form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
x ANNUAL REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year ended December 31, 2007
or
¨ TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
Commission
File Number 000-07246
PETROLEUM
DEVELOPMENT CORPORATION
(Exact name of registrant as specified
in its charter)
Nevada
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95-2636730
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(State
of Incorporation)
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(I.R.S.
Employer Identification No.)
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120
Genesis Boulevard
Bridgeport,
West Virginia 26330
(Address
of principal executive offices) (Zip Code)
Registrant's
telephone number, including area code: (304) 842-3597
Securities
registered pursuant to Section 12(b) of the Act:
Title
of Each Class
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Name
of Each Exchange on Which Registered
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Common
Stock, par value $.01 per share
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NASDAQ
Global Select Market
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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 ¨ No
x
Indicate by check mark if
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months and (2)
has been subject to such filing requirements for the past 90
days. Yes x
No o
Indicate by check mark if
disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form
10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or non-accelerated file. See definition of
"accelerated filer and larger accelerated filer" in Rule 12b-2 of the Exchange
Act:
Large
accelerated filer ¨
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Accelerated
filer x
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Non-accelerated
filer ¨
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Smaller
reporting company ¨
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Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes ¨ No
x
The
aggregate market value of our common stock held by non-affiliates on June 30,
2007, was $679,172,437 (based on the then closing price of $47.48).
As
of March 14, 2008, there were 14,851,234 shares of our common stock
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
The
information required by Part III of this Form is incorporated by reference to
our definitive proxy statement to be filed pursuant to Regulation 14A for our
2008 Annual Meeting of Shareholders.
PETROLEUM
DEVELOPMENT CORPORATION
2007
ANNUAL REPORT ON FORM 10-K
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PART
I
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Page
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Item
1.
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3
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Item1A.
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18
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Item1B.
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26
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Item
2.
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26
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Item
3.
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27
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Item
4.
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27
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PART
II
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Item
5.
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27
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Item
6.
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30
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Item
7.
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31
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Item
7A.
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56
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Item
8.
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58
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Item
9.
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58
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Item
9A.
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60
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Item
9B.
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61
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PART
III
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Item
10.
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61
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Item
11.
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61
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Item
12.
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61
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Item
13.
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62
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Item
14.
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62
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PART
IV
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Item
15.
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63
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64
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65
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PART I
REFERENCES
TO THE REGISTRANT
Unless
the context otherwise requires, references to "PDC", "the Company", "we", "us",
"our", "ours", or "ourselves" in this report refer to the registrant, Petroleum
Development Corporation, together with our subsidiaries, proportionate share of
our sponsored drilling partnerships and an entity in which we have a controlling
interest.
SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
report contains forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934 regarding our business, financial condition, results of operations and
prospects. Words such as expects, anticipates, intends, plans,
believes, seeks, estimates and similar expressions or variations of such words
are intended to identify forward-looking statements herein, which include
statements of estimated oil and gas
production and reserves, drilling plans, future cash flows, anticipated
liquidity, anticipated capital expenditures and our management’s strategies,
plans and objectives. However, these are not the exclusive means of
identifying forward-looking statements herein. Although
forward-looking statements contained in this report reflect our good faith
judgment, such statements can only be based on facts and factors currently known
to us. Consequently, forward-looking statements are inherently
subject to risks and uncertainties, including risks and uncertainties incidental
to the exploration for, and the acquisition, development, production and
marketing of, natural gas and oil, and actual outcomes may differ materially
from the results and outcomes discussed in the forward-looking
statements. Important factors that could cause actual results to
differ materially from the forward looking statements include, but are not
limited to:
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changes
in production volumes, worldwide demand, and commodity prices for
petroleum natural resources;
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the
timing and extent of our success in discovering, acquiring, developing and
producing natural gas and oil
reserves;
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our
ability to acquire leases, drilling rigs, supplies and services at
reasonable prices;
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the
availability of capital to us;
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risks
incident to the drilling and operation of natural gas and oil
wells;
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future
production and development costs;
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the
effect of existing and future laws, governmental regulations and the
political and economic climate of the United
States;
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the
effect of natural gas and oil derivatives
activities;
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conditions
in the capital markets; and
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losses
possible from pending or future
litigation.
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Further,
we urge you to carefully review and consider the disclosures made in this
report, including the risks and uncertainties that may affect our business as
described herein under Item 1A, Risk Factors, and our other
filings with the Securities and Exchange Commission, or SEC. We
caution you not to place undue reliance on forward-looking statements, which
speak only as of the date of this report. We undertake no obligation
to update publicly any forward-looking statements in order to reflect any event
or circumstance occurring after the date of this report or currently unknown
facts or conditions or the occurrence of unanticipated events.
General
We are an
independent energy company engaged in the exploration, development, production
and marketing of oil and natural gas. Since we began oil and gas
operations in 1969, we have grown through drilling and development activities,
acquisitions of producing natural gas and oil wells and the expansion of our
natural gas marketing activities.
As of
December 31, 2007, we owned interests in approximately 4,354 gross wells
located in the Rocky Mountain Region and the Appalachian and Michigan Basins
with 686 billion cubic feet equivalent, or Bcfe, of net proved
reserves, of which 86.6% was natural gas and 13.4% was oil.
During
2007, our share of production was 28 Bcfe, averaging 76.6 MMcfe per day, a 65%
increase over 46.4 MMcfe per day produced in 2006. We replaced our
2007 production with 391 Bcfe of new proved reserves, net of dispositions, for a
reserve replacement rate of 1,397%. Reserve replacement through the
drillbit was 256 Bcfe, or 914% of production, and reserve replacement
through acquisitions was 135 Bcfe, or 483% of production. Proved reserves grew
112% during 2007, from 323 Bcfe to 686 Bcfe, of which 54% were proved developed
reserves.
We make
available free of charge on our website at www.petd.com our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K, and any amendments to these reports as soon as reasonably practicable after
we electronically file these reports with, or furnish them to, the
SEC. We will also make available to any shareholder, without charge,
a copy of our Annual Report on Form 10-K, or any other filing, as filed with the
SEC, by mail. For a mailed copy of a report, you may contact
Petroleum Development Corporation, Investor Relations and Communications
Department, P.O. Box 26, Bridgeport, WV 26330, or call toll free (800)
624-3821.
In
addition to our SEC filings, other information, including our press releases,
Bylaws, Committee Charters, Code of Business Conduct and Ethics, Shareholder
Communication Policy, Board Nomination Procedures and the Whistleblower and
Qualified Legal Compliance Committee Hotline, is also available at our
website.
Business
Strategy
Our
primary objective is to continue to grow our reserves, production, net income
and cash flow. To achieve meaningful increases in these key areas, we
maintain an active drilling program that focuses on low risk development of our
oil and natural gas reserves, limited exploratory drilling and the acquisition
of producing properties with significant development potential.
Drill
and Develop
Our
acreage holdings include positions in the Rocky Mountain Region and the
Appalachian, Michigan and Fort Worth Basins. In the Rocky Mountain
Region, we focus on developmental drilling in Northeastern Colorado, or NECO,
the Wattenberg Field (both located in the DJ Basin), the Grand Valley Field,
Piceance Basin, and additional limited development in Burke County, North
Dakota. We drilled 349 gross wells in 2007, compared to 231 gross
wells in 2006. In addition, we seek to maximize the value of our
existing wells through a program of well recompletions and refractures. During
2007, we recompleted and/or refractured a total of 181 wells compared to
43 in 2006.
We
believe that we will be able to continue to drill a substantial number of new
wells on our current undeveloped properties. As of December 31, 2007,
we had leases or other development rights to approximately 200,000 acres, of
which approximately 164,000 acres, or 82%, were in the Rocky Mountain
Region. We plan to drill approximately 360 gross, 330 net, wells in
2008, excluding exploratory wells. We also plan to recomplete
approximately 100 gross Wattenberg Field wells (Colorado) and 30
gross wells in the Appalachian Basin during 2008. To support
future development activities we have conducted exploratory drilling in the past
and will continue exploratory drilling plans in 2008. The goal of the
exploration program is to develop several significant new areas for us to
include in our future development drilling activity.
Strategically
Acquire
Our
acquisition efforts focus on producing properties that complement our existing
operations and have a significant undeveloped acreage component. When
weighing potential acquisitions, we prefer properties that have most of their
value in producing wells, behind the pipe reserves or high quality proved
undeveloped locations. Historically, acquisitions have offered
efficiency improvements through economies of scale in management and
administration costs. Since December 2006, we completed three
acquisitions of assets or companies in our core operating area of the Wattenberg
Field in Colorado, in addition to the acquisition of assets in southwestern
Pennsylvania which are in close proximity to our existing assets in the
Appalachian Basin. See Note 2, Acquisitions, to our
consolidated financial statements included in this report.
Manage
Risk
We seek
opportunities to reduce the risk inherent to our business in the oil and natural
gas industry by focusing our drilling efforts primarily on lower risk development wells and
by maintaining positions in several different geographic regions and
markets. Historically we have concentrated on development drilling
and geographical diversification to reduce risk levels associated with natural
gas and oil drilling, production and markets. Currently, a majority
of our proved reserves are located in the Rocky Mountain Region due to our
success in that area over the past several years. However, we benefit
from operational diversity in the Rocky Mountain Region by maintaining
significant activity and production in three separate areas, including the Grand
Valley Field of the Piceance Basin in western Colorado, the Wattenberg Field in
northern Colorado and the NECO area. Additionally, we regularly
review opportunities to further diversify into other regions where we can apply
our operational expertise. We believe development drilling will
remain the foundation of our drilling activities in the future because it is
less risky than exploratory drilling and is likely to generate cash returns more
quickly. However, we expect that future activities may include a
somewhat higher level of exploratory drilling in light of the increasing cost of
accessing high-quality development opportunities and our ability, through
increased size and financial strength, to pursue exploratory activities of
greater significance. Additionally, exploratory activities have the
potential to identify new development opportunities at a cost competitive to the
current cost of acquiring proven locations.
To help
manage the risks associated with the oil and gas industry, we maintain a
conservative financial approach and proactively employ strategies to reduce the
effects of commodity price volatility. We have utilized asset sales
to maximize cash for acquisitions, to reduce debt and preserve our financial
flexibility. We also believe that successful oil and natural gas
marketing is essential to risk management and profitable
operations. To further this goal, we utilize Riley Natural Gas, or
RNG, a wholly-owned subsidiary, to manage the marketing of our oil and natural
gas and our use of oil and natural gas commodity derivatives as risk management
tools. This allows us to maintain better control over third party
risk in sales and derivative activities. We use oil and natural gas
derivatives contracts, or hedges, in order to reduce the effects of volatile
commodity prices. We currently have derivative contracts in place on
a significant portion of our production; however, pursuant to our derivative
policy, all volumes for derivatives contracts are limited to 80% of our
estimated production for the future periods based only on proved developed
producing production as defined in SEC reserve rules. As of March 3,
2008, we had oil and natural gas hedges in place covering 41% of our expected
oil production and 62% of our expected natural gas production in
2008. Further, while our derivative instruments are utilized to hedge
our oil and gas production, they do not qualify for use of hedge accounting
under the terms of SFAS No. 133, resulting in the potential for significant
earnings volatility. See Note 1, Summary of Significant Accounting
Polices – Derivative Financial Instruments, to our consolidated financial
statements included in this report.
Business
Segments
We divide
our operating activities into four segments:
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drilling
and development; and
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well
operations and pipeline income.
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See Note 17, Business Segments, to our
consolidated financial statements.
Oil
and Gas Sales
Our oil
and gas sales segment is our fastest growing business segment and reflects
revenues and expenses from production and sale of natural gas and
oil. We have interests in approximately 4,354 wells ranging from a
few percent to 100%. During 2007, approximately 11% of our oil and
gas sales revenue was generated by the Appalachian Basin, 6% by the Michigan
Basin and 83% by Rocky Mountain Region. As of the end of 2007, our
total proved reserves were located as follows: Appalachian Basin 15%, Michigan
4% and Rocky Mountain Region 81%. The majority of our undeveloped acreage
is in the Rocky Mountain Region, where we focused our 2007 drilling
activities. This segment represents approximately 78% of our income
before income taxes for the year ended December 31, 2007.
Natural
Gas Marketing
Our
natural gas marketing segment is composed of our wholly owned subsidiary, RNG,
through which we purchase, aggregate and resell natural gas produced by us and
others. This allows us to diversify our operations beyond natural gas
drilling and production. Through RNG, we have established
relationships with many of the natural gas producers in the Appalachian Basin
and we have gained significant expertise in the natural gas end-user
market. We do not take speculative positions on commodity prices, and
we employ derivative strategies to manage the financial effects of commodity
price volatility. Our natural gas marketing segment represented
approximately 7% of our income before income taxes for the year ended December
31, 2007.
Drilling
and Development
Our
drilling and development segment reflects results of drilling and development
activities conducted for affiliated and non-affiliated
parties. Historically, we have engaged in these activities primarily
through sponsoring drilling partnerships, which allowed us to share the risks
and costs inherent in drilling and development operations with our investor
partners. In the future, we plan to evaluate the conduct of our
drilling and development operations based on a comparison of the capital costs
and risks associated with available financing alternatives. Beginning
with our third sponsored drilling partnership in 2005, we have drilled
partnership wells on a “cost-plus” basis, which means that we bill our investor
partners for the actual drilling costs plus a fixed drilling
fee. Prior to our cost-plus drilling arrangements, drilling was
conducted on a "footage" basis; where the Company bore the risk of changes in
costs. In addition, we have typically purchased a 20% to 37% working interest in
the wells developed through these partnerships. In September 2006, we
raised approximately $90 million through investor subscriptions in one drilling
partnership, and in August 2007, we raised approximately $90 million through an
additional drilling partnership.
