UNITED STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
T
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For
the
fiscal year ended December 31, 2006
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
|
|
|
(State
of incorporation)
|
(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 exchange on which registered
|
|
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Common
Stock, par value $.01 per share
|
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
T
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
T
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 T
No
£
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. T
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 £
|
Accelerated
Filer T
|
Non-Accelerated
Filer £
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes £
No
T
As
of
April 30, 2007, 14,887,530 shares of the Registrant's Common Stock were issued
and outstanding.
The
aggregate market value of such shares held by non-affiliates of the Registrant
on June 30, 2006, the last business day of the Registrant's most recently
completed second quarter was $610,385,733 (based on the last traded price of
$37.70).
DOCUMENTS
INCORPORATED BY REFERENCE
None.
PETROLEUM
DEVELOPMENT CORPORATION
INDEX
TO 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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5
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Item
1A:
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15
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Item
1B:
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24
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Item
2:
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24
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Item
3:
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28
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Item
4:
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28
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PART
II
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Item
5:
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28
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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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49
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Item
8:
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51
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Item
9:
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52
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Item
9A:
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52
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Item
9B:
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57
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PART
III
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Item
10:
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57
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Item
11:
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60
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Item
12:
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74
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Item
13:
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75
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Item
14:
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76
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PART
IV
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Item
15:
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77
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78
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GLOSSARY
OF TERMS
The
following are abbreviations and definitions of terms commonly used in the oil
and gas industry and this Form 10-K.
Bbl
- One
barrel, or 42 U.S. gallons of liquid volume.
Bcf
- One
billion cubic feet.
Bcfe
- One
billion cubic feet of natural gas equivalents.
Completion
- The
installation of permanent equipment for the production of oil or
gas.
Credit
Facility
-
A
line of
credit provided by a group of banks, secured by oil and gas
properties.
DD&A
-
Refers
to
depreciation, depletion and amortization of the Company’s property and
equipment.
Development
well
- A well
drilled within the proved area of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Division
order
- A
contract setting forth the interest of each owner of an oil and gas property,
and serves as the basis on which the purchasing company pays each owner’s
respective share of the proceeds of the oil and gas purchased.
Dry
hole
- A well
found to be incapable of producing hydrocarbons in sufficient quantities to
justify completion as an oil or gas well.
Exploratory
well
- A well
drilled to find and produce oil or natural gas reserves not classified as
proved, to find a new productive reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to extend a known
reservoir.
Extensions
and discoveries
- As to
any period, the increases to proved reserves from all sources other than the
acquisition of proved properties or revisions of previous
estimates.
Gross
acres or wells
- Refers
to the total acres or wells in which the Company has a working
interest.
Horizontal
drilling
- A
drilling technique that permits the operator to contact and intersect a larger
portion of the producing horizon than conventional vertical drilling techniques
and may, depending on the horizon, result in increased production rates and
greater ultimate recoveries of hydrocarbons.
MBbls
- One
thousand barrels.
Mcf
- One
thousand cubic feet.
Mcfe
- One
thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for
each barrel of oil, which reflects the relative energy content.
MMbtu
-
One
million British thermal units. One British thermal unit is the heat required
to
raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
MMcf
- One
million cubic feet.
MMcfe
-
One
million cubic feet of natural gas equivalents.
Natural
gas liquids
- Liquid
hydrocarbons that have been extracted from natural gas, such as ethane, propane,
butane and natural gasoline.
Net
acres or wells
- Refers
to gross acres or wells multiplied, in each case, by the percentage working
interest owned by the Company.
Net
production
- Oil
and gas production that is owned by the Company, less royalties and production
due others.
NYMEX
- New
York Mercantile Exchange, the exchange on which commodities, including crude
oil
and natural gas futures contracts, are traded.
Oil
- Crude
oil or condensate.
Operator
- The
individual or company responsible for the exploration, development and
production of an oil or gas well or lease.
Present
value of proved reserves
- The
present value of estimated future revenues, discounted at 10% annually, to
be
generated from the production of proved reserves determined in accordance with
Securities and Exchange Commission guidelines, net of estimated production
and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to (i) estimated future
abandonment costs, net of the estimated salvage value of related equipment,
(ii) non-property related expenses such as general and administrative
expenses, debt service and future income tax expense, or
(iii) depreciation, depletion and amortization.
Proved
developed non-producing reserves
-
Reserves that consist of (i) proved reserves from wells which have been
completed and tested but are not producing due to lack of market or minor
completion problems which are expected to be corrected and (ii) proved reserves
currently behind the pipe in existing wells and which are expected to be
productive due to both the well log characteristics and analogous production
in
the immediate vicinity of the wells.
Proved
developed producing reserves
-
Proved
reserves that can be expected to be recovered from currently producing zones
under the continuation of present operating methods.
Proved
developed reserves
-
The
combination of proved developed producing and proved developed non-producing
reserves.
Proved
reserves
- The
estimated quantities of crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided
only by contractual arrangements, but not on escalations based upon future
conditions.
Proved
undeveloped reserves ("PUD")
- Proved
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion.
Recompletion
- A
recompletion occurs when the producer reenters a well to complete (i.e.,
perforate) a new formation from that in which a well has previously been
completed.
Royalty
- An
interest in an oil and gas lease that gives the owner of the interest the right
to receive a portion of the production from the leased acreage (or of the
proceeds of the sale thereof), but generally does not require the owner to
pay
any portion of the costs of drilling or operating the wells on the leased
acreage. Royalties may be either landowner’s royalties, which are reserved
by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold
in
connection with a transfer to a subsequent owner.
