulfill the Companys drilling program initiatives
in Wyoming.
Office space lease. The Companys
maintains office space in Colorado, Texas, Wyoming and
Pennsylvania with total remaining commitments for office leases
of $2.5 million at December 31, 2010
($0.8 million in 2011, $1.6 million in one to three
years).
During the years ended December 31, 2010, 2009 and 2008,
the Company recognized expense associated with its office leases
in the amount of $0.8 million, $0.9 million, and
$0.7 million, respectively.
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.
|
CONCENTRATION
OF CREDIT RISK:
|
The Companys financial instruments that are exposed to
concentrations of credit risk consist primarily of trade
receivables and commodity derivative contracts associated with
the Companys hedging program. The Companys revenues
related to natural gas sales are derived principally from a
diverse group of companies, including major energy companies,
natural gas utilities, oil refiners, pipeline companies, local
distribution companies, financial institutions and end-users in
various industries.
Concentrations of credit risk with respect to receivables is
limited due to the large number of customers and their
dispersion across geographic areas. Commodity-based contracts
expose the Company to the credit risk of nonperformance by the
counterparty to the contracts. This exposure is diversified
primarily among ten major investment grade institutions.
The Company maintains credit policies intended to mitigate the
risk of uncollectible accounts receivable related to the sale of
natural gas, condensate as well as its commodity derivative
positions. The Company performs a credit analysis of each of its
customers prior to making any sales to new customers or
increasing extension of credit for existing customers. Based
upon this credit analysis, the Company may require a standby
letter of credit or a financial guarantee. The Company did not
have any outstanding, uncollectible accounts for its natural gas
or condensate sales, nor derivative settlements sales at
December 31, 2010.
A significant counterparty is defined as one that individually
accounts for 10% or more of the Companys total revenues
during the year. In 2010, the Company had no single customer
that represented 10% or more of its total sales.
FASB ASC Topic 855, Subsequent Events (FASB
ASC 855), sets forth principles and requirements to
be applied to the accounting for and disclosure of subsequent
events. FASB ASC 855 sets forth the period after the
balance sheet date during which management shall evaluate events
or transactions that may occur for potential recognition or
disclosure in the financial statements, the circumstances under
which events or transactions occurring after the balance sheet
date shall be recognized in the financial statements and the
required disclosures about events or transactions that occurred
after the balance sheet date. The FASB issued ASU
No. 2010-09,
Subsequent Events (FASB ASC 855), Amendments to Certain
Recognition and Disclosure Requirements, on
February 24, 2010, in an effort to remove some
contradictions between the requirements of U.S. GAAP and
the SECs filing rules. The amendments remove the
requirement that public companies disclose the date through
which
68
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
their financial statements in both issued and revised financial
statements. The Company has evaluated the period subsequent to
December 31, 2010 for events that did not exist at the
balance sheet date but arose after that date and determined that
no subsequent events arose that should be disclosed in order to
keep the financial statements from being misleading.
|
|
15.
|
SUMMARIZED
QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
1st Quarter
|
|
|
2nd Quarter
|
|
|
3rd Quarter
|
|
|
4th Quarter
|
|
|
Total
|
|
|
Revenues from continuing operations
|
|
$
|
273,124
|
|
|
$
|
228,388
|
|
|
$
|
240,374
|
|
|
$
|
237,500
|
|
|
$
|
979,386
|
|
Gain (loss) on commodity derivatives
|
|
|
181,351
|
|
|
|
14,566
|
|
|
|
150,186
|
|
|
|
(20,651
|
)
|
|
|
325,452
|
|
Expenses from continuing operations
|
|
|
124,260
|
|
|
|
125,999
|
|
|
|
128,489
|
|
|
|
144,342
|
|
|
|
523,090
|
|
Interest expense
|
|
|
11,718
|
|
|
|
11,437
|
|
|
|
11,382
|
|
|
|
14,495
|
|
|
|
49,032
|
|
Litigation expense
|
|
|
|
|
|
|
9,902
|
|
|
|
|
|
|
|
|
|
|
|
9,902
|
|
Other income (expense), net
|
|
|
151
|
|
|
|
22
|
|
|
|
12
|
|
|
|
75
|
|
|
|
260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax provision