Our
drilling and development segment represented approximately 18% of our income
before income taxes for the year ended December 31, 2007. In January
2008, we announced that we do not plan to sponsor new drilling partnerships in
2008 in order to focus our effort on maximizing the value of the existing
partnerships and our continuing growth through drilling and
exploration. However, a portion of the funds available for drilling
from the 2007 partnership were advanced and unexpended at the end of 2007, and
they will be used to drill wells and the associated income will be recognized in
2008. With our plans not to sponsor a drilling partnership in 2008,
we anticipate that its contribution to operating income to decline significantly
in 2008.
Well
Operations and Pipeline Income
We
operate approximately 99% of the wells in which we own a working
interest. With respect to wells in which we own an interest of less
than 100%, we charge the other working interest owners a competitive fee for
operating the well. Our well operations and pipeline income segment
represented approximately 6% of our income before income taxes for the year
ended December 31, 2007.
Areas
of Operations
We focus
our exploration, development and acquisition efforts in four geographic
regions:
During
2007, we generated approximately 84.1% of our production from Rocky Mountain
Region wells, 9.8% of our production from Appalachian Basin wells, 6.1% of our
production from Michigan Basin wells. Production operations have not
commenced in the Fort Worth Basin. The majority of our undeveloped
acreage is in the Rocky Mountain Region and our current drilling plans continue
to be focused in that area.
Rocky Mountain
Region. In 1999, we began operations in the Rocky Mountain
Region, which includes our Colorado and North Dakota operations. The
region is further divided into four operating areas; (1) Grand Valley Field, (2)
Wattenberg Field, (3) NECO area and (4) North Dakota area. The Rocky
Mountain Region includes approximately 310,000 gross acres of
leasehold and approximately 2,117 oil and natural gas wells in which we own an
interest (approximately 99% are operated by us). The general details
of each area within the region are further outlined below:
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Grand
Valley Field, Piceance Basin, Garfield County,
Colorado. We commenced operations in the area in late
1999 and currently own an interest in 225 gross, 102.9 net, natural gas
wells. Our leasehold position encompasses approximately 7,800
gross acres with approximately 3,900 net undeveloped acres remaining for
development as of December 31, 2007. We drilled 53 gross, 41.7
net,
wells in the area in 2007 and produced approximately 8.2 Bcfe net to our
interests. Development wells drilled in the area range from
7,000 to 9,500 feet in depth and the majority of wells are drilled
directionally from multi-well pads ranging from two to eight or more wells
per drilling pad. The primary target in the area is gas
reserves, developed from multiple sandstone reservoirs in the Mesaverde
Williams Fork formation. Well spacing is approximately ten
acres per well.
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Wattenberg
Field, DJ Basin, Weld and Adams Counties, Colorado. We
commenced operations in the area in late 1999 and currently own an
interest in 1,242 gross, 747.6 net, oil and natural gas
wells. Our leasehold position encompasses approximately 65,000
gross acres with approximately 13,100 net undeveloped acres remaining for
development as of December 31, 2007. We drilled 158 gross,
106.1 net, wells in the area in 2007 and produced approximately 11.1 Bcfe
net to our interests. Wells drilled in the area range from
approximately 7,000 to 8,000 feet in depth and generally target oil and
gas reserves in the Niobrara, Codell and J Sand
reservoirs. Well spacing ranges from 20 to 40 acres per
well. Operations in the area, in addition to the drilling of
new development wells, includes the refrac of Codell and Niobrara
reservoirs in existing wellbores whereby the Codell sandstone reservoir is
re-stimulated or fraced a second time and/or initial completion
attempts are made in the slightly shallower Niobrara carbonate
reservoir.
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NECO area,
DJ Basin, Yuma County Colorado and Cheyenne County,
Kansas. We commenced operations in the area in 2003 and
currently own an interest in 586 gross, 383.3 net, natural gas
wells. Our leasehold position encompasses approximately 104,500
gross acres with approximately 55,300 net undeveloped acres remaining for
development as of December 31, 2007. We drilled 123 gross, 115
net, wells in the area in 2007 and produced approximately 3.6 Bcfe net to
our interests. Wells drilled in the area range from
approximately 1,500 to 3,000 feet in depth and target gas reserves in the
shallow Niobrara reservoir. Well spacing is approximately 40
acres per well. New drilling operations range from exploratory
wells to test undrilled, seismically defined, structural features
at the Niobrara horizon to development wells targeting known reserves in
existing identified features.
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North
Dakota, Burke County. We commenced operations in the
area in 2006 and currently own an interest in 13 gross, 4.6 net, oil and
natural gas wells. We divested the majority of our Bakken
project acreage in late 2007 (see Note 16, Sale of Oil and Gas
Properties, to our consolidated financial statements included in
this report). Our remaining leasehold encompasses two project
areas in Burke County and encompasses approximately 101,300 gross acres
with approximately 60,000 net undeveloped acres remaining for development
as of December 31, 2007. The eastern area acreage is
prospective for development of oil and gas reserves in the Nesson
Formation. Nesson development wells are approximately 6,000
feet in depth with single or multiple horizontal legs to 4,000 feet or
more in length for a measured length of 10,000 feet or more per
leg. The westernmost acreage block is undeveloped and includes
approximately 22,746 gross and 18,607 net acres. The western
project targets exploratory horizontal
drilling to the Midale/Nesson Formation at depths of approximately
6,800 feet with a lateral leg component of up to 6,100. We
drilled one unsuccessful vertical exploratory well in 2007 and anticipate
additional exploratory activity in
2008.
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Appalachian
Basin. We have conducted operations in the Appalachian Basin
since our inception in 1969. We own an interest in approximately
2,027 gross, 1,501.6 net, oil and natural gas wells in West Virginia,
Pennsylvania, and Tennessee. We drilled 8 gross/net wells in the area
in 2007 and produced approximately 2.7 Bcfe net to our interests. The
majority of the West Virginia leasehold is developed on approximately 40 acre
spacing. We are currently evaluating the results of an infill
drilling project on a limited portion of our developed
leasehold. Wells located in this area are approximately 4,500 feet
deep and target predominantly gas reserves in Devonian and Mississippian aged
tight sandstone reservoirs. The majority of our 10,000 net
undeveloped acres was acquired through our Castle acquisition in October
2007. Development wells in this area target similar Devonian aged
sands as in West Virginia, at depths ranging from 3,000 to 4,500
feet.
Michigan
Basin. We began
operations in the Michigan Basin in 1997 with the bulk of drilling activity
occurring prior to 2002. We own an interest in approximately 209
gross, 145.6 net, oil and natural gas wells that produced 1.7 Bcfe net to our
interest in 2007. Wells in the area range from 1,000 to 2,500 feet in
depth and produce gas from the Antrim Shale. We drilled 3 gross and
net wells in 2007.
Fort Worth Basin,
Erath County, Texas. We have an
interest in approximately 10,800 gross, 8,900 net acres, in northeastern Erath
County. The leasehold acreage is prospective for the development of
oil and natural gas reserves in the Barnett Shale formation at depths of
approximately 5,000 feet. Development is typically with a horizontal
component of approximately 3,000 feet or more, resulting in an approximate
measured length of up to 8,000 feet or more in this area. As of
December 31, 2007, we have drilled one exploratory Barnett well to total
depth. The exploratory well was pending determination at December 31,
2007, see Note
4, Properties and
Equipment - Suspended Well Costs. Completion operations have
not commenced as we are awaiting the completion of a third party gas gathering
infrastructure.
The table
below sets forth our productive wells by operating area at December 31,
2007.
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Productive
Wells
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Gas
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Oil
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Location
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Gross
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Net
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Gross
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Net
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Appalachian
Basin
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1,988
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1,486.2
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39
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15.4
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Michigan
Basin
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202
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142.9
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7
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2.7
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Rocky
Mountain Region
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Wattenberg
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1,217
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728.3
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25
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19.3
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Grand
Valley
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225
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102.9
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-
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-
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NECO
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586
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383.3
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-
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-
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North
Dakota
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4
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1.3
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9
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3.3
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Kansas
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48
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47.0
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-
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-
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Wyoming
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-
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-
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3
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0.7
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Total
Rocky Mountain Region
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2,080
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1,262.8
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37
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23.3
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Fort
Worth Basin-Texas
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1
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1.0
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-
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-
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Total
Productive Wells
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4,271
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2,892.9
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83
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|
|
41.4
|
|
Operations
Exploration
and Development Activities
Our
exploration and development activities focus on the identification and drilling
of new productive wells, the acquisition of existing producing wells from other
operators, and maximizing the
value of our current properties through infill drilling, recompletions, and
other production enhancements.
Prospect
Generation
Our staff
of professional geologists is responsible for identifying areas with potential
for economic production of natural gas and oil. They utilize results
from logs, seismic data and other tools to evaluate existing wells and to
predict the location of economically attractive new natural gas and oil
reserves. To further this process, we have collected and continue to
collect logs, core data, production information and other raw data available
from state and private agencies, other companies and individuals actively
drilling in the regions being evaluated. From this information the
geologists develop models of the subsurface structures and formations that are
used to predict areas for prospective economic development.
On the
basis of these models, our land department obtains available natural gas and oil
leaseholds, farmouts and other development rights in these prospective
areas. In most cases, to secure a lease, we pay a lease bonus and
annual rental payments, converting, upon initiation of production, to a royalty. In
addition, overriding royalty payments may be granted to third parties in
conjunction with the acquisition of drilling rights initially leased by
others. As of December 31, 2007, we had leasehold rights to
approximately 200,000 acres available for development.
Drilling
Activities
The
following table summarizes our development and exploratory drilling activity for
the last five years. There is no correlation between the number of
productive wells completed during any period and the aggregate reserves
attributable to those wells. Productive wells consist of producing
wells and wells capable of commercial production.
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
327.0 |
|
|
|
258.9 |
|
|
|
216.0 |
|
|
|
129.8 |
|
|
|
232.0 |
|
|
|
102.0 |
|
Dry
|
|
|
11.0 |
|
|
|
9.7 |
|
|
|
6.0 |
|
|
|
4.6 |
|
|
|
2.0 |
|
|
|
1.4 |
|
Total
development
|
|
|
338.0 |
|
|
|
268.6 |
|
|
|
222.0 |
|
|
|
134.4 |
|
|
|
234.0 |
|
|
|
103.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(1)
|
|
|
1.0 |
|
|
|
0.2 |
|
|
|
8.0 |
|
|
|
2.8 |
|
|
|
3.0 |
|
|
|
2.3 |
|
Dry
|
|
|
7.0 |
|
|
|
4.5 |
|
|
|
1.0 |
|
|
|
0.5 |
|
|
|
5.0 |
|
|
|
5.0 |
|
Pending
determination
|
|
|
3.0 |
|
|
|
3.0 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
exploratory
|
|
|
11.0 |
|
|
|
7.7 |
|
|
|
9.0 |
|
|
|
3.3 |
|
|
|
8.0 |
|
|
|
7.3 |
|
Total
Drilling Activity
|
|
|
349.0 |
|
|
|
276.3 |
|
|
|
231.0 |
|
|
|
137.7 |
|
|
|
242.0 |
|
|
|
110.7 |
|
|
(1)
|
As
of December 31, 2007, 128 of the 328 productive wells were awaiting gas
pipeline connection, of which 39 were connected and turned in line by
February 29, 2008.
|
The
following table sets forth the wells we drilled by operating area during the
periods indicated.
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Appalachian
Basin
|
|
|
8.0
|
|
|
|
8.0
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Michigan
Basin
|
|
|
3.0
|
|
|
|
3.0
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
-
|
|
|
|
-
|
|
Rocky
Mountain Region
|
|
|
337.0
|
|
|
|
264.3
|
|
|
|
230.0
|
|
|
|
136.7
|
|
|
|
242.0
|
|
|
|
110.7
|
|
Fort
Worth Basin
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
349.0
|
|
|
|
276.3
|
|
|
|
231.0
|
|
|
|
137.7
|
|
|
|
242.0
|
|
|
|
110.7
|
|
We plan
to drill approximately 360 gross wells, excluding exploratory wells, in
2008: 73 in the Appalachian Basin, 2 in the Michigan Basin and 285 in
the Rocky Mountain Region.
Typically,
we will act as driller-operator for these prospects, sometimes selling working
interests in the wells to Company-sponsored partnerships and other entities that
are interested in exploration or development of the prospects. We
retain a working interest in each well we drill. Occasionally, we
participate in wells as a working interest owner with another operator,
typically when we own a minority interest in the property to be
developed.
Most of
the wells we have drilled have targeted developmental natural gas reserves at
depths of less than 10,000 feet. Recently we began drilling to deeper
targets in the Rocky Mountain Region, including several wells with depths of
more than 12,000 feet and horizontal wells with a total drilled footage
approaching 20,000 feet. As wells are drilled to greater depths or
utilize more complicated and expensive drilling and completion methodologies,
they must also develop greater reserves and production to offer attractive
economics and reserves. However, the probability of encountering
problems when drilling wells at greater depths or utilizing horizontal drilling
is generally greater than when drilling a vertical well of lesser
depth. Nevertheless, with increasing costs for, and declining
availability of, proved developed drilling locations, we believe the additional
risk associated with drilling these types of prospects is justified by the
potential to generate additional proved locations and reserves at a
significantly lower cost than would be required to purchase proved undeveloped
locations.
We
drilled eleven exploratory wells in 2007: one was determined to be productive,
seven were determined to be dry, with the remaining three pending
determination. Costs of $4.2 million related to the exploratory dry
holes were expensed in 2007. We plan to conduct additional
exploratory drilling activities in 2008. See sections entitled Financing of Company Drilling and
Development Activities and Drilling and Development Activities
Conducted for Company Sponsored Partnerships below for additional
discussion regarding our drilling activities.