SEC
- The
United States Securities and Exchange Commission.
Standardized
measure of discounted future net cash flows
-
Present value of proved reserves, as adjusted to give effect to
(i) estimated future abandonment costs, net of the estimated salvage value
of related equipment, and (ii) estimated future income taxes.
Tcf
- One
trillion cubic feet.
Undeveloped
acreage
- Leased
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas, regardless of
whether such acreage contains proved reserves.
Working
interest
- An
interest in an oil and gas lease that gives the owner of the interest the right
to drill for and produce oil and gas on the leased acreage and requires the
owner to pay a share of the costs of drilling and production operations.
The share of production to which a working interest is entitled will be smaller
than the share of costs that the working interest owner is required to bear
to
the extent of any royalty burden.
Workover
-
Operations on a producing well to restore or increase production.
PART
I
ITEM
1: BUSINESS
Petroleum
Development Corporation is an independent energy company engaged primarily
in
the development, production and marketing of natural gas and oil. Since it
began
oil and gas operations in 1969, the Company has grown primarily through drilling
and development activities, the acquisition of producing natural gas and oil
wells and the expansion of its natural gas marketing activities. As of December
31, 2006, the Company has interests in approximately 3,100 wells located in
the
Rocky Mountain Region, Appalachian Basin and Michigan with gross proved reserves
of 719 billion cubic feet equivalent of natural gas (“Bcfe”, based on one barrel
of oil equaling six thousand cubic feet equivalent of natural gas (“Mcfe”)) of
which the Company's share is 323 Bcfe. The Company's share of production for
the
fourth quarter of 2006 averaged 52,000 Mcfe per day.
Unless
the context otherwise requires, the terms "PDC" or "Company" refer to Petroleum
Development Corporation, its subsidiaries and proportionately consolidated
drilling partnerships, collectively. The Company’s corporate headquarters are
located at 120 Genesis Boulevard, Bridgeport, West Virginia 26330 where the
telephone number is (304) 842-3597.
Business
Segments
The
Company’s operations are divided into four segments for management and reporting
purposes: (1) drilling and development, (2) natural gas marketing, (3) oil
and
gas sales and (4) well operations and pipeline income. See Note 17 to the
consolidated financial statements.
Drilling
and Development
The
Company drills wells not only for itself, but also for its investor partners.
When the Company drills wells for others it earns profit above the cost of
the
wells. Beginning with the last Company-sponsored partnership of 2005 (for which
revenue generating activities did not commence until early 2006), partnership
wells are drilled on a “cost-plus” basis, where the Company bills investors for
the actual cost of the wells plus an agreed upon mark-up above the costs. Prior
to that, most of the Company’s third-party drilling activities were conducted on
a footage-based basis, where the Company drills the wells for a fixed price
per
foot drilled with additional chargeable items per the drilling agreement.
Since
1984, the Company has sponsored limited partnerships formed to engage in
drilling operations. The Company typically purchases a 20% to 37% ownership
working interest in these drilling limited partnerships. In 2006, the Company,
through one private drilling partnership, raised approximately $90 million
in
investor subscriptions, making it one of the largest sponsors of oil and gas
partnership programs in the United States, as it has been for the last several
years. PDC’s working interest is 37% in the 2006 partnership. Through the
partnerships, the Company has been able to expand its drilling opportunities,
reduce its drilling risk through greater diversification, and share the costs
of
the infrastructure necessary to support such activities.
Natural
Gas Marketing
The
Company’s wholly-owned subsidiary, Riley Natural Gas ("RNG"), purchases,
aggregates and resells natural gas developed by the Company and other producers.
This allows the Company to diversify its operations beyond natural gas drilling
and production. RNG has established relationships with many of the natural
gas
producers in the Appalachian Basin and has significant expertise in the natural
gas end-user market. In addition, RNG has extensive experience in the use of
risk management strategies, which the Company utilizes to help manage the
financial impact of changes in the price of natural gas and oil on the Company
and its partnerships. RNG also manages the marketing of oil and gas for the
Company's wells outside the Appalachian Basin, but does not market gas or oil
for the non-affiliated producers in those areas.
Oil
and Gas Sales
Revenue
and expenses from the production and sale of oil and natural gas from the
Company’s interests in oil and gas wells is reported in this segment. The
Company has interests in approximately 3,100 wells ranging from a few percent
to
100%. During 2006, approximately 9% of the Company’s production was generated by
Appalachian Basin wells, 8% by Michigan Basin wells and 83% by Rocky Mountain
Region wells. As of the end of 2006, the Company's total proved reserves were
located as follows: Appalachian Basin (11%), Michigan (7%) and Rocky Mountain
Region (82%). The majority of the Company's undeveloped acreage is in the Rocky
Mountain Region and the Company's planned drilling for 2007 will be focused
in
that area. See Note 3 to the consolidated financial statements for disclosure
of
significant customers.
Well
Operations and Pipeline Income
The
Company operates approximately 95% of the wells in which it owns an interest.
When the Company owns less than 100% of the working interest in a well, it
charges the other owners a competitive fee for operating the well. These
revenues and the associated costs are reflected in the Well Operations
segment.
Areas
of Operations
The
Company's operations are divided into three regions: the Appalachian Basin,
Michigan, and the Rocky Mountain Region. The Company has conducted operations
in
the Appalachian Basin since its inception in 1969, in Michigan since 1997,
and
in the Rocky Mountain Region since 1999. The Company includes its North Dakota
operations in the Rocky Mountain Region.