|
|
|
318,648
|
|
|
|
95,638
|
|
|
|
250,701
|
|
|
|
58,087
|
|
|
|
723,074
|
|
Income tax provision
|
|
|
116,272
|
|
|
|
34,145
|
|
|
|
88,059
|
|
|
|
20,139
|
|
|
|
258,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
202,376
|
|
|
$
|
61,493
|
|
|
$
|
162,642
|
|
|
$
|
37,948
|
|
|
$
|
464,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic
|
|
$
|
1.33
|
|
|
$
|
0.40
|
|
|
$
|
1.07
|
|
|
$
|
0.25
|
|
|
$
|
3.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share fully diluted
|
|
$
|
1.31
|
|
|
$
|
0.40
|
|
|
$
|
1.05
|
|
|
$
|
0.25
|
|
|
$
|
3.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
1st Quarter
|
|
|
2nd Quarter
|
|
|
3rd Quarter
|
|
|
4th Quarter
|
|
|
Total
|
|
|
Revenues from continuing operations
|
|
$
|
167,953
|
|
|
$
|
130,341
|
|
|
$
|
155,164
|
|
|
$
|
213,304
|
|
|
$
|
666,762
|
|
Gain (loss) on commodity derivatives
|
|
|
206,428
|
|
|
|
(60,698
|
)
|
|
|
(55,428
|
)
|
|
|
56,215
|
|
|
|
146,517
|
|
Expenses from continuing operations
|
|
|
116,975
|
|
|
|
98,264
|
|
|
|
104,131
|
|
|
|
113,043
|
|
|
|
432,413
|
|
Write down of proved oil and gas properties
|
|
|
1,037,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,037,000
|
|
Interest expense
|
|
|
7,297
|
|
|
|
9,897
|
|
|
|
9,744
|
|
|
|
10,229
|
|
|
|
37,167
|
|
Other (expense) income , net
|
|
|
(2,613
|
)
|
|
|
(505
|
)
|
|
|
193
|
|
|
|
37
|
|
|
|
(2,888
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income tax (benefit) provision
|
|
|
(789,504
|
)
|
|
|
(39,023
|
)
|
|
|
(13,946
|
)
|
|
|
146,284
|
|
|
|
(696,189
|
)
|
Income tax (benefit) provision
|
|
|
(276,916
|
)
|
|
|
(13,497
|
)
|
|
|
(5,616
|
)
|
|
|
50,893
|
|
|
|
(245,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(512,588
|
)
|
|
$
|
(25,526
|
)
|
|
$
|
(8,330
|
)
|
|
$
|
95,391
|
|
|
$
|
(451,053
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
(3.39
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
0.63
|
|
|
$
|
(2.98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share fully diluted
|
|
$
|
(3.39
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
0.62
|
|
|
$
|
(2.98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16.
|
DISCLOSURE
ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
|
The following information about the Companys oil and
natural gas producing activities is presented in accordance with
FASB ASC Topic 932, Oil and Gas Reserve Estimation and
Disclosures:
On January 6, 2010, the FASB issued an ASU updating oil and
gas reserve estimation and disclosure requirements. The ASU
amends FASB ASC 932 to align the reserve calculation and
disclosure requirements with
69
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the requirements in SEC Release
No. 33-8995.
SEC Release
No. 33-8995,
amends oil and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
revising oil and gas reserves estimation and disclosure
requirements. The rules include changes to pricing used to
estimate reserves, the ability to include non-traditional
resources in reserves, the use of new technology for determining
reserves and permitting disclosure of probable and possible
reserves. 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.
Our policies and practices regarding internal controls over the
recording of reserves is structured to objectively and
accurately estimate our oil and gas reserves quantities and
present values in compliance with the SECs regulations and
GAAP. The Director Reservoir Engineering &
Planning is primarily responsible for overseeing the preparation
of the Companys reserve estimates by our independent
engineers, Netherland, Sewell & Associates, Inc. The
Director has a Bachelor and Master of Science degree in
Petroleum Engineering and is a licensed Professional Engineer
with over 15 years of experience. The Companys
internal controls over reserve estimates include reconciliation
and review controls, including an independent internal review of
assumptions used in the estimation.
All of the information regarding reserves in this annual report
is derived from the report of Netherland, Sewell &
Associates, Inc. The report of Netherland, Sewell &
Associates, Inc. is included as an Exhibit to this annual
report. The principal engineer at Netherland, Sewell &
Associates, Inc. responsible for preparing our reserve estimates
has a Bachelor of Science degree in Mechanical Engineering and
is a licensed Professional Engineer with over 25 years of
experience, including significant experience throughout the
Rocky Mountain basins.