Much of
the work associated with drilling, completing and connecting wells, including
drilling, fracturing, logging and pipeline construction is performed under our
direction by subcontractors specializing in those operations, as is common in
the industry. When judged advantageous, material and services we use
in the development process are acquired through competitive bidding by approved
vendors. We also directly negotiate rates and costs for services and
supplies when conditions indicate that such an approach is
warranted.
Financing
of Company Drilling and Development Activities
We
conduct development drilling activities for our own account and act as operator
for other oil and gas owners. When conducting activities for our own
account, we have historically used cash flow from operations and capital
provided from our long term credit facility to fund our share of
operations. In the future, we may use other sources of funding,
including, but not limited to, asset sales, volumetric production payments, debt
securities, convertible debt securities and equity offerings.
Drilling
and Development Activities Conducted for Company Sponsored
Partnerships
In
addition to wells and interests in wells that we drill for ourselves, we also
act as operator for other oil and gas owners. Historically, these
other owners have included individuals, corporations, partnerships formed by
non-affiliated parties and other investors. We began sponsoring
drilling partnerships in 1984, and have sponsored one or more every year since
then. For many years, our drilling partners have consisted primarily
of public and private partnerships we sponsored. We contribute a cash
investment to purchase an interest in the drilling and development activities
and serve as the managing general partner for each partnership; accordingly, we
are subject to substantial cash commitments at the closing of each drilling
partnership.
In
January 2008, we announced that we do not plan to sponsor new drilling
partnerships in 2008 in order to focus our effort on continuing our growth
through drilling and exploration. However, a portion of the funds
available for drilling from the 2007 partnership were advanced and unexpended at
the end of 2007, and they will be used to drill wells and the associated income
will be recognized in 2008.
We
sponsored partnerships in 2007 and 2006, each with $90 million in subscriptions,
and in 2005, with $116 million in subscriptions. During 2007, we
sponsored one drilling partnership to which we contributed $38.7 million and
received a 37% working interest in the partnership. While funds were
received by us pursuant to drilling contracts in the years indicated, we
recognize revenues from drilling operations on the percentage of completion
method as the wells were drilled, rather than when funds were
received. Substantially all of our drilling and development funds
were received from partnerships in which we serve as managing general
partner. As wells produce for a number of years, we continue to serve
as operator for a number of partnerships and unaffiliated parties.
When
developing wells for our partnerships or others, we enter into a development
agreement with the investor partner, pursuant to which we agree to sell some or
all of our rights in a well to be drilled to the partnership or other
entity. The partnership or other entity thereby becomes owner of a
working interest in the well. In our financial reporting, we report
only our proportionate share of oil and gas reserves, production, oil and gas
sales and costs associated with wells in which other investors
participate.
Purchases
of Producing Properties
In
addition to drilling new wells, we continue to pursue opportunities to purchase
existing wells and development rights from other owners, as well as greater
ownership interests in the wells we operate. Generally, outside
interests purchased include a majority interest in the wells and the right to
operate the wells. In January 2007, we completed the purchase of
approximately 144 oil and gas wells and 8,160 acres of leaseholds in the
Wattenberg Field from EXCO Resources. Also in January 2007, we
purchased the outside partnership interests in 44 partnerships which we
sponsored and formed primarily in the late 1980s and 1990s. These
interests constituted the majority of the interests in 718 wells, primarily in
the Appalachian and Michigan Basins. In February 2007, we acquired
from an unrelated party 28 producing wells and associated undeveloped acreage in
Colorado. In October 2007, we purchased from unrelated parties a
majority working interest of 762 natural gas wells located in southwestern
Pennsylvania. We estimated that the acquisition included
approximately 47 Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of
unproved reserves. The purchase also included associated pipelines,
equipment, real estate and undeveloped acreage.
Production, Sales, Prices and Lifting
Costs
The
following table sets forth information regarding our production volumes,
oil and natural gas sales, average sales price received and average lifting cost
incurred for the periods indicated.
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Production (1)
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
|
910,052
|
|
|
|
631,395
|
|
|
|
438,971
|
|
Natural
gas (Mcf)
|
|
|
22,513,306
|
|
|
|
13,160,784
|
|
|
|
11,030,760
|
|
Natural
gas equivalent (Mcfe) (2)
|
|
|
27,973,618
|
|
|
|
16,949,154
|
|
|
|
13,664,586
|
|
Oil and Gas Sales (in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$ |
55,196
|
|
|
$ |
37,460
|
|
|
$ |
22,193
|
|
Gas
sales
|
|
|
119,991
|
|
|
|
77,729
|
|
|
|
80,366
|
|
Total
oil and gas sales
|
|
$ |
175,187
|
|
|
$ |
115,189
|
|
|
$ |
102,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain (Loss) on
Derivatives, net (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
derivatives - realized (loss) gain
|
|
$ |
(177
|
) |
|
$ |
-
|
|
|
$ |
(1,288)
|
|
Natural
gas derivatives - realized gain (loss)
|
|
|
7,350
|
|
|
|
1,895
|
|
|
|
(5,079)
|
|
Total
realized gain (loss) on derivatives, net
|
|
$ |
7,173
|
|
|
$ |
1,895
|
|
|
$ |
(6,367)
|
|
Average
Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl) (3)
|
|
$ |
60.65
|
|
|
$ |
59.33
|
|
|
$ |
50.56
|
|
Natural
gas (per Mcf) (3)
|
|
$ |
5.33
|
|
|
$ |
5.91
|
|
|
$ |
7.29
|
|
Natural
gas equivalent (per Mcfe)
|
|
$ |
6.26
|
|
|
$ |
6.80
|
|
|
$ |
7.51
|
|
Average
Sales Price (including realized gain (loss) on
derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
60.46
|
|
|
$ |
59.33
|
|
|
$ |
47.62
|
|
Natural
gas (per Mcf)
|
|
$ |
5.66
|
|
|
$ |
6.05
|
|
|
$ |
6.83
|
|
Natural
gas equivalent (per Mcfe)
|
|
$ |
6.52
|
|
|
$ |
6.91
|
|
|
$ |
7.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Cost
(Lifting Cost) per Mcfe (4)
|
|
$ |
1.34
|
|
|
$ |
1.23
|
|
|
$ |
1.19
|
|
|
(1)
|
Production
as shown in the table is net and is determined by multiplying the gross
production volume of properties in which we have an interest by the
percentage of the leasehold or other property interest we
own.
|
|
(2)
|
A
ratio of energy content of natural gas and oil (six Mcf of natural gas
equals one barrel of oil) was used to obtain a conversion factor to
convert oil production into equivalent Mcf of natural
gas.
|
|
(3)
|
We
utilize commodity based derivative instruments to manage a portion of our
exposure to price volatility of our natural gas and oil
sales. This amount excludes realized and unrealized gains and
losses on commodity based derivative
instruments.
|
|
(4)
|
Production
costs represent oil and gas operating expenses which include severance and
ad valorem taxes as reflected in our financial statements. See
Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Oil and Gas Production
and Well Operations Costs."
|
Oil
and Natural Gas Reserves
All of
our natural gas and oil reserves are located in the United States. We
utilized the services of two independent petroleum engineers for our 2007 and
2006 independent reserve reports. Wright & Company prepared the
reserve reports for the Appalachian and Michigan Basins. Ryder Scott
Company, L.P. prepared the reserve reports for the Rocky Mountain
Region. Wright & Company prepared all of the reserve reports for
us for 2005 with the exception of our 2005 North Dakota wells which were
prepared by Ryder Scott Company, L.P. The independent engineers'
estimates are made using available geological and reservoir data as well as
production performance data. The estimates are prepared with respect
to reserve categorization, using the definitions for proved reserves set forth
in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and
guidance. When preparing our reserve estimates, the independent
engineers did not independently verify the accuracy and completeness of
information and data furnished by us with respect to ownership interests, oil
and natural gas production, well test data, historical costs of operations and
developments, product prices, or any agreements relating to current and future
operations of properties and sales of production. Our independent
reserve estimates are reviewed and approved by our internal engineering staff
and management.
The
tables below set forth information as of December 31, 2007, regarding our
estimated proved reserves. Reserves cannot be measured exactly,
because reserve estimates involve subjective judgment. The estimates
must be reviewed periodically and adjusted to reflect additional information
gained from reservoir performance, new geological and geophysical data and
economic changes. Neither the present value of estimated future net
cash flows nor the standardized measure is intended to represent the current
market value of the estimated oil and natural gas reserves we own.
|
|
December
31, 2007
|
|
|
|
Oil
(MBbl)
|
|
|
Gas
(MMcf)
|
|
|
Total
(MMcfe)
|
|
Proved
developed
|
|
|
8,927
|
|
|
|
314,123
|
|
|
|
367,685
|
|
Proved
undeveloped
|
|
|
6,411
|
|
|
|
279,440
|
|
|
|
317,906
|
|
Total
Proved
|
|
|
15,338
|
|
|
|
593,563
|
|
|
|
685,591
|
|
|
|
Proved
Developed
|
|
|
Proved
Undeveloped
|
|
|
Total
Proved
|
|
|
|
(in
millions)
|
|
Estimated
future net cash flows (1)
|
|
$ |
1,203
|
|
|
$ |
644
|
|
|
$ |
1,847
|
|
Standardized
measure
(1)(2)
|
|
|
600
|
|
|
|
153
|
|
|
|
753
|
|
|
(1)
|
Estimated
future net cash flow represents the estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production costs, future development costs and income tax expense, using
prices and costs in effect at December 31, 2007. The prices
used in our reserve reports yield weighted average wellhead prices of
$80.67 per barrel of oil and $6.77 per Mcf of natural
gas. These prices should not be interpreted as a prediction of
future prices, nor do they reflect the value of our commodity hedges in
place at December 31, 2007. The amounts shown do not give
effect to non-property related expenses, such as corporate general and
administrative expenses and debt service, or to depreciation, depletion
and amortization.
|
|
(2)
|
The
standardized
measure of discounted future net cash flows is calculated in
accordance with Statement of Financial Accounting Standards (“SFAS”) No.
69, which requires the future cash flows to be discounted. The
discount rate used was 10%. Additional information on this
measure is presented in Note 20,
"Supplemental Oil and Gas Information," of our consolidated financial
statements included in this report.
|
|
|
December
31, 2007
|
|
|
|
Oil
(MBbl)
|
|
|
Gas
(MMcf)
|
|
|
Gas
Equivalent (MMcfe)
|
|
|
Percent
|
|
Proved
developed
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
34
|
|
|
|
80,355
|
|
|
|
80,559
|
|
|
|
22
|
% |
Michigan
Basin
|
|
|
58
|
|
|
|
23,979
|
|
|
|
24,327
|
|
|
|
7
|
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
8,473
|
|
|
|
67,227
|
|
|
|
118,065
|
|
|
|
32
|
% |
Grand
Valley
|
|
|
107
|
|
|
|
91,326
|
|
|
|
91,968
|
|
|
|
25
|
% |
NECO
|
|
|
-
|
|
|
|
50,942
|
|
|
|
50,942
|
|
|
|
14
|
% |
North
Dakota
|
|
|
250
|
|
|
|
294
|
|
|
|
1,794
|
|
|
|
0
|
% |
Wyoming
|
|
|
5
|
|
|
|
-
|
|
|
|
30
|
|
|
|
0
|
% |
Total
Rocky Mountain Region
|
|
|
8,835
|
|
|
|
209,789
|
|
|
|
262,799
|
|
|
|
71
|
% |
Total
proved developed
|
|
|
8,927
|
|
|
|
314,123
|
|
|
|
367,685
|
|
|
|
100
|
% |
Proved
undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
-
|
|
|
|
22,115
|
|
|
|
22,115
|
|
|
|
7
|
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
6,210
|
|
|
|
40,729
|
|
|
|
77,989
|
|
|
|
24
|
% |
Grand
Valley
|
|
|
201
|
|
|
|
200,998
|
|
|
|
202,204
|
|
|
|
64
|
% |
NECO
|
|
|
-
|
|
|
|
15,598
|
|
|
|
15,598
|
|
|
|
5
|
% |
Total
Rocky Mountain Region
|
|
|
6,411
|
|
|
|
257,325
|
|
|
|
295,791
|
|
|
|
93
|
% |
Total
proved undeveloped
|
|
|
6,411
|
|
|
|
279,440
|
|
|
|
317,906
|
|
|
|
100
|
% |
Proved
reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
34
|
|
|
|
102,470
|
|
|
|
102,674
|
|
|
|
15
|
% |
Michigan
|
|
|
58
|
|
|
|
23,979
|
|
|
|
24,327
|
|
|
|
4
|
% |
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
14,683
|
|
|
|
107,956
|
|
|
|
196,054
|
|
|
|
28
|
% |
Grand
Valley
|
|
|
308
|
|
|
|
292,324
|
|
|
|
294,172
|
|
|
|
43
|
% |
NECO
|
|
|
-
|
|
|
|
66,540
|
|
|
|
66,540
|
|
|
|
10
|
% |
North
Dakota
|
|
|
250
|
|
|
|
294
|
|
|
|
1,794
|
|
|
|
0
|
% |
Wyoming
|
|
|
5
|
|
|
|
-
|
|
|
|
30
|
|
|
|
0
|
% |
Total
Rocky Mountain Region
|
|
|
15,246
|
|
|
|
467,114
|
|
|
|
558,590
|
|
|
|
81
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
proved reserves
|
|
|
15,338
|
|
|
|
593,563
|
|
|
|
685,591
|
|
|
|
100
|
% |
Acreage
The
following table sets forth by operating area leased acres as of December 31,
2007.