In
all
three regions, the Company has historically targeted developmental natural
gas
reserves at depths of less than 10,000 feet. In some areas of the Rocky Mountain
Region, Michigan and the Appalachian Basin, the wells also produce oil in
conjunction with natural gas. Recently the Company has begun to drill to
progressively deeper targets in the Rocky Mountain Region. In particular, the
Company has drilled several wells with depths of more than 12,000 feet and
horizontal wells with a total drilled footage approaching 20,000 feet. The
Company’s management believes these deeper and horizontal wells, although more
expensive to drill, offer attractive economics and reserves. The probability
of
encountering problems when drilling wells at depths greater than 12,000 feet
or
horizontally is generally greater than when drilling a vertical well of lesser
depth. With increasing costs for and declining availability of proved developed
drilling locations, the Company’s management believes the additional risk
associated with exploratory drilling is justified by the potential to generate
additional proved locations at a significantly lower cost than would be required
to purchase proved undeveloped locations.
Business
Strategy
The
Company's primary objective is to increase shareholder value by expanding its
oil and natural gas reserves, production and revenues through a strategy that
includes the following key elements:
Drill
and Develop
Drilling
developmental natural gas wells has been the mainstay of the Company’s drilling
program for a number of years. The Company drilled 231 wells in 2006, compared
to 242 wells in 2005. In addition, the Company seeks to maximize the value
of
its existing wells through a program of well recompletions. The Company’s
management believes that it will be able to drill a substantial number of new
wells on its current undeveloped leased properties. As of December 31, 2006,
the
Company had leases or other development rights to
200
undeveloped acres in the Michigan Basin, 12,800 undeveloped acres in the
northern Appalachian Basin and 187,500 undeveloped acres in the Rocky Mountain
Region.
The
Company also plans to recomplete about 164 Wattenberg Field wells (Colorado)
during 2007.
To
support future development activities the Company has conducted exploratory
drilling in the past and will continue exploratory drilling plans in 2007.
The
goal of the exploration program is to develop several significant new areas
for
the Company to include in its future development drilling activity.
Acquire
The
Company's acquisition efforts are focused on producing properties that fit
well
within existing operations or in areas where the Company is establishing new
operations. Preferred properties have most of their value in producing wells,
behind pipe reserves or high quality proved undeveloped locations. Acquisitions
have historically offered economies in management and administration costs,
and
the Company’s management believes that with its growing operations staff it can
acquire and manage more producing wells without incurring substantial increases
in its administrative costs. See Notes 2, 15 and 16 to Consolidated Financial
Statements.
Diversify
and Focus
With
operations in the Rocky Mountains, Michigan and the Appalachian Basin, the
Company has proven its ability to grow through operations in geographically
diverse areas. While these areas provide geographic diversification, within
each
area, the Company has concentrated positions that lend themselves to effective
development and operation. The Company plans to conduct the majority of its
drilling activities in the Rocky Mountain Region during 2007, but will continue
to seek additional opportunities for expansion in areas where the Company's
experience and expertise can be applied successfully.
Manage
Risk
The
Company seeks opportunities to reduce the risks inherent in the oil and gas
industry in a variety of ways. For a number of years, an integral part of the
Company's strategy has been to concentrate on development drilling and
geographical diversification to reduce risk levels associated with natural
gas
and oil drilling, production and markets. Development drilling is less risky
than exploratory drilling and is likely to generate cash returns more quickly.
Development drilling will remain the foundation of the Company’s drilling
activities in 2007. However, the Company’s management believes the increasing
cost of high quality development locations has made exploratory drilling
relatively more attractive for future efforts. Exploratory wells have the
potential of identifying new development opportunities at a significantly lower
cost than the current cost of acquiring proven locations. While successful
exploratory efforts could add to the Company’s future drilling opportunities at
favorable costs, under the successful efforts method of accounting, exploratory
dry holes are expensed at the time it is recognized that they are unproductive.
This could result in greater short-term expenses and a reduction in the
near-term profitability of the Company.
To
help
offset the relatively high business risk inherent in the oil and gas industry
the Company maintains a conservative financial structure. The Company’s
management believes that successful natural gas marketing is essential to risk
management and profitable operations in a deregulated gas market. To further
this goal, the Company utilizes RNG to manage the marketing of the Company’s oil
and natural gas and its use of oil and gas commodity derivatives as risk
management tools. This allows the Company to maintain better control over third
party risk in sales and derivative activities. The Company uses natural gas
and
oil derivatives to reduce the effects of volatile energy prices.
Available
Information Posted on the Company's Website
The
Company files Annual Reports on Form 10-K, Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K, registration statements and
other items with the Securities and Exchange Commission ("SEC"). PDC provides
free access to all of these SEC filings, as soon as reasonably practicable
after
filing, on its internet site located at www.petd.com. The Company will also
make
available to any shareholder, without charge, a copy of its Annual Report on
Form 10-K as filed with the SEC. For a copy of the Company’s Annual Report,
or any other filings, please 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 the Company's SEC filings, other information, including the
Company's press releases, current drilling program sales, 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 the Company’s internet site,
www.petd.com.
The
public may read and copy any materials the Company files with the SEC at the
SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC
20549. The public may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an
internet site (www.sec.gov) that contains reports, proxies, information
statements and other information regarding issuers, like PDC, that file
electronically with the SEC.