In accordance with our three-year planning and budgeting cycle,
proved undeveloped reserves included in the current, as well as
previous, reserve estimates include only economic well locations
that are forecast to be drilled within a three-year period. As a
result of our self-imposed three-year limit on proved
undeveloped reserves inventory, we have not booked any proved
undeveloped reserves beyond five years.
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.
In estimating proved reserves and future revenue as of
December 31, 2010, the Companys independent reserve
engineer, Netherland, Sewell & Associates, Inc., used
technical and economic data including, but not limited to, well
logs, geologic maps, seismic data, well test data, production
data, historical price and cost information and property
ownership interests. The reserves were estimated using
deterministic methods; these estimates were prepared in
accordance with generally accepted petroleum engineering and
evaluation principles. Standard engineering and geoscience
methods, such as performance analysis, volumetric analysis and
analogy, that were considered to be appropriate and necessary to
establish reserve quantities and reserve categorization that
conform to SEC definitions and guidelines, were also used. In
evaluating the information at their disposal, Netherland,
Sewell & Associates, Inc. excluded from their
consideration all matters as to which the controlling
interpretation may be legal or accounting, rather than
engineering and geoscience. As in all aspects of oil and natural
gas evaluation, there are uncertainties inherent in the
interpretation of engineering and geoscience data; therefore,
Netherland, Sewell & Associates, Inc.s
conclusions necessarily represent only informed professional
judgment.
The following unaudited tables as of December 31, 2010,
2009, and 2008 are based upon estimates prepared by Netherland,
Sewell & Associates, Inc. in reports dated
January 31, 2011, January 27, 2010, and
February 6, 2009, 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, 2010, 2009 and 2008. All such reserves are
located in the Green River Basin in Wyoming and the Appalachian
Basin of Pennsylvania.
Since January 1, 2010, 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.
70
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
B.
|
ANALYSES
OF CHANGES IN PROVEN RESERVES:
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
Reserves, December 31, 2007
|
|
|
22,832
|
|
|
|
2,842,655
|
|
Extensions, discoveries and additions
|
|
|
6,536
|
|
|
|
803,200
|
|
Production
|
|
|
(1,122
|
)
|
|
|
(138,564
|
)
|
Revisions
|
|
|
(1,239
|
)
|
|
|
(151,503
|
)
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2008
|
|
|
27,007
|
|
|
|
3,355,788
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and additions
|
|
|
5,902
|
|
|
|
758,659
|
|
Production
|
|
|
(1,320
|
)
|
|
|
(172,189
|
)
|
Revisions
|
|
|
(2,404
|
)
|
|
|
(205,657
|
)
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2009
|
|
|
29,185
|
|
|
|
3,736,601
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and additions
|
|
|
7,369
|
|
|
|
1,055,047
|
|
Production
|
|
|
(1,334
|
)
|
|
|
(205,613
|
)
|
Revisions
|
|
|
(3,536
|
)
|
|
|
(385,880
|
)
|
|
|
|
|
|
|
|
|
|
Reserves, December 31, 2010
|
|
|
31,684
|
|
|
|
4,200,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
Proved:
|
|
|
|
|
|
|
|
|
Developed
|
|
|
8,764
|
|
|
|
1,084,224
|
|
Undeveloped
|
|
|
14,068
|
|
|
|
1,758,431
|
|
|
|
|
|
|
|
|
|
|
Total Proved 2007
|
|
|
22,832
|
|
|
|
2,842,655
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
11,462
|
|
|
|
1,412,562
|
|
Undeveloped
|
|
|
15,546
|
|
|
|
1,943,225
|
|
|
|
|
|
|
|
|
|
|
Total Proved 2008
|
|
|
27,007
|
|
|
|
3,355,788
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
11,627
|
|
|
|
1,541,813
|
|
Undeveloped
|
|
|
17,558
|
|
|
|
2,194,788
|
|
|
|
|
|
|
|
|
|
|
Total Proved 2009
|
|
|
29,185
|
|
|
|
3,736,601
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
11,013
|
|
|
|
1,678,697
|
|
Undeveloped
|
|
|
20,671
|
|
|
|
2,521,458
|
|
|
|
|
|
|
|
|
|
|
Total Proved 2010
|
|
|
31,684
|
|
|
|
4,200,155
|
|
|
|
|
|
|
|
|
|
|
During 2010, substantially all of our extensions and discoveries
in the proved developed category were attributable to wells
drilled in 2010, and substantially all of our extensions and
discoveries in the proved undeveloped category were attributable
to our ongoing drilling activities and its associated effect on
our proved undeveloped reserves estimates.