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
Location
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
Basin
|
|
|
84,240
|
|
|
|
84,240
|
|
|
|
10,000
|
|
|
|
10,000
|
|
|
|
94,240
|
|
|
|
94,240
|
|
Michigan
Basin
|
|
|
8,240
|
|
|
|
8,240
|
|
|
|
440
|
|
|
|
440
|
|
|
|
8,680
|
|
|
|
8,680
|
|
New
York
|
|
|
-
|
|
|
|
-
|
|
|
|
19,500
|
|
|
|
16,575
|
|
|
|
19,500
|
|
|
|
16,575
|
|
Rocky
Mountain Region
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg
|
|
|
50,860
|
|
|
|
47,440
|
|
|
|
14,093
|
|
|
|
13,143
|
|
|
|
64,953
|
|
|
|
60,583
|
|
Grand
Valley
|
|
|
2,994
|
|
|
|
2,994
|
|
|
|
3,900
|
|
|
|
3,900
|
|
|
|
6,894
|
|
|
|
6,894
|
|
NECO
|
|
|
26,392
|
|
|
|
18,680
|
|
|
|
78,147
|
|
|
|
55,320
|
|
|
|
104,539
|
|
|
|
74,000
|
|
North
Dakota
|
|
|
7,453
|
|
|
|
4,767
|
|
|
|
93,814
|
|
|
|
59,972
|
|
|
|
101,267
|
|
|
|
64,739
|
|
Wyoming
|
|
|
-
|
|
|
|
-
|
|
|
|
31,945
|
|
|
|
31,945
|
|
|
|
31,945
|
|
|
|
31,945
|
|
Total
Rocky Mountain Region
|
|
|
87,699
|
|
|
|
73,881
|
|
|
|
221,899
|
|
|
|
164,280
|
|
|
|
309,598
|
|
|
|
238,161
|
|
Fort
Worth Basin
|
|
|
-
|
|
|
|
-
|
|
|
|
10,804
|
|
|
|
8,868
|
|
|
|
10,804
|
|
|
|
8,868
|
|
Total
Acreage
|
|
|
180,179
|
|
|
|
166,361
|
|
|
|
262,643
|
|
|
|
200,163
|
|
|
|
442,822
|
|
|
|
366,524
|
|
Title
to Properties
We
believe that we hold good and defensible title to our developed properties, in
accordance with standards generally accepted in the oil and natural gas
industry. As is customary in the industry, a perfunctory title
examination is conducted at the time the undeveloped properties are
acquired. Prior to the commencement of drilling operations, a title
examination is conducted and curative work is performed with respect to
discovered defects which we deem to be significant. Title
examinations have been performed with respect to substantially all of our
producing properties. Two properties in our Grand Valley Field
represent 43% of our total proved reserves.
The
properties we own are subject to royalty, overriding royalty and other
outstanding interests customary to the industry. The properties may
also be subject to additional burdens, liens or encumbrances customary to the
industry, including items such as operating agreements, current taxes,
development obligations under natural gas and oil leases, farm-out agreements
and other restrictions. We do not believe that any of these burdens
will materially interfere with the use of the properties.
Natural
Gas Sales
We
generally sell the natural gas that we produce under contracts with monthly
pricing provisions. Virtually all of our contracts include provisions
wherein prices change monthly with changes in the market, for which certain
adjustments may be made based on whether a well delivers to a gathering or
transmission line, quality of natural gas and prevailing supply and demand
conditions, so that the price of the natural gas fluctuates to remain
competitive with other available natural gas supplies. As a result,
our revenues from the sale of natural gas will suffer if market prices decline
and benefit if they increase. We believe that the pricing provisions
of our natural gas contracts are customary in the industry. We also
enter into financial derivatives such as puts, collars, or swaps in order to
protect against possible price instability regarding the physical sales
market.
We
sell our natural gas to industrial end-users, utilities, other gas marketers,
and other wholesale gas purchasers. During 2007, the natural gas we
produce was sold at prices ranging from $1.68 to $18.56 per Mcf, depending upon
well location, the date of the sales contract and other factors. Our
weighted net average price of natural gas sold in 2007 was $5.33 per
Mcf.
In
general, we, together with our marketing subsidiary, RNG, have been and expect
to continue to be able to produce and sell natural gas from our wells without
significant curtailment and at competitive prices. We do experience
limited curtailments from time to time due to pipeline maintenance and operating
issues, and during October 2007, we chose to curtail some of our Piceance Basin
production due to low prices. Open access transportation through the
country's interstate pipeline system gives us access to a broad range of
markets. Whenever feasible, we obtain access to multiple pipelines
and markets from each of our gathering systems seeking the best available market
for our natural gas at any point in time.
Oil
Sales
The
majority of our wells in the Wattenberg Field in Colorado and our wells in North
Dakota produce oil in addition to natural gas. As of December 31,
2007, oil represented 13.4% of our total equivalent reserves and accounted for
approximately 31.5% of our oil and gas sales revenue for the year ended December
31, 2007.
We are
currently able to sell all the oil that we can produce under existing sales
contracts with petroleum refiners and marketers. We do not refine any
of our oil production. Our crude oil production is sold to purchasers
at or near our wells under both short and long-term purchase contracts with
monthly pricing provisions. During 2007, oil we produced sold at
prices ranging from $41.03 to $76.03 per barrel, depending upon the location and
quality of oil. Our weighted net average price per barrel of oil sold
in 2007 was $60.65.
Natural
Gas Marketing
Our
natural gas marketing activities involve the purchase of natural gas from other
producers and the sale of that natural gas along with the natural gas we
produce. We believe that in a deregulated market, successful natural
gas marketing is an essential component of profitable operations. A
variety of factors affect the market for natural gas, including:
|
·
|
the
availability of other domestic
production;
|
|
·
|
the
availability and price of alternative
fuels;
|
|
·
|
the
proximity and capacity of natural gas
pipelines;
|
|
·
|
general
fluctuations in the supply and demand for natural gas;
and
|
|
·
|
the
effects of state and federal regulations on natural gas production and
sales.
|
The
natural gas industry also competes with other industries in supplying the energy
and fuel requirements of industrial, commercial and individual
customers.
RNG, our
wholly owned subsidiary, is a natural gas marketing company that specializes in
the purchase, aggregation and sale of natural gas production in our Eastern
operating areas. RNG markets the natural gas we produce and also
purchases natural gas in the Appalachian Basin from other producers and resells
it to utilities, end users or other marketers. RNG's employees have
extensive knowledge of natural gas markets in our areas of
operations. Such knowledge assists us in maximizing our prices as we
market natural gas from PDC-operated wells. The gas is marketed to
natural gas utilities, industrial and commercial customers as well as other
marketers, either directly through our gathering system, or through
transportation services provided by regulated interstate pipeline
companies.
Commodity
Risk Management Activities
We
utilize commodity based derivative instruments to manage a portion of the
exposure to price volatility stemming from our oil and natural gas sales and
marketing activities. These instruments consist of over-the-counter
swaps, NYMEX-traded natural
gas futures and option contracts for Appalachian and Michigan production,
Colorado Interstate Gas Index, or CIG, and Panhandle Eastern Pipeline-based
contracts for Colorado natural gas production and NYMEX-traded oil futures and
option contracts for Colorado oil production. We may utilize
derivatives based on other indices or markets where appropriate. The
contracts economically provide price protection for committed and anticipated
oil and natural gas purchases and sales, generally forecasted to occur within
the next two- to three-year period. Our policies prohibit the use of
oil and natural gas futures, swaps or options for speculative purposes and
permit utilization of derivatives only if there is an underlying physical
position.
RNG has
extensive experience with the use of cash-settled derivatives to reduce the risk
and effect of natural gas price changes. RNG uses these financial
derivatives to coordinate fixed purchases and sales. We use financial
derivatives to establish "floors" and "ceilings" or "collars" on the possible
range of the prices realized for the sale of natural gas and oil. RNG
also enters into back-to-back fixed-price purchases and sales contracts with
counterparties. These fixed physical contracts meet the SFAS No. 133,
Accounting for Derivative
Instruments and Certain Hedging Activities, definition of a
derivative. Both types of derivatives (i.e., the physical deals and
the cash settled contracts) are carried on the balance sheet at fair value with
changes in fair values recognized currently in the income
statement.
We are
subject to price fluctuations for natural gas sold in the spot market and under
market index contracts. We continue to evaluate the potential for
reducing these risks by entering into derivative transactions. In
addition, we may close out any portion of derivatives that may exist from time
to time which may result in a realized gain or loss on that derivative
transaction. We manage price risk on only a portion of our
anticipated production, so the remaining portion of our production is subject to
the full fluctuation of market pricing.
Well
Operations
At
December 31, 2007, we had an interest in approximately 2,117 wells in the Rocky
Mountain Region, 2,027 wells in the Appalachian Basin, and 209 wells in the
Michigan Basin. Our ownership interest in these wells range up to
100% and as of December 31, 2007, on average, we had approximately 67.4%
ownership interest in the wells we operated.
We are
paid a monthly operating fee for the portion of each well we operate that is
owned by others, including our sponsored partnerships. The fee is
competitive with rates charged by other operators in the area. The
fee covers monthly operating and accounting costs, insurance and other recurring
costs. We may also receive additional compensation, at competitive
rates, for special non-recurring activities, such as reworks and
recompletions. If we purchase well interests belonging to investors
in the partnerships, we then account for the purchased interests as being owned
by us, which results in a decrease in well operations income. As of
December 31, 2007, we operate approximately 99% of the wells in which we own a
working interest.
Transportation
Natural
gas wells are connected by pipelines to natural gas markets. Over the
years, we have developed, own and operate gathering systems in some of our areas
of operations. We also continue to construct new trunk lines as
necessary to provide for the marketing of natural gas being developed from new
areas and to enhance or maintain our existing systems. Pipelines and
related facilities can represent a significant portion of the capital costs of
developing wells, particularly in new areas located at a distance from existing
pipelines. We consider these costs in our evaluation of our leasing,
development and acquisition opportunities.
Governmental
Regulation
While the
prices of oil and natural gas are set by the market, other aspects of our
business and the oil and natural gas industry in general are heavily
regulated. The availability of a ready market for oil and natural gas
production depends on several factors beyond our control. These
factors include regulation of production, federal and state regulations
governing environmental quality and pollution control, 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. State and federal regulations generally are intended to
protect consumers from unfair treatment and oppressive control, to reduce the
risk to the public and workers from the drilling, completion, production and
transportation of oil and natural gas, to prevent waste of oil and natural gas,
to protect rights to between owners in a common reservoir and to control
contamination of the environment. Pipelines are subject to the
jurisdiction of various federal, state and local agencies. In the
western part of the United States, the federal and state governments own a large
percentage of the land and the rights to develop oil and natural
gas. Recently, we have increased our positions in these types of
leases. Generally, government leases are subject to additional
regulations and controls not commonly seen on private leases. We take
the steps necessary to comply with applicable regulations, both on our own
behalf and as part of the services we provide to our drilling
partnerships. We believe that we are in compliance with such
statutes, rules, regulations and governmental orders, although there can be no
assurance that this is or will remain the case. The following summary
discussion of the regulation of the United States oil and natural gas industry
is not intended to constitute a complete discussion of the various statutes,
rules, regulations and environmental orders to which our operations may be
subject.
Regulation
of Oil and Natural Gas Exploration and Production
Our
exploration and production business is subject to various federal, state and
local laws and regulations on taxation, the development, production and
marketing of oil and gas and environmental and safety matters. Many
laws and regulations require drilling permits and govern the spacing of wells,
rates of production, water discharge, prevention of waste and other
matters. Prior to commencing drilling activities for a well, we must
procure permits and/or approvals for the various stages of the drilling process
from the applicable state and local agencies in the state in which the area to
be drilled is located. The permits and approvals include those for
the drilling of wells. Also, regulated matters include:
|
·
|
bond
requirements in order to drill or operate
wells;
|
|
·
|
the
method of drilling and casing
wells;
|
|
·
|
the
surface use and restoration of well
properties;
|
|
·
|
the
plugging and abandoning of wells;
and
|
|
·
|
the
disposal of fluids.
|
Our
operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and
spacing units or proration units, the density of wells which may be drilled and
the unitization or pooling of properties. In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely primarily or exclusively on voluntary pooling of lands
and leases. In areas where pooling is voluntary, it may be more
difficult to form units, and therefore, more difficult to develop a project if
the operator owns less than 100% of the leasehold. In addition, state
conservation laws may establish maximum rates of production from oil and natural
gas wells, generally prohibiting the venting or flaring of natural gas and
imposing certain requirements regarding the ratability of
production. Where wells are to be drilled on state or federal leases,
additional regulations and conditions may apply. The effect of these
regulations may limit the amount of oil and natural gas we can produce from our
wells and may limit the number of wells or the locations at which we can
drill. Such laws and regulations may increase the costs of planning,
designing, drilling, installing, operating and abandoning our oil and natural
gas wells and other facilities. In addition, these laws and
regulations, and any others that are passed by the jurisdictions where we have
production, could limit the total number of wells drilled or the allowable
production from successful wells, which could limit our reserves. As
a result, we are unable to predict the future cost or effect of complying with
such regulations.