Natural
Gas Industry
Overview
Natural
gas is one of the largest energy sources in the United States. The estimated
21.9 Tcf of natural gas consumed in 2006 represented approximately 22% of the
total energy used in the United States. Natural gas is consumed in the United
States as follows: 35% by industrial end-users as feedstock for products such
as
plastic and fertilizer or as the energy source for producing products such
as
glass; 21% and 14% by residential and commercial end-users, respectively, for
uses including heating, cooling and cooking; 28% by utilities for the generation
of electricity; and 2% for other users. (Source U.S. Energy Information
Administration)
The
Company’s management believes that the market for natural gas will continue to
grow in the future. Natural gas burns cleaner than most fossil fuels and
produces less greenhouse gas per unit of energy released. Relative to other
energy sources, natural gas usage and losses during transportation from source
to destination are slight, averaging only about 2% of the natural gas energy.
The delivery of natural gas is among the safest means of distributing energy
to
customers, as the natural gas transmission system is fixed and is located
underground.
The
deregulation of the natural gas industry and a favorable regulatory environment
have resulted in end-users' ability to purchase natural gas on a competitive
basis from a greater variety of sources. Increasing international demand for
petroleum combined with supply constraints kept oil prices near record high
levels throughout 2006. Continuing increases in world energy demand appear
likely in 2007 and beyond. This makes natural gas more competitive in domestic
markets as a replacement for oil and increases the value of domestic oil and
natural gas reserves.
The
Company’s management believes that the foregoing factors, together with the
increased availability of natural gas as a form of energy for residential,
commercial and industrial uses, should increase the demand for natural gas
as
well as create new markets for natural gas, even at prices that are high by
historical standards.
Because
local supplies of natural gas are inadequate to meet demand in some sections
of
the United States, areas including the West Coast and the Northeast import
natural gas from producing areas via interstate natural gas pipelines. The
cost
of transporting natural gas from the major producing areas to markets creates
a
price advantage for production located closer to the consuming regions. Natural
gas producers in the Appalachian Basin and Michigan benefit from proximity
to
the Northeastern and Midwestern United States markets.
In
contrast, much of the production in the Rocky Mountains is transported
significant distances to end user markets. As a result, the price received
for
gas in the Rocky Mountains is generally less than the price received in areas
closer to the primary consuming areas. The Rocky Mountain Region is believed
to
hold substantial undeveloped natural gas resources. Recent and planned additions
to pipeline capacity in the region have made the area more attractive for
development. Although in the near term, gas from the region will generally
sell
for less than gas in the Appalachian and Michigan Basins, development costs
per
Mcfe may be less.
Operations
Exploration
and Development Activities
The
Company's 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 the Company’s current properties through
infill drilling, recompletions, and other production enhancements.
Prospect
Generation
The
Company's staff of professional geologists is responsible for identifying areas
with potential for economic production of natural gas and oil. These geologists
have decades of cumulative experience evaluating prospects and drilling natural
gas and oil wells. 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, the
Company has collected and continues 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, the Company's 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, the Company pays a lease
bonus and annual rental payments, converting, upon initiation of production,
to
a royalty. In addition, overriding royalty payments may be made to third parties
in conjunction with the acquisition of drilling rights initially leased by
others. As of December 31, 2006, the Company had leasehold rights to
approximately 200,500 acres available for development. See "Properties--Oil
and
Natural Gas Leases."
Drilling
Activities
When
prospects have been identified, leased and all regulatory approvals obtained,
the Company develops these properties by drilling wells. In 2006, the Company
drilled a total of 222 development wells, which 216 wells were designated
successful. As of December 31, 2006, 82 of the 216 successful wells were
awaiting gas pipeline connection. As of April 30, 2007, 67 of the wells awaiting
pipeline connection were connected and turned in line. Typically, the Company
will act as driller-operator for these prospects, frequently selling interests
in the wells to Company-sponsored partnerships and other entities that are
interested in exploration or development of the prospects. The Company retains
a
working interest in each well it drills.
The
Company also drilled nine exploratory wells in 2006, eight (including one
pending determination as of December 31, 2006) were determined to be productive
and one was determined to be dry. Costs related to the dry hole of $1.3 million
were expensed in 2006. The Company plans to conduct additional exploratory
drilling activities in 2007. See "Financing of Company Drilling and Development
Activities" and “Drilling and Development Activities Conducted for Company
Sponsored Partnerships” for additional discussion regarding the Company's
drilling activities.
Much
of
the work associated with drilling, completing and connecting wells, including
drilling, fracturing, logging and pipeline construction is performed under
the
Company’s direction by subcontractors specializing in those operations, as is
common in the industry. When judged advantageous, material and services used
by
the Company in the development process are acquired through competitive bidding
by approved vendors. The Company also directly negotiates rates and costs for
services and supplies when conditions indicate that such an approach is
warranted.