The following table sets forth a standardized measure of the
estimated discounted future net cash flows attributable to the
Companys proved natural gas reserves. Natural gas prices
have fluctuated widely in recent years. The calculated weighted
average sales prices utilized for the purposes of estimating the
Companys proved reserves and future net revenues at
December 31, 2010 and 2009 was $4.05 per Mcf and $3.04 per
Mcf, respectively, for natural gas and $68.93 per barrel and
$52.18 per barrel, respectively, for condensate, based upon the
average of the
71
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
price in effect on the first day of the month for the preceding
twelve month period. The calculated weighted average sales
prices utilized for the purposes of estimating the
Companys proved reserves and future net revenues was $4.71
per Mcf of natural gas at December 31, 2008, utilizing
prices in effect on the last day of the year. The calculated
weighted average oil price at December 31, 2008 for
condensate was $30.10 per barrel, utilizing prices in effect on
the last day of the year.
The future production and development costs represent the
estimated future expenditures to be incurred in developing and
producing the proved reserves, assuming continuation of existing
economic conditions. Future income tax expense was computed by
applying statutory income tax rates to the difference between
pretax net cash flows relating to the Companys proved
reserves and the tax basis of proved properties and available
operating loss carryovers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Future cash inflows
|
|
$
|
19,186,072
|
|
|
$
|
12,870,816
|
|
|
$
|
16,608,609
|
|
Future production costs
|
|
|
(5,253,509
|
)
|
|
|
(3,916,222
|
)
|
|
|
(4,217,034
|
)
|
Future development costs
|
|
|
(3,052,843
|
)
|
|
|
(2,249,993
|
)
|
|
|
(2,351,312
|
)
|
Future income taxes
|
|
|
(3,198,413
|
)
|
|
|
(1,998,114
|
)
|
|
|
(3,222,246
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
7,681,307
|
|
|
|
4,706,487
|
|
|
|
6,818,017
|
|
Discount at 10%
|
|
|
(4,155,739
|
)
|
|
|
(2,679,787
|
)
|
|
|
(3,800,331
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
3,525,568
|
|
|
$
|
2,026,700
|
|
|
$
|
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.
|
|
D.
|
SUMMARY
OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Standardized measure, beginning
|
|
$
|
2,026,700
|
|
|
$
|
3,017,686
|
|
|
$
|
3,869,402
|
|
Net revisions of previous quantity estimates
|
|
|
(592,919
|
)
|
|
|
(216,946
|
)
|
|
|
(247,791
|
)
|
Extensions, discoveries and other changes
|
|
|
1,601,154
|
|
|
|
782,763
|
|
|
|
1,313,391
|
|
Changes in future development costs
|
|
|
(606,449
|
)
|
|
|
(103,056
|
)
|
|
|
(327,325
|
)
|
Sales of oil and gas, net of production costs
|
|
|
(787,409
|
)
|
|
|
(513,958
|
)
|
|
|
(890,157
|
)
|
Net change in prices and production costs
|
|
|
1,501,002
|
|
|
|
(1,772,644
|
)
|
|
|
(1,971,128
|
)
|
Development costs incurred during the period that reduce future
development costs
|
|
|
404,402
|
|
|
|
395,092
|
|
|
|
503,582
|
|
Accretion of discount
|
|
|
288,713
|
|
|
|
444,387
|
|
|
|
584,119
|
|
Net changes in production rates and other
|
|
|
297,957
|
|
|
|
(572,380
|
)
|
|
|
(362,018
|
)
|
Net change in income taxes
|
|
|
(607,583
|
)
|
|
|
565,756
|
|
|
|
545,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate changes
|
|
|
1,498,868
|
|
|
|
(990,986
|
)
|
|
|
(851,716
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, ending
|
|
$
|
3,525,568
|
|
|
$
|
2,026,700
|
|
|
$
|
3,017,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
72
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates
of different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an
estimate may justify revision of such estimates. Accordingly,
reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. Further, the
estimated future net revenues from proved reserves and the
present value thereof are based upon certain assumptions,
including geologic success, prices, future production levels and
costs that may not prove correct over time. Predictions of
future production levels are subject to great uncertainty, and
the meaningfulness of such estimates is highly dependent upon
the accuracy of the assumptions upon which they are based.