Regulation
of Sales and Transportation of Natural Gas
Historically,
the price of natural gas was subject to limitation by federal
legislation. The Natural Gas Wellhead Decontrol Act removed, as of
January 1, 1993, all remaining federal price controls from natural gas sold in
"first sales" on or after that date. The Federal Energy Regulatory
Commission's, or FERC, jurisdiction over natural gas transportation was
unaffected by the Decontrol Act. While sales by producers of natural
gas and all sales of crude oil, condensate and natural gas liquids
can currently be made at market prices, there are a number of proposed bills in
the United States Congress to reenact price controls or impose “windfall
profits” or similar taxes in the future on oil and natural gas
prices. The passage of one of those bills or similar legislation
could have the effect of reducing the price we receive for our production, or
substantially increasing the tax burden associated with our production
operations.
We move
natural gas through pipelines owned by other companies, and sell natural gas to
other companies that also utilize common carrier pipeline
facilities. Natural gas pipeline interstate transmission and storage
activities are subject to regulation by the FERC under the Natural Gas Act of
1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates
and charges for the transportation of natural gas in interstate commerce,
accounting, and the extension, enlargement or abandonment of its jurisdictional
facilities, among other things, are subject to regulation. Each
natural gas pipeline company holds certificates of public convenience and
necessity issued by the FERC authorizing ownership and operation of all
pipelines, facilities and properties for which certificates are required under
the NGA. Each natural gas pipeline company is also subject to the
Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety
requirements in the design, construction, operation and maintenance of
interstate natural gas transmission facilities. FERC regulations
govern how interstate pipelines communicate and do business with their
affiliates. Interstate pipelines may not operate their pipeline
systems to preferentially benefit their marketing affiliates.
Each
interstate natural gas pipeline company establishes its rates primarily through
the FERC’s ratemaking process. Key determinants in the ratemaking
process are:
|
|
costs
of providing service, including depreciation
expense;
|
|
|
allowed
rate of return, including the equity component of the capital structure
and related income taxes; and
|
|
|
volume
throughput assumptions.
|
The
availability, terms and cost of transportation affect our natural gas
sales. In the past, FERC has undertaken various initiatives to
increase competition within the natural gas industry. As a result of
initiatives like FERC Order No. 636, issued in April 1992, the interstate
natural gas transportation and marketing system was substantially restructured
to remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions
of Order No. 636 require that interstate pipelines provide transportation
separate or "unbundled" from their sales service, and require that pipelines
provide firm and interruptible transportation service on an open access basis
that is equal for all natural gas suppliers. In many instances, the
result of Order No. 636 and related initiatives has been to substantially reduce
or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation
services. Another effect of regulatory restructuring is greater
access to transportation on interstate pipelines. In some cases,
producers and marketers have benefited from this
availability. However, competition among suppliers has greatly
increased and traditional long-term producer-pipeline contracts are
rare. Furthermore, gathering facilities of interstate pipelines are
no longer regulated by FERC, thus allowing gatherers to charge higher gathering
rates.
Additional
proposals and proceedings that might affect the natural gas industry occur
frequently in Congress, FERC, state commissions, state legislatures, and the
courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by FERC and Congress will continue. We
cannot determine to what extent our future operations and earnings will be
affected by new legislation, new regulations, or changes in existing regulation,
at federal, state or local levels.
Environmental
Regulations
Our
operations are subject to numerous laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Public interest in the protection of the environment has
increased dramatically in recent years. The trend of more expansive
and tougher environmental legislation and regulations could
continue. To the extent laws are enacted or other governmental action
is taken that restricts drilling or imposes environmental protection
requirements that result in increased costs and reduced access to the natural
gas industry in general, our business and prospects could be adversely
affected.
We
generate wastes that may be subject to the Federal Resource Conservation and
Recovery Act, or RCRA, and comparable state statutes. The U.S.
Environmental Protection Agency, or EPA, and various state agencies have limited
the approved methods of disposal for certain hazardous and non-hazardous
wastes. Furthermore, certain wastes generated by our operations that
are currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.
We
currently own or lease numerous properties that for many years have been used
for the exploration and production of oil and natural gas. Although
we believe that we have utilized good operating and waste disposal practices,
and when necessary, appropriate remediation techniques, prior owners and
operators of these properties may not have utilized similar practices and
techniques, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties that we own or lease or on or under
locations where such wastes have been taken for disposal. These
properties and the wastes disposed thereon may be subject to the Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and
analogous state laws, as well as state laws governing the management of oil and
natural gas wastes. Under such laws, we could be required to remove
or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
CERCLA
and similar state laws impose liability, without regard to fault or the legality
of the original conduct, on certain classes of persons that are considered to
have contributed to the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed of
or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for release of hazardous
substances under CERCLA may be subject to full liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. As an owner and operator of oil and natural gas
wells, we may be liable pursuant to CERCLA and similar state laws.
Our
operations may be subject to the Clean Air Act, or CAA, and comparable state and
local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have been developing regulations to
implement these requirements. We may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emission-related issues. The state of
Colorado has also indicated it intends to implement new air regulations later in
2008 which affect the oil and gas industry, including our operations, related to
air emissions and wildlife.
The
Federal Clean Water Act, or CWA, and analogous state laws impose strict controls
against the discharge of pollutants, including spills and leaks of oil and other
substances. The CWA also regulates storm water run-off from oil and
gas facilities and requires a storm water discharge permit for certain
activities. Spill prevention, control, and countermeasure
requirements of the CWA require appropriate containment terms and similar
structures to help prevent the contamination of navigable waters in the event of
a petroleum hydrocarbon tank spill, rupture, or leak.
Oil
production is subject to many of the same operating hazards and environmental
concerns as natural gas production, but is also subject to the risk of oil
spills. Federal regulations require certain owners or operators of
facilities that store or otherwise handle oil, including us, to procure and
implement Spill Prevention, Control and Counter-measures plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act
of 1990, or OPA, subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from oil spills. Noncompliance with OPA may result in varying
civil and criminal penalties and liabilities. We are also subject to
the CWA and analogous state laws relating to the control of water pollution,
which laws provide varying civil and criminal penalties and liabilities for
release of petroleum or its derivatives into surface waters or into the
ground. Historically, we have not experienced any significant oil
discharge or oil spill problems.
Our
expenses relating to preserving the environment during 2007 were not significant
in relation to operating costs and we expect no material change in
2008. Environmental regulations have had no materially adverse effect
on our operations to date, but no assurance can be given that environmental
regulations will not, in the future, result in a curtailment of production or
otherwise have a materially adverse effect on our business, financial condition
or results of operations.
Operating
Hazards and Insurance
Our
exploration and production operations include a variety of operating risks,
including the risk of fire, explosions, blowouts, cratering, pipe failure,
casing collapse, abnormally pressured formations, and environmental hazards such
as gas leaks, ruptures and discharges of toxic gas. The occurrence of
any of these could result in substantial losses to us due to injury and loss of
life, severe damage to and destruction of property, natural resources and
equipment, pollution and other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of
operations. Our pipeline, gathering and distribution operations are
subject to the many hazards inherent in the natural gas
industry. These hazards include damage to wells, pipelines and other
related equipment, damage to property caused by hurricanes, floods, fires and
other acts of God, inadvertent damage from construction equipment, leakage of
natural gas and other hydrocarbons, fires and explosions and other hazards that
could also result in personal injury and loss of life, pollution and suspension
of operations.
Any
significant problems related to our facilities could adversely affect our
ability to conduct our operations. In accordance with customary
industry practice, we maintain insurance against some, but not all, potential
risks; however, there can be no assurance that such insurance will be adequate
to cover any losses or exposure for liability. The occurrence of a
significant event not fully insured against could materially adversely affect
our operations and financial condition. We cannot predict whether
insurance will continue to be available at premium levels that justify our
purchase or whether insurance will be available at all. Furthermore,
we are not insured against our economic losses resulting from damage or
destruction to third party property, such as the Rockies Express pipeline; such
an event could result in significantly lower regional prices or our inability to
deliver gas.
Competition
We
believe that our exploration, drilling and production capabilities and the
experience of our management and professional staff generally enable us to
compete effectively. We encounter competition from numerous other oil
and natural gas companies, drilling and income programs and partnerships in all
areas of operations, including drilling and marketing oil and natural gas and
obtaining desirable oil and natural gas leases on producing
properties. Many of these competitors possess larger staffs and
greater financial resources than we do, which may enable them to identify and
acquire desirable producing properties and drilling prospects more
economically. Our ability to explore for oil and natural gas
prospects and to acquire additional properties in the future depends upon our
ability to conduct our operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive
environment. We also face intense competition in the marketing of
natural gas from competitors including other producers as well as marketing
companies. Also, international developments and the possible improved
economics of domestic natural gas exploration may influence other companies to
increase their domestic oil and natural gas exploration. Furthermore,
competition among companies for favorable prospects can be expected to continue,
and it is anticipated that the cost of acquiring properties may increase in the
future. During 2007, our industry experienced continued strong demand
for drilling services and supplies. This is resulting in increasing
costs, and in some cases the demand for supplies and services exceeds the
available supplies. This can result in higher well costs and delays
in the execution of planned drilling operations. Factors affecting
competition in the oil and natural gas industry include price, location of
drilling, availability of drilling prospects and drilling rigs, pipeline
capacity, quality of production and volumes produced. We believe that
we can compete effectively in the oil and natural gas industry in each of the
listed areas. Nevertheless, our business, financial condition and
results of operations could be materially adversely affected by
competition. We also compete with other oil and gas companies as well
as companies in other industries for the capital we need to conduct our
operations. Recently, turmoil in the capital markets has made capital
more expensive and difficult to obtain. In the event that we do not
have adequate capital to execute our business plan, we may be forced to curtail
our drilling and acquisition activities.
Employees
As of
December 31, 2007, we had 256 employees, including 164 in production, 7 in
natural gas marketing, 26 in exploration and development, 37 in finance,
accounting and data processing, and 22 in administration. Our
engineers, supervisors and well tenders are responsible for the day-to-day
operation of wells and pipeline systems. In addition, we retain
subcontractors to perform drilling, fracturing, logging, and pipeline
construction functions at drilling sites, with our employees supervising the
activities of the subcontractors. In 2007, the total number of
Company employees increased by 67.
Our
employees are not covered by a collective bargaining agreement. We
consider relations with our employees to be excellent.
You
should carefully consider the following risk factors in addition to the other
information included in this report. Each of these risk factors could
adversely affect our business, operating results and financial condition, as
well as adversely affect the value of an investment in our common stock or other
securities.
Risks
Related to Our Business and the Natural Gas and Oil Industry
Our
"material weaknesses" in our internal control over financial reporting and
resulting ineffective disclosure controls and procedures could have a material
adverse effect on the reliability of our financial statements and our ability to
file public reports on time, raise capital and meet our debt
obligations.
Our
management assessed the effectiveness of our internal control over financial
reporting as of December 31, 2007, and pursuant to this assessment, identified
two material weaknesses in our internal control over financial reporting. The
existence of any material weaknesses means there is a deficiency, or a
combination of deficiencies, in internal control over financial reporting, such
that there is a reasonable possibility that a material misstatement of our
annual or interim financial statements will not be prevented or detected on a
timely basis. The two material weaknesses relate to our failure to
maintain effective controls over some of our key financial statement
spreadsheets that support all significant balance sheet and income statement
accounts and our failure to ensure proper accounting for derivative
activities. For a more detailed discussion of our material
weaknesses, see Item 8, Management's Report on Internal
Control over Financial Reporting, and Item 9A, Controls and Procedures of
this report. As a result of these material weaknesses, our management
concluded that our disclosure controls and procedures were not effective as of
December 31, 2007.
Failure
to maintain effective internal control over financial reporting and/or effective
disclosure controls and procedures could prevent us from being able to prevent
fraud and/or provide reliable financial statements and other public
reports. Such circumstances could harm our business and operating
results, cause investors to lose confidence in the accuracy and completeness of
our financial statements and reports, and have a material adverse effect on the
trading price of our debt and equity securities and our ability to raise capital
necessary for our operations. These failures may also adversely
affect our ability to file our periodic reports with the SEC on
time. Being late in filing our periodic reports with the
SEC may result in the delisting of our common stock from the NASDAQ
Stock Market or a default under our senior credit agreement, the indenture
governing our outstanding 12% senior notes due 2018, and any other
instruments governing debt that we may incur in the
future. Ultimately, such defaults could lead to the acceleration of
our debt obligations, and if an acceleration of our debt obligations were to
occur, we would probably not have sufficient funds to repay those obligations
immediately, and we would be forced to seek alternative repayment arrangements
either through a bankruptcy or an out of court debt
restructuring. Consequently, our material weaknesses could lead to
significant and negative changes to our financial condition and the value of our
equity and debt securities.
Natural
gas and oil prices fluctuate unpredictably and a decline in natural gas and oil
prices can significantly affect the value of our assets, our financial results
and impede our growth.
Our
revenue, profitability and cash flow depend in large part upon the prices and
demand for natural gas and oil. The markets for these commodities are
very volatile, and even relatively modest drops in prices can significantly
affect our financial results and impede our growth. Changes in
natural gas and oil prices have a significant effect on our cash flow and on the
value of our reserves, which can in turn reduce our borrowing base under our
senior credit agreement. Prices for natural gas and oil may fluctuate
widely in response to relatively minor changes in the supply of and demand for
natural gas and oil, market uncertainty and a variety of additional factors that
are beyond our control, including national and international economic and
political factors and federal and state legislation.
The
prices of natural gas and oil are volatile, often fluctuating
greatly. Lower natural gas and oil prices may not only reduce our
revenues, but also may reduce the amount of natural gas and oil that we can
produce economically. As a result, we may have to make substantial
downward adjustments to our estimated proved reserves. If this occurs
or if our estimates of development costs increase, production data factors
change or our exploration results deteriorate, accounting rules may require us
to write-down operating assets to fair value, as a non-cash charge to
earnings. We assess impairment of capitalized costs of proved natural
gas and oil properties by comparing net capitalized costs to estimated
undiscounted future net cash flows on a field-by-field basis using estimated
production based upon prices at which management reasonably estimates such
products may be sold. In 2006, we recorded an impairment charge of
$1.5 million related to our Nesson field in North Dakota. There were
no impairments during 2007 or 2005. We may incur impairment charges
in the future, which could have a material adverse effect on the results of our
operations.