The
following tables summarize the Company's 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.
|
Development
Wells Drilled
|
|||||||||||||||||||
|
Total
|
Productive
|
Dry
|
|||||||||||||||||
|
Drilled
|
Net
|
Drilled
|
Net
|
Drilled
|
Net
|
||||||||||||||
|
2002
|
70
|
13.7
|
70
|
13.7
|
-
|
-
|
|||||||||||||
|
2003
|
110
|
28.5
|
110
|
28.5
|
-
|
-
|
|||||||||||||
|
2004
|
157
|
43.0
|
153
|
42.4
|
4
|
0.6
|
|||||||||||||
|
2005
|
234
|
103.4
|
232
|
102.0
|
2
|
1.4
|
|||||||||||||
|
2006
|
222
|
134.4
|
216
|
129.8
|
6
|
4.6
|
|||||||||||||
|
Total
|
793
|
323.0
|
781
|
316.4
|
12
|
6.6
|
|||||||||||||
|
Exploratory
Wells Drilled
|
|||||||||||||||||||
|
Total
|
Productive
|
Dry
|
|||||||||||||||||
|
Drilled
|
Net
|
Drilled
|
Net
|
Drilled
|
Net
|
||||||||||||||
|
2002
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||
|
2003
|
1
|
1.0
|
-
|
-
|
1
|
1.0
|
|||||||||||||
|
2004
|
1
|
1.0
|
-
|
-
|
1
|
1.0
|
|||||||||||||
|
2005
|
8
|
7.3
|
3
|
2.3
|
5
|
5.0
|
|||||||||||||
|
2006
|
9
|
3.3
|
8
|
2.8
|
1
|
0.5
|
|||||||||||||
|
Total
|
19
|
12.6
|
11
|
5.1
|
8
|
7.5
|
|||||||||||||
Financing
of Company Drilling and Development Activities
The
Company conducts development drilling activities for its own account and acts
as
operator for other owners. When conducting activities for its own account,
the
Company uses cash flow from operations and capital provided from its long term
credit facility to fund its share of operations.
Drilling
and Development Activities Conducted for Company Sponsored
Partnerships
In
addition to wells and interests in wells that it drills for itself, the Company
also acts 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. Currently, the Company’s drilling
partners consist primarily of public and private partnerships sponsored by
the
Company. The Company contributes a cash investment to purchase an interest
in
the drilling and development activities and serves as the managing general
partner for each partnership; accordingly, the Company is subject to substantial
cash commitments at the closing of each drilling partnership.
In
1984,
the Company began sponsoring drilling partnerships. The Company-sponsored
partnerships had $90 million in subscriptions in 2006, $116 million in
subscriptions in 2005, and $100 million in subscriptions in 2004. During 2006,
the Company sponsored one drilling partnership to which it contributed $38.9
million and received a 37% working interest in the partnership. While funds
were
received by the Company pursuant to drilling contracts in the years indicated,
the Company recognizes revenues from drilling operations on the percentage
of
completion method as the wells are drilled, rather than when funds are received.
Substantially all of the Company's drilling and development funds are now
received from partnerships in which the Company serves as managing general
partner. However, because wells produce for a number of years, the Company
continues to serve as operator for a number of unaffiliated parties. The Company
plans to offer $110 million in subscriptions through a private placement in
2007.
The
Company enters into a development agreement with an investor partner, pursuant
to which the Company agrees to sell some or all of its 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.
The
Company's drilling contracts with its investor partners have historically taken
many different forms. Beginning with the last Company-sponsored partnership
of
2005 (for which revenue generating activities did not commence until early
2006), partnership wells are drilled on a “cost-plus” basis, whereby the Company
bills investors for the actual cost of the wells plus an agreed upon mark-up
above the costs. In the past the drilling contracts could be classified as
on a
footage-based rate, whereby the Company received drilling and completion
payments based on the depth of the well. The Company may also purchase an
additional working interest in the partnership properties. In its financial
reporting, the Company reports only its proportionate share of oil and gas
reserves, production, oil and gas sales and costs associated with wells in
which
other investors participate. The level of the Company's drilling and development
activity is dependent upon the amount of subscriptions in its public drilling
partnerships and investments from other partnerships or other joint venture
partners. Accepting investments from third party investors and Company sponsored
partnerships enables the Company to diversify its holdings, thereby reducing
the
risk of the Company’s investments. The Company’s management believes that
investments in drilling activities, whether through Company-sponsored
partnerships or other sources, are influenced in part by the favorable treatment
that such limited partner investments receive under the federal income tax
laws.
No assurance can be given that the Company will continue to have access to
funds
generated through these financing vehicles or that the favorable tax treatment
will continue.
Purchases
of Producing Properties
In
addition to drilling new wells, the Company continues to pursue opportunities
to
purchase existing wells from other owners, as well as greater ownership
interests in the wells it operates. Generally, outside interests purchased
include a majority interest in the wells and the right to operate the wells.
During 2006, the Company successfully acquired the stock of Unioil, Inc., a
small independent producer with properties primarily in the Wattenberg Field
in
Colorado, for a total of $18.6 million. In addition, in January 2007, the
Company 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, the Company purchased the outside partnership interests in 44 partnerships
which had been 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, the Company acquired 28
producing wells and associated undeveloped acreage in Colorado for $11.8
million.
Production
The
following table shows the Company's net production in thousands of barrels
("MBbl") of crude oil and in million cubic feet ("MMcf") of natural gas and
the
costs and weighted average selling prices of oil in barrels (Bbl) and gas in
thousands of cubic feet (Mcf).