Historically, oil and natural gas prices have fluctuated widely.
|
|
E.
|
COSTS
INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs unproved properties, net
|
|
$
|
472,339
|
|
|
$
|
33,176
|
|
|
$
|
18,766
|
|
Exploration
|
|
|
249,029
|
|
|
|
102,217
|
|
|
|
395,970
|
|
Development
|
|
|
855,110
|
|
|
|
605,958
|
|
|
|
534,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,576,478
|
|
|
$
|
741,351
|
|
|
$
|
949,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F.
|
RESULTS
OF OPERATIONS FOR OIL AND GAS PRODUCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
|
$
|
979,386
|
|
|
$
|
666,762
|
|
|
$
|
1,084,400
|
|
Production expenses
|
|
|
(191,978
|
)
|
|
|
(152,804
|
)
|
|
|
(194,243
|
)
|
Depletion and depreciation
|
|
|
(241,796
|
)
|
|
|
(201,826
|
)
|
|
|
(184,795
|
)
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
(1,037,000
|
)
|
|
|
|
|
Income taxes
|
|
|
(193,692
|
)
|
|
|
254,429
|
|
|
|
(235,095
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
351,920
|
|
|
$
|
(470,439
|
)
|
|
$
|
470,267
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G.
|
CAPITALIZED
COSTS RELATING TO OIL AND GAS PRODUCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and
|
|
|
|
|
|
|
|
|
environmental costs
|
|
$
|
4,575,222
|
|
|
$
|
3,544,519
|
|
Less: accumulated depletion, depreciation and amortization
|
|
|
(1,985,799
|
)
|
|
|
(1,749,916
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,589,423
|
|
|
|
1,794,603
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized
|
|
|
486,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,075,670
|
|
|
$
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
73
|
|
Item 9.
|
Change
in and Disagreements with Accountants on Accounting and
Financial Disclosures.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Managements
Report on Assessment of Internal Control Over Financial
Reporting
Managements Report on Assessment of Internal Control Over
Financial Reporting is included on page 45 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, 2010 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, 2010. The evaluation
considered the procedures designed to ensure that information
required to be disclosed by us in the reports filed or submitted
by us under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified in the SECs
rules and forms and communicated to our management as
appropriate to allow timely decisions regarding required
disclosure.
|
|
Item 9B.
|
Other
Information.
|
None.
Part III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2010.
The Company has adopted a code of ethics that applies to the
Companys Chief Executive Officer, Chief Financial Officer
and Chief Accounting Officer. The full text of such code of
ethics is posted on the Companys website at
www.ultrapetroleum.com, and is available free of charge in print
to any shareholder who requests it. Requests for copies should
be addressed to the Secretary at 363 North Sam Houston Parkway
East, Suite 1200, Houston, Texas 77060.
|
|
Item 11.
|
Executive
Compensation.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2010.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2010.
74
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2010.
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
The information required by this item is incorporated herein by
reference to the Companys definitive proxy statement,
which will be filed not later than 120 days after
December 31, 2010.
Part IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules.
|
The following documents are filed as part of this report:
1. Financial Statements: See Item 8.
2. Financial Statement Schedules: None.
3. Exhibits. The following Exhibits are
filed herewith pursuant to Rule 601 of the
Regulation S-K
or are incorporated by reference to previous filings.
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp. (incorporated
by reference to Exhibit 3.1 of the Companys Quarterly
Report on Form 10-Q for the period ended June 30, 2001).
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp. (incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on Form 10-Q
for the period ended June 30, 2001).