A
substantial part of our natural gas and oil production is located in the Rocky
Mountain Region, making it vulnerable to risks associated with operating in a
single major geographic area.
Our
operations have been focused on the Rocky Mountain Region, which means our
current producing properties and new drilling opportunities are geographically
concentrated in that area. Because our operations are not as
diversified geographically as many of our competitors, the success of our
operations and our profitability may be disproportionately exposed to the effect
of any regional events, including fluctuations in prices of natural gas and oil
produced from the wells in the region, natural disasters, restrictive
governmental regulations, transportation capacity constraints, curtailment of
production or interruption of transportation, and any resulting delays or
interruptions of production from existing or planned new wells.
During
the second half of 2007, natural gas prices in the Rocky Mountain Region have
fallen disproportionately when compared to other markets, due in part to
continuing constraints in transporting natural gas from producing properties in
the region. Because of the concentration of our operations in the
Rocky Mountain Region, such price decreases are more likely to have a material
adverse effect on our revenue, profitability and cash flow than those of our
more geographically diverse competitors.
Our
estimated natural gas and oil reserves are based on many assumptions that may
turn out to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions may materially affect the quantities and
present value of our reserves.
No one
can measure underground accumulations of natural gas and oil in an exact
way. Natural gas and oil reserve engineering requires subjective
estimates of underground accumulations of natural gas and oil and assumptions
concerning future natural gas and oil prices, production levels, and operating
and development costs over the economic life of the properties. As a
result, estimated quantities of proved reserves and projections of future
production rates and the timing of development expenditures may be
inaccurate. Independent petroleum engineers prepare our estimates of
natural gas and oil reserves using pricing, production, cost, tax and other
information that we provide. The reserve estimates are based on
certain assumptions regarding future natural gas and oil prices, production
levels, and operating and development costs that may prove
incorrect. Any significant variance from these assumptions to actual
figures could greatly affect:
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the
estimates of reserves;
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the
economically recoverable quantities of natural gas and oil attributable to
any particular group of properties;
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future
depreciation, depletion and amortization rates and
amounts;
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the
classifications of reserves based on risk of recovery;
and
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estimates
of the future net cash flows.
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Some of
our reserve estimates must be made with limited production history, which
renders these reserve estimates less reliable than estimates based on a longer
production history. Numerous changes over time to the assumptions on
which the reserve estimates are based, as described above, often result in the
actual quantities of natural gas and oil recovered being different from earlier
reserve estimates.
The
present value of our estimated future net cash flows from proved reserves is not
necessarily the same as the current market value of our estimated natural gas
and oil reserves (the SEC requires the use of year end prices). The
estimated discounted future net cash flows from proved reserves are based on
selling prices in effect on the day of estimate (year end). However,
factors such as actual prices we receive for natural gas and oil and hedging
instruments, the amount and timing of actual production, amount and timing of
future development costs, supply of and demand for natural gas and oil, and
changes in governmental regulations or taxation also affect our actual future
net cash flows from our natural gas and oil properties.
The
timing of both our production and incurrence of expenses in connection with the
development and production of natural gas and oil properties will affect the
timing of actual future net cash flows from proved reserves, and thus their
actual present value. In addition, the 10% discount factor (the rate
required by the SEC) we use when calculating discounted future net cash flows
may not be the most appropriate discount factor based on interest rates
currently in effect and risks associated with our natural gas and oil properties
or the natural gas and oil industry in general.
Unless
natural gas and oil reserves are replaced as they are produced, our reserves and
production will decline, which would adversely affect our future business,
financial condition and results of operations.
Producing
natural gas and oil reservoirs generally are characterized by declining
production rates that vary depending upon reservoir characteristics and other
factors. The rate of decline will change if production from existing
wells declines in a different manner than we estimated and the rate can change
due to other circumstances. Thus, our future natural gas and oil
reserves and production and, therefore, our cash flow and income, are highly
dependent on efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves. We
may not be able to develop, discover or acquire additional reserves to replace
our current and future production at acceptable costs. As a result,
our future operations, financial condition and results of operations would be
adversely affected.
Acquisitions
are subject to the uncertainties of evaluating recoverable reserves and
potential liabilities.
Acquisitions
of producing properties and undeveloped properties have been an important part
of our historical growth. We expect acquisitions will also contribute
to our future growth. Successful acquisitions require an assessment
of a number of factors, many of which are beyond our control. These
factors include recoverable reserves, development potential, future natural gas
and oil prices, operating costs and potential environmental and other
liabilities. Such assessments are inexact and their accuracy is
inherently uncertain. In connection with our assessments, we perform
engineering, geological and geophysical reviews of the acquired properties,
which we believe is generally consistent with industry
practices. However, such reviews are not likely to permit us to
become sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. We do not inspect every well prior to
an acquisition. Even when we inspect a well, we do not always
discover structural, subsurface and environmental problems that may exist or
arise. In some cases, our review prior to signing a definitive
purchase agreement may be even more limited.
Our focus
on acquiring producing natural gas and oil properties may increase our potential
exposure to liabilities and costs for environmental and other problems existing
on acquired properties. Often we are not entitled to contractual
indemnification associated with acquired properties. Normally, we
acquire interests in properties on an “as is” basis with no or limited remedies
for breaches of representations and warranties, as was the case in the
acquisitions of assets from EXCO Resources Inc. and Castle, as well as the
acquisition of all shares of Unioil. We could incur significant
unknown liabilities, including environmental liabilities, or experience losses
due to title defects, in our acquisitions for which we have limited or no
contractual remedies or insurance coverage.
Additionally,
significant acquisitions can change the nature of our operations depending upon
the character of the acquired properties, which may have substantially different
operating and geological characteristics or be in different geographic locations
than our existing properties. For example, in the Castle acquisition,
we acquired interests in wells which we will need to operate together with other
partners, we acquired pipelines that we will need to operate and expect we will
need to commit to drilling in the acquired areas to achieve the expected
benefits. Consequently, we may not be able to efficiently realize the
assumed or expected economic benefits of properties that we acquire, if at
all.
When
drilling prospects, we may not yield natural gas or oil in commercially viable
quantities.
A
prospect is a property on which our geologists have identified what they
believe, based on available information, to be indications of natural gas or oil
bearing rocks. However, our geologists cannot know conclusively prior
to drilling and testing whether natural gas or oil will be present or, if
present, whether natural gas or oil will be present in sufficient quantities to
repay drilling or completion costs and generate a profit given the available
data and technology. If a well is determined to be dry or uneconomic,
which can occur even though it contains some oil or natural gas, it is
classified as a dry hole and must be plugged and abandoned in accordance with
applicable regulations. This generally results in the loss of the
entire cost of drilling and completion to that point, the cost of plugging, and
lease costs associated with the prospect. Even wells that are
completed and placed into production may not produce sufficient natural gas and
oil to be profitable. If we drill a dry hole or unprofitable well on
current and future prospects, the profitability of our operations will decline
and our value will likely be reduced. In sum, the cost of drilling,
completing and operating any well is often uncertain and new wells may not be
productive.
We
may not be able to identify enough attractive prospects on a timely basis to
meet our development needs, which could limit our future development
opportunities.
Our
geologists have identified a number of potential drilling locations on our
existing acreage. These drilling locations must be replaced as they
are drilled for us to continue to grow our reserves and
production. Our ability to identify and acquire new drilling
locations depends on a number of uncertainties, including the availability of
capital, regulatory approvals, natural gas and oil prices, competition, costs,
availability of drilling rigs, drilling results and the ability of our
geologists to successfully identify potentially successful new areas to
develop. Because of these uncertainties, our profitability and growth
opportunities may be limited by the timely availability of new drilling
locations. As a result, our operations and profitability could be
adversely affected.
Drilling
for and producing natural gas and oil are high risk activities with many
uncertainties that could adversely affect our business, financial condition and
results of operations.
Drilling
activities are subject to many risks, including the risk that we will not
discover commercially productive reservoirs. Drilling for natural gas and oil
can be unprofitable, not only due to dry holes, but also due to curtailments,
delays or cancellations as a result of other factors, including:
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unusual
or unexpected geological
formations;
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loss
of drilling fluid circulation;
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facility
or equipment malfunctions;
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unexpected
operational events;
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shortages
or delivery delays of equipment and
services;
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compliance
with environmental and other governmental requirements;
and
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adverse
weather conditions.
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Any of
these risks can cause substantial losses, including personal injury or loss of
life, damage to or destruction of property, natural resources and equipment,
pollution, environmental contamination or loss of wells and regulatory
penalties. We maintain insurance against various losses and
liabilities arising from operations; however, insurance against all operational
risks is not available. Additionally, our management may elect not to
obtain insurance if the cost of available insurance is excessive relative to the
perceived risks presented. Thus, losses could occur for uninsurable or uninsured
risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a
material adverse effect on business activities, financial condition and results
of operations.
We
may be forced to curtail our drilling operations, thereby reducing revenue and
profits from new natural gas and oil wells and from our drilling and completion
activities, due to increased drilling activity, particularly in the Rocky
Mountain Region, which may create a shortage of drilling rigs, service
providers, or materials.
With high
natural gas and oil prices, many natural gas and oil companies have increased
the drilling and completing of new wells and the reworking of old
wells. At the same time there is a limited supply of drilling rigs,
completion equipment and qualified personnel to provide the services necessary
to drill, complete and rework new wells. We do not own any drilling
rigs. The Rocky Mountain Region has seen a great increase in activity over the
past few years. If the demand for these goods and services continues
to increase, shortages may develop, which could result in increased prices for
these goods and services or our inability to complete all of the drilling we
have planned. Thus, we could be forced to drill less, and we could
temporarily or permanently lose all or part of our drilling operations,
negatively affecting our profits.
Our oil and gas well drilling
operations segment has historically received most of its revenue from the
partnerships we sponsor, and a reduction or loss of that business could reduce
or eliminated the revenue, profit and cash flow associated with those
activities.
Our
oil and gas well drilling operations segment has historically received most of
its revenue from the partnerships we sponsor. We sponsor oil and natural
gas partnerships through a network of non-affiliated NASD broker dealers.
In January 2008, we announced that we would not be offering a partnership in
2008. There can be no assurance that the network of brokers will be
available or can be recreated if we wish to use partnerships to raise funds in
future years. In that situation, our operations and profitability could be
adversely affected.
Under
the “successful efforts” accounting method that we use, unsuccessful exploratory
wells must be expensed in the period when they are determined to be
non-productive, which reduces our net income in such periods and could have a
negative effect on our profitability.
We
conducted exploratory drilling in 2006 and 2007 and plan to continue exploratory
drilling in 2008 in order to identify additional opportunities for future
development. Under the “successful efforts” method of accounting that
we use, the cost of unsuccessful exploratory wells must be charged to expense in
the period when they are determined to be unsuccessful. In addition,
lease costs for acreage condemned by the unsuccessful well must also be
expensed. In contrast, unsuccessful development wells are capitalized
as a part of the investment in the field where they are
located. Because exploratory wells generally are more likely to be
unsuccessful than development wells, we anticipate that some or all of our
exploratory wells may not be productive. The costs of such
unsuccessful exploratory wells could result in a significant reduction in our
profitability in periods when the costs are required to be expensed and these
increased costs could reduce our net income and have a negative effect on our
profitability and ability to repay or refinance our indebtedness.
Increasing
finding and development costs may impair our profitability.
In order
to continue to grow and maintain our profitability, we must annually add new
reserves that exceed our yearly production at a finding and development cost
that yields an acceptable operating margin and depreciation, depletion and
amortization rate. Without cost effective exploration, development or
acquisition activities, our production, reserves and profitability will decline
over time. Given the relative maturity of most natural gas and oil
basins in North America and the high level of activity in the industry, the cost
of finding new reserves through exploration and development operations has been
increasing. The acquisition market for natural gas and oil properties
has become extremely competitive among producers for additional production and
expanded drilling opportunities in North America. Acquisition values
climbed toward historic highs during 2006 and 2007 on a per unit basis,
particularly in the Rocky Mountain Region, and we believe these values may
continue to increase in 2008. This increase in finding and
development costs results in higher depreciation, depletion and amortization
rates. If the upward trend in finding and development costs
continues, we will be exposed to an increased likelihood of a write-down in
carrying value of our natural gas and oil properties in response to falling
commodity prices and reduced profitability of our operations.
Our
development and exploration operations require substantial capital, and we may
be unable to obtain needed capital or financing on satisfactory terms, which
could lead to a loss of properties and a decline in our natural gas and oil
reserves.
The
natural gas and oil industry is capital intensive. We make and expect
to continue to make substantial capital expenditures in our business and
operations for the exploration, development, production and acquisition of
natural gas and oil reserves. To date, we have financed capital
expenditures primarily with bank borrowings and cash generated by
operations. We intend to finance our future capital expenditures with
cash flow from operations and our existing and planned financing
arrangements. Our cash flow from operations and access to capital are
subject to a number of variables, including:
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the
amount of natural gas and oil we are able to produce from existing
wells;
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the
prices at which natural gas and oil are
sold;
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the
costs to produce oil and natural gas;
and
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our
ability to acquire, locate and produce new
reserves.