|
Year
Ended December 31,
|
||||||||||||||||
|
2006
|
2005
|
2004
|
2003
|
2002
|
||||||||||||
|
Production
(1):
|
||||||||||||||||
|
Oil
(MBbl)
|
631
|
439
|
381
|
289
|
227
|
|||||||||||
|
Natural
Gas (MMcf)
|
13,161
|
11,031
|
10,372
|
8,712
|
6,462
|
|||||||||||
|
Equivalent
(MMcfe) (2)
|
16,949
|
13,665
|
12,659
|
10,449
|
7,824
|
|||||||||||
|
Average
sales price:
|
||||||||||||||||
|
Oil
(per Bbl) (3)
|
$
|
59.33
|
$
|
50.56
|
$
|
38.00
|
$
|
29.43
|
$
|
24.41
|
||||||
|
Natural
gas (per Mcf) (3)
|
$
|
5.91
|
$
|
7.29
|
$
|
5.30
|
$
|
4.58
|
$
|
2.65
|
||||||
|
Equivalent
average sales price (per Mcfe)
|
$
|
6.80
|
$
|
7.51
|
$
|
5.49
|
$
|
4.63
|
$
|
2.90
|
||||||
|
Average
production cost (lifting cost)
|
||||||||||||||||
|
Per
equivalent (Mcfe) (4)
|
$
|
1.23
|
$
|
1.19
|
$
|
1.12
|
$
|
0.93
|
$
|
0.76
|
||||||
|
(1)
|
Production
as shown in the table is net to the Company and is determined by
multiplying the gross production volume of properties in which the
Company
has an interest by the percentage of the leasehold or other property
interest owned by the Company.
|
|
(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)
|
The
Company utilizes commodity based derivative instruments to manage
a
portion of its exposure to price volatility of its natural gas and
oil
sales. The above table does not include the results of derivative
transactions.
|
|
(4)
|
Production
costs represent oil and gas operating expenses which include severance
and
ad valorem taxes as reflected in the financial statements of the
Company.
See “Oil and Gas Production and Well Operations Costs” in Management's
Discussion and Analysis.
|
Natural
Gas Sales
Natural
gas produced by the Company’s well interests is generally sold under contracts
with monthly pricing provisions. Virtually all of the Company's contracts
include provisions wherein prices change monthly with changes in the market
with
certain adjustments based on, among other factors, 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, the
Company's revenues from the sale of natural gas will suffer if market prices
decline and benefit if they increase. The Company’s management believes that the
pricing provisions of its natural gas contracts are customary in the
industry.
The
Company sells its natural gas to industrial end-users, utilities, other gas
marketers, and other wholesale gas purchasers. During 2006, natural gas produced
by the Company was sold at prices ranging from $2.26 to $15.70 per Mcf,
depending upon well location, the date of the sales contract and other factors.
The weighted net average price of natural gas sold by the Company during 2006
was
$5.91
per
Mcf.
In
general, the Company, together with its marketing subsidiary, RNG, has been
and
expects to continue to be able to produce and sell natural gas from its wells
without significant curtailment by providing natural gas to purchasers at
competitive prices. Open access transportation through the country's interstate
pipeline system makes a broad range of markets accessible to the Company.
Whenever feasible, the Company obtains access to multiple pipelines and markets
from each of its gathering systems seeking the best available market for its
natural gas at any point in time.
Oil
Sales
The
majority of the Company's wells in the Wattenberg Field in Colorado and the
Company's North Dakota wells produce oil in addition to natural gas. As of
December 31, 2006, oil represented about 13% of the Company's total equivalent
reserves and accounted for approximately 33% of the Company's oil and gas sales
for the year ended December 31, 2006.
The
Company is currently able to sell all the oil that it can produce under existing
sales contracts with petroleum refiners and marketers. The Company does not
refine any of its oil production. The Company's crude oil production is sold
to
purchasers at or near the Company's wells under short-term purchase contracts.
During 2006, oil produced by the Company sold at prices ranging from
$53.75 to
$71.77
per barrel, depending upon the location and quality of oil. In 2006, the
weighted net average price per barrel of oil sold by the Company was
$59.33.
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 the Company, to procure and
implement Spill Prevention, Control and Counter-measures ("SPCC") plans relating
to the possible discharge of oil into surface waters. The Oil Pollution Act
of
1990 ("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. Operations of the Company are also subject to the
Federal Clean Water Act 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.
Natural
Gas Marketing
The
Company's natural gas marketing activities involve the purchase of natural
gas
from other producers and the sale of that natural gas along with natural gas
produced by the Company. The Company’s management believes 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, natural gas imports, 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,
a
wholly owned subsidiary, is a natural gas marketing company that specializes
in
the purchase, aggregation and sale of natural gas production in the Company's
Eastern operating areas. RNG markets natural gas produced by the Company and
also purchases natural gas from other producers and resells to utilities, end
users or other marketers. The employees of RNG have extensive knowledge of
natural gas markets in the Company's areas of operations. Such knowledge assists
the Company in maximizing its prices as it markets natural gas from
Company-operated wells. The gas is marketed to natural gas utilities, industrial
and commercial customers as well as other marketers, either directly through
the
Company's gathering system, or utilizing transportation services provided by
regulated interstate pipeline companies.
Commodity
Risk Management Activities
The
Company utilizes commodity based derivative instruments to manage a portion
of
the exposure to price volatility stemming from its oil and natural gas sales
and
marketing activities. These instruments consist of over the counter swaps and
options and NYMEX-traded natural gas futures and option contracts for
Appalachian and Michigan production and Colorado Interstate Gas Index ("CIG")
and Panhandle Eastern Pipeline ("PEPL")-based contracts for Colorado natural
gas
production and NYMEX traded oil futures and option contracts for Colorado oil
production. The Company may utilize derivatives based on other indices or
markets where appropriate. The contracts economically provide price protection
for committed and anticipated natural gas purchases and sales and anticipated
oil sales, generally forecasted to occur within the next two to three year
period. Company policy prohibits the use of natural gas or oil futures or
options for speculative purposes and permits 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 impact of natural gas price changes. These financial derivatives are used
by
RNG to coordinate fixed purchases and sales, and by the Company 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 FAS 133 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.