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the
Companys 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 Companys 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 Companys 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 Companys
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 Companys 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 Companys 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 Companys 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 Companys 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 Companys Registration
Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on
April 2, 2001).
|
75
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
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 Companys 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 Companys Report on
Form 8-K filed on March 6, 2008).
|
|
10
|
.10
|
|
First Supplement dated March 5, 2009 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
March 5, 2009).
|
|
10
|
.11
|
|
Second Supplement dated January 28, 2010 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
January 28, 2010).
|
|
10
|
.12
|
|
Third Supplement dated October 12, 2010 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
October 12, 2010).
|
|
10
|
.13
|
|
Sale and Purchase Agreement dated December 18, 2009 between
Ultra Resources, Inc. and NCL Appalachian Partners, L.P., Locin
Oil Corporation, Lyons Petroleum Reserves, Inc., MC Reserves,
Inc., (incorporated by reference to Exhibit 1.1 of the
Companys Report on Form 8-K filed on December 23, 2009).
|
|
21
|
.1
|
|
Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Companys 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 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.
|
|
*99
|
.1
|
|
Reserve Report Summary prepared by Netherland, Sewell &
Associates, Inc. as of December 31, 2010.
|
|
*101
|
.INS
|
|
XBRL Instance Document
|
|
*101
|
.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
*101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
*101
|
.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
*101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
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 24, 2011
76
Pursuant to the requirements of the Securities and Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Michael
D. Watford
Michael
D. Watford
|
|
Chairman of the Board,
Chief Executive Officer, and President (principal executive
officer)
|
|
February 24, 2011
|
|
|
|
|
|
/s/ Marshall
D. Smith
Marshall
D. Smith
|
|
Chief Financial Officer
(principal financial officer)
|
|
February 24, 2011
|
|
|
|
|
|
/s/ Garland
R. Shaw
Garland
R. Shaw
|
|
Corporate Controller
(principal accounting officer)
|
|
February 24, 2011
|
|
|
|
|
|
/s/ W.
Charles Helton
W.
Charles Helton
|
|
Director
|
|
February 24, 2011
|
|
|
|
|
|
/s/ Stephen
J. McDaniel
Stephen
J. McDaniel
|
|
Director
|
|
February 24, 2011
|
|
|
|
|
|
/s/ Robert
E. Rigney
Robert
E. Rigney
|
|
Director
|
|
February 24, 2011
|
|
|
|
|
|
/s/ Roger
A. Brown
Roger
A. Brown
|
|
Director
|
|
February 24, 2011
|
EXHIBIT INDEX
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp. (incorporated
by reference to Exhibit 3.1 of the Companys Quarterly
Report on Form 10-Q for the period ended June 30, 2001).
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp. (incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on Form 10-Q
for the period ended June 30, 2001).
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the
Companys 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 Companys 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 Companys 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 Companys
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 Companys 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 Companys Report on Form 8-K filed on February 9,
2006).
|
77
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.5
|
|
Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by
reference to Exhibit 99.1 of the Companys Registration
Statement on Form S-8 (Reg. No. 333-132443), filed with the SEC
on March 15, 2006).
|
|
10
|
.6
|
|
Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by
reference to Exhibit 99.1 of the Companys Registration
Statement on Form S-8 (Reg. No. 333-13278), filed with the SEC
on March 15, 2001).
|
|
10
|
.7
|
|
Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by
reference to Exhibit 99.1 of the Companys Registration
Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on
April 2, 2001).
|
|
10
|
.8
|
|
Employment Agreement between Ultra Petroleum Corp. and Michael
D. Watford dated August 6, 2007 (incorporated by reference from
Exhibit 10.2 of the Companys 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 Companys Report on
Form 8-K filed on March 6, 2008).
|
|
10
|
.10
|
|
First Supplement dated March 5, 2009 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
March 5, 2009).
|
|
10
|
.11
|
|
Second Supplement dated January 28, 2010 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
January 28, 2010).
|
|
10
|
.12
|
|
Third Supplement dated October 12, 2010 to Master Note Purchase
Agreement dated March 6, 2008 (incorporated by reference to
Exhibit 10.1 of the Companys Report on Form 8-K filed on
October 12, 2010).
|
|
10
|
.13
|
|
Sale and Purchase Agreement dated December 18, 2009 between
Ultra Resources, Inc. and NCL Appalachian Partners, L.P., Locin
Oil Corporation, Lyons Petroleum Reserves, Inc., MC Reserves,
Inc., (incorporated by reference to Exhibit 1.1 of the
Companys Report on Form 8-K filed on December 23, 2009).
|
|
21
|
.1
|
|
Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Companys 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 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.
|
|
*99
|
.1
|
|
Reserve Report Summary prepared by Netherland, Sewell &
Associates, Inc. as of December 31, 2010.
|
|
*101
|
.INS
|
|
XBRL Instance Document
|
|
*101
|
.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
*101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
*101
|
.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
*101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
78