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If our
revenues or the borrowing base under our credit facility decreases as a result
of lower natural gas and oil prices, operating difficulties, declines in
reserves or for any other reason, then we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. We
may, from time to time, need to seek additional financing. There can
be no assurance as to the availability or terms of any additional
financing.
If our revenues or the
borrowing base under our revolving credit facility decrease as a result of lower
natural gas and oil prices, or we incur operating difficulties, declines in
reserves or for any other reason, we may have limited ability to obtain the
capital necessary to sustain our operations at planned
levels.
If
additional capital is needed, we may not be able to obtain debt or equity
financing on favorable terms, or at all. If cash generated by our
operations or sale of drilling partnerships or available under our revolving
credit facility is not sufficient to meet our capital requirements, failure to
obtain additional financing could result in a curtailment of the exploration and
development of our prospects, which in turn could lead to a possible loss of
properties, decline in natural gas and oil reserves and a decline in our
profitability.
Our
credit facility has substantial restrictions and financial covenants and we may
have difficulty obtaining additional credit, which could adversely affect our
operations.
We depend
on our revolving credit facility for future capital needs. The terms
of the borrowing agreement require us to comply with certain financial covenants
and ratios. Our ability to comply with these restrictions and
covenants in the future is uncertain and will be affected by the levels of cash
flows from operations and events or circumstances beyond our
control. Our failure to comply with any of the restrictions and
covenants under the revolving credit facility or other debt financing could
result in a default under those facilities, which could cause all of our
existing indebtedness to be immediately due and payable.
The
revolving credit facility limits the amounts we can borrow to a borrowing base
amount, determined by the lenders in their sole discretion based upon projected
revenues from the natural gas and oil properties securing their
loan. The lenders can unilaterally adjust the borrowing base and the
borrowings permitted to be outstanding under the revolving credit
facility. Outstanding borrowings in excess of the borrowing base must
be repaid immediately, or we must pledge other natural gas and oil properties as
additional collateral. We do not currently have any substantial unpledged
properties, and we may not have the financial resources in the future to make
any mandatory principal prepayments required under the revolving credit
facility. Our inability to borrow additional funds under our credit
facility could adversely affect our operations.
Seasonal
weather conditions and lease stipulations adversely affect our ability to
conduct drilling activities in some of the areas where we operate.
Seasonal
weather conditions and lease stipulations designed to protect various wildlife
affect natural gas and oil operations in the Rocky Mountains. In
certain areas, including parts of the Piceance Basin in Colorado, drilling and
other natural gas and oil activities are restricted or prohibited by lease
stipulations, or prevented by weather conditions, for up to six months out of
the year. This limits our operations in those areas and can intensify
competition during those months for drilling rigs, oil field equipment,
services, supplies and qualified personnel, which may lead to periodic
shortages. These constraints and the resulting shortages or high
costs could delay our operations and materially increase operating and capital
costs and therefore adversely affect our profitability.
We
have limited control over activities on properties in which we own an interest
but we do not operate, which could reduce our production and
revenues.
We
operate most of the wells in which we own an interest. However, there
are some wells we do not operate because we participate through joint operating
agreements under which we own partial interests in natural gas and oil
properties operated by other entities. If we do not operate the
properties in which we own an interest, we do not have control over normal
operating procedures, expenditures or future development of underlying
properties. The failure of an operator to adequately perform
operations, or an operator’s breach of the applicable agreements, could reduce
production and revenues and affect our profitability. The success and
timing of drilling and development activities on properties operated by others
therefore depends upon a number of factors outside of our control, including the
operator’s timing and amount of capital expenditures, expertise (including
safety and environmental compliance) and financial resources, inclusion of other
participants in drilling wells, and use of technology.
Market
conditions or operational impediments could hinder our access to natural gas and
oil markets or delay production.
Market
conditions or the unavailability of satisfactory natural gas and oil
transportation arrangements may hinder our access to natural gas and oil markets
or delay our production. The availability of a ready market for
natural gas and oil production depends on a number of factors, including the
demand for and supply of natural gas and oil and the proximity of reserves to
pipelines and terminal facilities. Our ability to market our
production depends in substantial part on the availability and capacity of
gathering systems, pipelines and processing facilities owned and operated by
third parties. Failure to obtain such services on acceptable terms
could materially harm our business. We may be required to shut in
wells for lack of market or because of inadequacy, unavailability or the pricing
associated with natural gas pipeline, gathering system capacity or processing
facilities. If that were to occur, we would be unable to realize
revenue from those wells until we made production arrangements to deliver the
product to market. Thus, our profitability would be adversely
affected.
Our
derivative activities could result in financial losses or reduced
income.
We use
derivatives for a portion of our natural gas and oil production from our own
wells, our partnerships and for natural gas purchases and sales by our marketing
subsidiary to achieve a more predictable cash flow, to reduce exposure to
adverse fluctuations in the prices of natural gas and oil, and to allow our
natural gas marketing company to offer pricing options to natural gas sellers
and purchasers. These arrangements expose us to the risk of financial loss in
some circumstances, including when purchases or sales are different than
expected, the counter-party to the derivative contract defaults on its contract
obligations, or when there is a change in the expected differential between the
underlying price in the derivative agreement and actual prices that we
receive. In addition, derivative arrangements may limit the benefit
from changes in the prices for natural gas and oil and may require the use of
our resources to meet cash margin requirements. Since our derivatives
do not currently qualify for use of hedge accounting, changes in the fair value
of derivatives are recorded in our income statements, and our net income is
subject to greater volatility than if our derivative instruments qualified for
hedge accounting. For instance, we have recently increased our derivative
use. The market prices for oil and natural gas, however, have continued to
increase since such derivatives were entered; if such market pricing continues,
it could result in significant non-cash charges each quarter, which could have a
material negative affect on our net income.
The
inability of one or more of our customers to meet their obligations may
adversely affect our financial results.
Substantially
all of our accounts receivable result from natural gas and oil sales or joint
interest billings to a small number of third parties in the energy
industry. This concentration of customers and joint interest owners
may affect our overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions. In addition,
our natural gas and oil derivatives as well as the derivatives used by our
marketing subsidiary expose us to credit risk in the event of nonperformance by
counterparties.
Terrorist
attacks or similar hostilities may adversely affect our results of
operations.
Increasing
terrorist attacks around the world have created many economic and political
uncertainties, some of which may materially adversely affect our
business. Uncertainty surrounding military strikes or a sustained
military campaign may affect our operations in unpredictable ways, including
disruptions of fuel supplies and markets, particularly oil, and the possibility
that infrastructure facilities, including pipelines, production facilities,
processing plants and refineries, could be direct targets of, or indirect
casualties of, an act of terror or war. The continuation of these
attacks may subject our operations to increased risks and, depending on their
ultimate magnitude, could have a material adverse effect on our business,
results of operations, financial condition and prospects.
Our
insurance coverage may not be sufficient to cover some liabilities or losses
that we may incur.
The
occurrence of a significant accident or other event not fully covered by
insurance could have a material adverse effect on our operations and financial
condition. Insurance does not protect us against all operational
risks. We do not carry business interruption insurance at levels that
would provide enough funds for us to continue operating without access to other
funds. For some risks, we may not obtain insurance if we believe the
cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks that we are
subject to are generally not fully insurable.
We
may not be able to keep pace with technological developments in our
industry.
The
natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As our competitors use or develop new technologies,
we may be placed at a competitive disadvantage, and competitive pressures may
force us to implement those new technologies at substantial cost. In
addition, other natural gas and oil companies may have greater financial,
technical and personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new technologies before
we can. We may not be able to respond to these competitive pressures
and implement new technologies on a timely basis or at an acceptable
cost. If one or more of the technologies we use now or in the future
were to become obsolete or if we were unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.
Competition
in the natural gas and oil industry is intense, which may adversely affect our
ability to succeed.
The
natural gas and oil industry is intensely competitive, and we compete with other
companies that have greater resources. Many of these companies not
only explore for and produce natural gas and oil, but also carry on refining
operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for
productive natural gas and oil properties and exploratory prospects or define,
evaluate, bid for and purchase a greater number of properties and prospects than
we can. In addition, these companies may have a greater ability to
continue exploration activities during periods of low natural gas and oil market
prices. Larger competitors may be able to absorb the burden of
present and future federal, state, local and other laws and regulations more
easily than we can, which can adversely affect our competitive
position. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon our ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment. In addition, because many companies
in our industry have greater financial and human resources, we may be at a
disadvantage in bidding for exploratory prospects and producing natural gas and
oil properties. These factors could adversely affect the success of
our operations and our profitability.
We
are subject to complex federal, state, local and other laws and regulations that
could adversely affect the cost, manner or feasibility of doing
business.
Our
exploration, development, production and marketing operations are regulated
extensively at the federal, state and local levels. Environmental and other
governmental laws and regulations have increased the costs to plan, design,
drill, install, operate and abandon natural gas and oil wells. Under
these laws and regulations, we could also be liable for personal injuries,
property damage and other damages. Failure to comply with these laws
and regulations may result in the suspension or termination of operations and
subject us to administrative, civil and criminal penalties. Moreover,
public interest in environmental protection has increased in recent years, and
environmental organizations have opposed, with some success, certain drilling
projects.
Part of
the regulatory environment includes federal requirements for obtaining
environmental assessments, environmental impact studies and/or plans of
development before commencing exploration and production
activities. In addition, our activities are subject to the regulation
by natural gas and oil-producing states of conservation practices and protection
of correlative rights. These regulations affect our operations and
limit the quantity of natural gas and oil that can be produced and
sold. A major risk inherent in our drilling plans is the need to
obtain drilling permits from state and local authorities. Delays in
obtaining regulatory approvals, drilling permits, the failure to obtain a
drilling permit for a well or the receipt of a permit with unreasonable
conditions or costs could have a material adverse effect on our ability to
explore on or develop our properties. Additionally, the natural gas
and oil regulatory environment could change in ways that might substantially
increase our financial and managerial costs to comply with the requirements of
these laws and regulations and, consequently, adversely affect our
profitability. Furthermore, these additional costs may put us at a
competitive disadvantage compared to larger companies in the industry who can
spread such additional costs over a greater number of wells and larger operating
staff.
Litigation
has been commenced against us pertaining to our royalty practices and payments;
the cost of our defending these lawsuits, and any future similar lawsuit, could
be significant and any resulting judgments against us could have a material
adverse effect upon our financial condition.
Recent
litigation has commenced against us and several other companies in our industry
regarding royalty practices and payments in jurisdictions where we conduct
business. For more information on the two suits that currently relate
to us, see Item
3, Legal
Proceedings. We intend to defend ourselves vigorously in these
cases. Even if the ultimate outcome of this litigation resulted in
our dismissal, defense costs could be significant. These costs would
be reflected in terms of dollar outlay as well as the amount of time, attention
and other resources that our management would have to appropriate to the
defense. Although we cannot predict an eventual outcome of this
litigation, a judgment in favor of a plaintiff could have a material adverse
effect on our financial condition.
Information
technology financial systems implementation problems could disrupt our internal
business operations and adversely affect our business financial results or our
ability to report our financial results.
We are
currently in the process of implementing a new financial software system to
enhance operating efficiencies and provide more effective management of our
business operations. Our implementation is based on a phased
approach, with the financial reporting system to be implemented in the first
quarter of 2008. Implementations of financial systems and related
software carry such risks as cost overruns, project delays and business
interruptions, which could increase our expense, have an adverse effect on our
business, our ability to report in
an accurate and timely manner our financial position and our results of
operations and cash flows.
Risks
Associated with Our Indebtedness
We
may incur additional indebtedness to facilitate our acquisition of additional
properties, which would increase our leverage and could negatively affect our
business or financial condition.
Our
business strategy includes the acquisition of additional properties that we
believe would have a positive effect on our current business and
operations. We expect to continue to pursue acquisitions of such
properties and may incur additional indebtedness to finance the
acquisitions. Our incurrence of additional indebtedness would
increase our leverage and our interest expense, which could have a negative
effect on our business or financial condition.
If
we fail to obtain additional financing, we may be unable to refinance our
existing debt, expand our current operations or acquire new businesses. This
could result in our failure to grow in accordance with our plans, or could
result in defaults in our obligations under our senior credit agreement or the
indenture relating to our outstanding senior notes.
In order
to refinance indebtedness, expand existing operations and acquire additional
businesses or properties, we will require substantial amounts of
capital. There can be no assurance that financing, whether from
equity or debt financings or other sources, will be available or, if available,
will be on terms satisfactory to us. If we are unable to obtain such
financing, we will be unable to acquire additional businesses and may be unable
to meet our obligations under our senior credit agreement and the indenture
relating to our outstanding senior notes or any other debt securities we may
issue in the future.
The
indenture governing our outstanding senior notes and our senior credit agreement
impose (and we anticipate that the indentures governing any other debt
securities we may issue will also impose) restrictions on us that may limit the
discretion of management in operating our business. That, in turn, could impair
our ability to meet our obligations.
The
indenture governing our outstanding senior notes and our senior credit agreement
contain (and we anticipate that the indentures governing any other debt
securities we may issue will also contain) various restrictive covenants that
limit management’s discretion in operating our business. In
particular, these covenants limit our ability to, among other
things:
|
|
make
certain investments or pay dividends or distributions on our capital
stock, or purchase, redeem or retire capital
stock;
|
|
|
sell
assets, including capital stock of our restricted
subsidiaries;
|
|
|
restrict
dividends or other payments by restricted
subsidiaries;
|
|
|
enter
into transactions with affiliates;
and
|
|
|
merge
or consolidate with another
company.
|
These
covenants could materially and adversely affect our ability to finance our
future operations or capital needs. Furthermore, they may restrict
our ability to expand, to pursue our business strategies and otherwise conduct
our business. Our ability to comply with these covenants may be
affected by circumstances and events beyond our control, such as prevailing
economic conditions and changes in regulations, and we cannot assure you that we
will be able to comply with them. A breach of these covenants could
result in a default under the indenture governing our outstanding senior notes
and any other debt securities we may issue in the future and/or our senior
credit agreement. If there were an event of default under our
indenture and/or the senior credit agreement, the affected creditors could cause
all amounts borrowed under these instruments to be due and payable
immediately. Additionally, if we fail to repay indebtedness under our
senior credit agreement when it becomes due, the lenders under the senior credit
agreement could proceed against the assets which we have pledged to them as
security. Our assets and cash flow might not be sufficient to repay
our outstanding debt in the event of a default.