The
Company is subject to price fluctuations for natural gas sold in the spot market
and under market index contracts. The Company continues to evaluate the
potential for reducing these risks by entering into derivative transactions.
In
addition, the Company 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. The Company economically manages the price risk on only a portion
of its anticipated production, so some of the production is subject to the
full
fluctuation of market pricing.
Well
Operations
At
December 31, 2006, the Company had an interest in approximately 1,365 wells
in
the Appalachian Basin, 206 wells in the Michigan Basin and 1,530 wells in the
Rocky Mountain Region. The Company's ownership interest in these wells ranges
from greater than 0% to 100% and, on average, the Company has an approximate
51.4% ownership interest in the wells it operates.
The
Company is paid a monthly operating fee for each well it operates for the
portion of these wells owned by others, including the limited partnerships
sponsored by the Company. 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. The Company may also receive additional
compensation, at competitive rates, for special non-recurring activities, such
as reworks and recompletions.
Transportation
Natural
gas wells are connected by pipelines to natural gas markets. Over the years,
the
Company has developed, owns and operates gathering systems in some of its areas
of operations. The Company also continues 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 its existing systems.
Governmental
Regulation
While
the
price of natural gas is set by the market, other aspects of the Company's
business and the natural gas industry in general are heavily regulated. The
availability of a ready market for natural gas production depends on several
factors beyond the Company's control. These factors include regulation of
natural gas production, federal and state regulations governing environmental
quality and pollution control, the amount of 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, control
and
reduce the risk to the public and workers from the drilling, completion,
production and transportation of oil and natural gas, prevent waste of natural
gas, protect rights to produce natural gas between owners in a common reservoir
and 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 the Company
has increased its positions in these types of leases. Generally, government
leases are subject to additional regulations and controls not commonly seen
on
private leases. The Company takes the steps necessary to comply with applicable
regulations both on its own behalf and as part of the services it provides
to
its investor partnerships. The Company’s management believes that it is 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 discussion of the regulation of the United States natural gas industry
is not intended to constitute a complete discussion of the various statutes,
rules, regulations and environmental orders to which the Company's operations
may be subject.
Regulation
of Oil and Natural Gas Exploration and Production
The
Company's 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, the Company 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,
and the regulation includes maintaining bonding requirements in order to drill
or operate wells and regulating the location of wells, the method of drilling
and casing wells, the surface use and restoration of properties on which wells
are drilled, the plugging and abandoning of wells and the disposal of fluids
used in connection with operations. The Company's 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 and 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 the Company can produce from its wells and may limit the
number of wells or the locations at which the Company can drill. Such
laws
and regulations have increased the costs of planning, designing, drilling,
installing, operating and abandoning the Company’s oil and gas wells and other
facilities. In addition, these laws and regulations, and any others that are
passed by the jurisdictions where the Company has production, could limit the
total number of wells drilled or the allowable production from successful wells,
which could limit its reserves.
Inasmuch
as such laws and regulations are frequently expanded, amended and reinterpreted,
the Company is unable to predict the future cost or impact 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 (the "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
("FERC")'s 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 gas prices. The passage of one of those bills or similar legislation
could have the impact of reducing the price received by the Company for its
production, or substantially increasing the tax burden associated with its
production operations.
The
Company moves gas through pipelines owned by other companies, and sells gas
to
other companies that also utilize common carrier pipeline facilities. Gas
pipeline interstate transmission and storage activities are subject to
regulation by the FERC under the Natural Gas Act of 1938 ("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 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 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 Order 2004
“Standards of Conduct for Transmission Providers” governs how interstate
pipelines communicate and do business with their energy affiliates. One of
the
cornerstones of Order 2004 is that interstate pipelines will not operate their
pipeline systems to preferentially benefit their energy 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;
|
|
•
|
volume
throughput assumptions.
|
The
Company's sales of natural gas are affected by the availability, terms and
cost
of transportation. 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 the greater transportation access available 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. The Company cannot
determine to what extent future operations and earnings of the Company will
be
affected by new legislation, new regulations, or changes in existing regulation,
at federal, state or local levels.
Environmental
Regulations
The
Company's 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
stricter 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, the business and
prospects of the Company could be adversely affected.
The
Company generates wastes that may be subject to the Federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency ("EPA") and various state agencies have limited
the approved methods of disposal for certain hazardous and non-hazardous wastes.
Furthermore, certain wastes generated by the Company's 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.
The
Company currently owns or leases numerous properties that for many years have
been used for the exploration and production of oil and natural gas. Although
the Company’s management believes that it has utilized good operating and waste
disposal practices, prior owners and operators of these properties may not
have
utilized similar practices, and hydrocarbons or other wastes may have been
disposed of or released on or under the properties owned or leased by the
Company 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 ("CERCLA"),
RCRA and analogous state laws as well as state laws governing the management
of
oil and natural gas wastes. Under such laws, the Company 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
joint and several 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.
The
Company's operations may be subject to the Clean Air Act ("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 the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company 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
Company's expenses relating to preserving the environment during 2006 were
not
significant in relation to operating costs and the Company expects no material
change in 2007. Environmental regulations have had no materially adverse effect
on the Company's 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 the Company's
business, financial condition or results of operations.
Operating
Hazards and Insurance
The
Company's 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 which could result in substantial losses to the Company 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. The Company's 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, and surrounding
properties 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 its facilities could adversely affect the
Company's ability to conduct its operations. In accordance with customary
industry practice, the Company maintains 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
the Company's operations and financial condition. The Company cannot predict
whether insurance will continue to be available at premium levels that justify
its purchase or whether insurance will be available at all.