Our
senior credit agreement also requires us to maintain specified financial ratios
and satisfy certain financial tests. Our ability to maintain or meet
such financial ratios and tests may be affected by events beyond our control,
including changes in general economic and business conditions, and we cannot
assure you that we will maintain or meet such ratios and tests, or that the
lenders under the senior credit agreement will waive any failure to meet such
ratios or tests.
None.
Information
regarding our wells, production, proved reserves and acreage are included in
Item 1 and in Note
1, Summary of
Significant Accounting Policies, to our consolidated financial statements
included in this report.
Substantially
all of our oil and natural gas properties have been mortgaged or pledged as
security for our credit facility. See Note 5, Long Term Debt, to our
consolidated financial statements included in this report.
Facilities
We own
our 32,000 square feet corporate office building located in Bridgeport, West
Virginia. In February 2008, we entered into an agreement to lease
approximately 17,000 square feet of office space in a building under
construction near the corporate office and purchased an approximate 12 acre,
undeveloped parcel of land adjacent to our existing corporate offices for
potential future expansion of the corporate office facility. We
maintain a lease for 13,000 square feet of administrative office space in
downtown Denver, Colorado through May 2012.
We own or
lease field operating facilities in the following locations:
|
·
|
West
Virginia: Bridgeport, Glenville and West
Union
|
|
·
|
Colorado: Evans,
Parachute and Wray
|
|
·
|
Pennsylvania: Indiana
and Mahaffey
|
Information
regarding our legal proceedings can be found in Note 8, Commitments and Contingencies –
Litigation, to our consolidated financial statements included in this
report.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
None.
PART
II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
Our
authorized capital stock consists of 50,000,000 shares of common stock, par
value $0.01 per share. There were 14,851,234 shares of common stock
issued and outstanding as of March 14, 2008. Our common stock is
traded on the NASDAQ Global Select Market under the ticker symbol
PETD.
The
following table sets forth the range of high and low sales prices for our common
stock as reported on the NASDAQ Global Select Market for the periods indicated
below.
|
|
High
|
|
|
Low
|
|
2007
|
|
|
|
|
|
|
First
Quarter
|
|
$ |
55.20
|
|
|
$ |
40.53
|
|
Second
Quarter
|
|
|
55.24
|
|
|
|
44.59
|
|
Third
Quarter
|
|
|
51.13
|
|
|
|
35.73
|
|
Fourth
Quarter
|
|
|
61.91
|
|
|
|
41.65
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
|
46.17
|
|
|
|
32.12
|
|
Second
Quarter
|
|
|
45.62
|
|
|
|
32.51
|
|
Third
Quarter
|
|
|
45.23
|
|
|
|
33.16
|
|
Fourth
Quarter
|
|
|
47.44
|
|
|
|
36.54
|
|
As of
March 14, 2008, we had approximately 1,242 shareholders of record.
We
have not paid any dividends on our common stock and currently intend to retain
earnings for use in our business. Therefore, we do not expect to
declare cash dividends in the foreseeable future.
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
|
|
|
|
Average
Price Paid per
Share
|
|
|
Total
Number of Shares Purchased
as Part of
Publicly Announced
Plans or
Programs
|
|
|
Maximum
Number of Shares that
May Yet Be
Purchased Under the
Plans or
Programs
|
|
Shares
purchased prior to October 1, 2007, under the current
repurchase program.
|
|
|
6,833
|
|
|
$ |
50.63
|
|
|
|
6,833
|
|
|
|
1,470,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth
quarter purchases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October
1 - 31, 2007
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
November
1-30, 2007
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
December
1-31, 2007
|
|
|
5,187
|
|
|
|
57.93
|
|
|
|
5,187
|
|
|
|
1,465,089
|
|
Total
fourth quarter purchases
|
|
|
5,187
|
|
|
|
|
|
|
|
5,187
|
|
|
|
|
|
Total
shares purchased under the current program
|
|
|
12,020
|
|
|
|
53.78
|
|
|
|
12,020
|
|
|
|
1,465,089
|
|
On
October 16, 2006, our Board of Directors approved a second 2006 share purchase
program authorizing us to purchase up to 10% of our then outstanding common
stock (1,477,109 shares) through April 2008. Stock purchases under
this program may be made in the open market or in private transactions, at times
and in amounts that we deem appropriate. Shares are generally
purchased at fair market value based on the closing price on the date of
purchase. Total shares purchased in 2007 pursuant to the program were
12,020 common shares at a cost of $0.6 million ($53.78 average price paid per
share), including 5,187 shares from our executive officers at a cost of $0.3
million ($57.93 price paid per share). Shares purchased pursuant to
the plan were primarily to satisfy the statutory minimum tax withholding
requirement for restricted stock that vested in 2007. All shares were
subsequently retired.
Pursuant to
our senior notes indenture entered on February 8, 2008, any future purchases are
limited, see Note 19, Subsequent Events,
to our accompanying consolidated financial statements.
On
February 25, 2008, pursuant to a separation agreement, we purchased 50,000
shares of our common stock from one of our executive officers at a cost of $3.4
million, or $67.92 per share. See Note 19, Subsequent Events, to our
consolidated financial statements included in this report.
SHAREHOLDER
PERFORMANCE GRAPH
The
performance graph below compares the cumulative total return of our common stock
over a five year period ended December 31, 2007, with the cumulative total
returns for the same period for a Standard Industrial Code Index, or SIC, and
the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is
a weighted composite of 154 crude petroleum and natural gas
companies. The cumulative total shareholder return assumes that $100
was invested, including reinvestment of dividends, if any, in our common stock
on December 31, 2002, and in the S&P 500 Index and the SIC Code Index on the
same date. The results shown in the graph below are not necessarily
indicative of future performance.
|
|
Year
Ended December 31,
|
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PETROLEUM
DEVELOPMENT CORPORATION
|
|
$ |
100.00 |
|
|
$ |
447.17 |
|
|
$ |
727.74 |
|
|
$ |
629.06 |
|
|
$ |
812.26 |
|
|
$ |
1,115.66 |
|
SIC
CODE INDEX
|
|
|
100.00 |
|
|
|
160.61 |
|
|
|
204.02 |
|
|
|
293.12 |
|
|
|
381.13 |
|
|
|
535.76 |
|
S&P
500 INDEX
|
|
|
100.00 |
|
|
|
128.68 |
|
|
|
142.69 |
|
|
|
149.70 |
|
|
|
173.34 |
|
|
|
182.87 |
|
|
|
Year
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(in
thousands, except per share data)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$ |
175,187 |
|
|
$ |
115,189 |
|
|
$ |
102,559 |
|
|
$ |
69,492 |
|
|
$ |
48,394 |
|
Sales
from natural gas marketing activities
|
|
|
103,624 |
|
|
|
131,325 |
|
|
|
121,104 |
|
|
|
94,627 |
|
|
|
73,132 |
|
Oil
and gas well drilling operations (1)
|
|
|
12,154 |
|
|
|
17,917 |
|
|
|
99,963 |
|
|
|
94,076 |
|
|
|
57,510 |
|
Well
operations and pipeline income
|
|
|
9,342 |
|
|
|
10,704 |
|
|
|
8,760 |
|
|
|
7,677 |
|
|
|
6,907 |
|
Oil
and gas price risk management (loss) gain, net
|
|
|
2,756 |
|
|
|
9,147 |
|
|
|
(9,368 |
) |
|
|
(3,085 |
) |
|
|
(812 |
) |
Other
|
|
|
2,172 |
|
|
|
2,221 |
|
|
|
2,180 |
|
|
|
1,696 |
|
|
|
3,338 |
|
Total
revenues
|
|
|
305,235 |
|
|
|
286,503 |
|
|
|
325,198 |
|
|
|
264,483 |
|
|
|
188,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas production and well operations costs
|
|
|
49,264 |
|
|
|
29,021 |
|
|
|
20,400 |
|
|
|
17,713 |
|
|
|
13,630 |
|
Cost
of natural gas marketing activities
|
|
|
100,584 |
|
|
|
130,150 |
|
|
|
119,644 |
|
|
|
92,881 |
|
|
|
72,361 |
|
Cost
of oil and gas well drilling operations (1)
|
|
|
2,508 |
|
|
|
12,617 |
|
|
|
88,185 |
|
|
|
77,696 |
|
|
|
46,946 |
|
Exploration
expense
|
|
|
23,551 |
|
|
|
8,131 |
|
|
|
11,115 |
|
|
|
- |
|
|
|
- |
|
General
and administrative expense
|
|
|
30,968 |
|
|
|
19,047 |
|
|
|
6,960 |
|
|
|
4,506 |
|
|
|
4,975 |
|
Depreciation,
depletion and amortization
|
|
|
70,844 |
|
|
|
33,735 |
|
|
|
21,116 |
|
|
|
18,156 |
|
|
|
15,313 |
|
Total
costs and expenses
|
|
|
277,719 |
|
|
|
232,701 |
|
|
|
267,420 |
|
|
|
210,952 |
|
|
|
153,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on sale of leaseholds (2)
|
|
|
33,291 |
|
|
|
328,000 |
|
|
|
7,669 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
|
60,807 |
|
|
|
381,802 |
|
|
|
65,447 |
|
|
|
53,531 |
|
|
|
35,244 |
|
Interest
income
|
|
|
2,662 |
|
|
|
8,050 |
|
|
|
898 |
|
|
|
185 |
|
|
|
190 |
|
Interest
expense
|
|
|
(9,279 |
) |
|
|
(2,443 |
) |
|
|
(217 |
) |
|
|
(238 |
) |
|
|
(816 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes and cumulative effect of change in accounting
principle
|
|
|
54,190 |
|
|
|
387,409 |
|
|
|
66,128 |
|
|
|
53,478 |
|
|
|
34,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for income taxes
|
|
|
20,981 |
|
|
|
149,637 |
|
|
|
24,676 |
|
|
|
20,250 |
|
|
|
11,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before cumulative effect of change in accounting principle
|
|
|
33,209 |
|
|
|
237,772 |
|
|
|
41,452 |
|
|
|
33,228 |
|
|
|
22,684 |
|
Cumulative
effect of change in accounting principle (net of taxes of $1,392) (3)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,271 |
) |
Net
income
|
|
$ |
33,209 |
|
|
$ |
237,772 |
|
|
$ |
41,452 |
|
|
$ |
33,228 |
|
|
$ |
20,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$ |
2.25 |
|
|
$ |
15.18 |
|
|
$ |
2.53 |
|
|
$ |
2.05 |
|
|
$ |
1.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share
|
|
$ |
2.24 |
|
|
$ |
15.11 |
|
|
$ |
2.52 |
|
|
$ |
2.00 |
|
|
$ |
1.25 |
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
Total
assets
|
|
$ |
1,050,479 |
|
|
$ |
884,287 |
|
|
$ |
444,361 |
|
|
$ |
329,453 |
|
|
$ |
294,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital (deficit)
|
|
$ |
(50,212 |
) |
|
$ |
29,180 |
|
|
$ |
(16,763 |
) |
|
$ |
231 |
|
|
$ |
7,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$ |
235,000 |
|
|
$ |
117,000 |
|
|
$ |
24,000 |
|
|
$ |
21,000 |
|
|
$ |
53,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders'
equity
|
|
$ |
395,526 |
|
|
$ |
360,144 |
|
|
$ |
188,265 |
|
|
$ |
154,021 |
|
|
$ |
112,559 |
|
(1)
|
In
December 2005, we began entering into cost-plus drilling service
arrangements, which are recorded on a net basis unlike our footage based
arrangements which are recorded on a gross basis. See Note 1,
"Summary of Significant Accounting Policies," to our consolidated
financial statements included in this
report.
|
(2)
|
In
July 2006, we sold a portion of our undeveloped leasehold located in Grand
Valley Field, Garfield County, Colorado. See Note 16, "Sale
of Oil and Gas Properties," to our consolidated financial statements
included in this report.
|
(3)
|
Represents
the income effect of the adoption of SFAS No. 143, Accounting for Asset
Retirement Obligations. See Note 7, "Asset
Retirement Obligation," to our consolidated financial statements included
in this report.
|
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The
following discussion and analysis, as well as other sections in this Form 10-K,
should be read in conjunction with our accompanying consolidated financial
statements and related notes to consolidated financial statements included in
this report.
Year Ended December 31,
2007, Compared to December 31, 2006
Management
Overview
Net
Income
The
following table presents net income and diluted earnings per share for the year
ended December 31, 2007 and 2006.
|
|
Year
Ended December 31,
|
|
|
Change
|
|
|
|
2007
|
|
|
2006
|
|
|
Amount
|
|
|
Percent
|
|
|
|
(dollars
in thousands, except per share data)
|
|
|
|
|
|
Net
income
|
|
$ |
33,209 |
|
|
$ |
237,772 |
|
|
$ |
(204,563 |
) |
|
|
-86.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
earnings per share
|
|
$ |
2.24 |
|
|
$ |
15.11 |
|
|
$ |
(12.87 |
) |
|
|