Competition
The
Company’s management believes that its exploration, drilling and production
capabilities and the experience of its management and professional staff
generally enable it to compete effectively. The Company encounters competition
from numerous other oil and natural gas companies, drilling and income programs
and partnerships in all areas of its operations, including drilling and
marketing oil and natural gas and obtaining desirable oil and natural gas leases
and producing properties. Many of these competitors possess larger staffs and
greater financial resources than the Company, which may enable them to identify
and acquire desirable producing properties and drilling prospects more
economically. The Company's ability to explore for oil and natural gas prospects
and to acquire additional properties in the future depends upon its ability
to
conduct its operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. The Company
competes with a number of other companies that offer interests in drilling
partnerships with a wide range of investment objectives and program structures.
Competition for investment capital for both public and private drilling programs
is intense. The Company also faces 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 2006, the 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.
The Company’s management believes that it can compete effectively in the oil and
natural gas industry on each of the foregoing factors. Nevertheless, the
Company's business, financial condition or results of operations could be
materially adversely affected by competition.
Employees
As
of
December 31, 2006, the Company had 189 employees, including 104 in production
and seven in natural gas marketing, 32 in exploration and development, 31 in
finance, accounting and data processing, and 15 in administration. The Company's
engineers, supervisors and well tenders are responsible for the day-to-day
operation of wells and pipeline systems. In addition, the Company retains
subcontractors to perform drilling, fracturing, logging, and pipeline
construction functions at drilling sites, with the Company's employees
supervising the activities of the subcontractors. In 2006, the total number
of
Company employees increased by 39.
The
Company's employees are not covered by a collective bargaining agreement. The
Company considers relations with its employees to be excellent.
ITEM
1A. RISK FACTORS
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 the Company’s business, operating results and financial condition, as
well as adversely affect the value of an investment in its common stock or
other
securities.
Oil
and natural gas prices fluctuate unpredictably and a decline in oil and natural
gas prices can significantly affect the Company’s financial results and impede
its growth.
The
Company’s revenue, profitability and cash flow depend in large part upon the
prices and demand for oil and natural gas. The markets for these commodities
are
very volatile and even relatively modest drops in prices can significantly
affect the Company’s financial results and impede its growth. Changes in oil and
natural gas prices have a significant impact on the value of the Company’s
reserves and on its cash flow. Prices for oil and natural gas may fluctuate
widely in response to relatively minor changes in the supply of and demand
for
oil and natural gas, market uncertainty and a variety of additional factors
that
are beyond the Company’s control, including national and international economic
and political factors and federal and state legislation.
The
prices of oil and natural gas are quite volatile, often fluctuating greatly.
Lower oil and natural gas prices may not only reduce the Company’s revenues, but
also may reduce the amount of oil and natural gas that the Company can produce
economically. This may result in the Company having to make substantial downward
adjustments to its estimated proved reserves. If this occurs or if the Company’s
estimates of development costs increase, production data factors change or
the
Company’s exploration results deteriorate, accounting rules may require the
Company to write-down operating assets to fair value, as a non-cash charge
to
earnings. The
Company assesses impairment of capitalized costs of proved oil and gas
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 to be sold.
The
Company may incur impairment charges in the future, which could have a material
adverse effect on its results of operations.
The
Company’s estimated oil and gas 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 the Company’s reserves.
No
one
can measure underground accumulations of oil and natural gas in an exact way.
Oil and natural gas reserve engineering requires subjective estimates of
underground accumulations of oil and natural gas and assumptions concerning
future oil and natural gas 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. The
Company’s estimates of oil and gas reserves are prepared by independent
petroleum engineers, using pricing, production, cost, tax and other information
provided by the Company. The reserve estimates are based on certain assumptions
regarding future oil and natural gas prices, production levels, and operating
and development costs that may prove incorrect. Any significant variance from
these assumptions to actual figures could greatly affect the estimates of
reserves, the economically recoverable quantities of oil and natural gas
attributable to any particular group of properties, future depreciation,
depletion and amortization rates and amounts, the classifications of reserves
based on risk of recovery, and estimates of the future net cash flows. Some
of
the Company’s reserve estimates must be made with limited production history,
which renders these reserve estimates less reliable than estimates based on
a
lengthy 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 oil and gas recovered being different from earlier reserve
estimates.
The
present value of estimated future net cash flows from proved reserves is not
necessarily the same as the current market value of the estimated oil and
natural gas reserves (the Securities and Exchange Commission 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)
and future estimated costs. However, actual future net cash flows from the
Company’s oil and natural gas properties also will be affected by factors such
as actual prices it receives for oil and natural gas and hedging instruments,
the amount and timing of actual production, amount and timing of future
development costs, supply of and demand for oil and natural gas, and changes
in
governmental regulations or taxation.
The
timing of both the Company’s production and incurrence of expenses in connection
with the development and production of oil and natural gas 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 Securities and Exchange Commission) the Company uses 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 its oil and gas properties or the oil and natural gas industry in general.
Unless
oil and natural gas reserves are replaced as they are produced, the Company’s
reserves and production will decline, which would adversely affect the Company’s
future business, financial condition and results of
operations.
Producing
oil and natural gas 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 the Company has estimated and can change
due
to other circumstances. Thus, the Company’s future oil and natural gas reserves
and production and, therefore, its cash flow and income are highly dependent
on
efficiently developing and exploiting the Company’s current reserves and
economically finding or acquiring additional recoverable reserves. The Company
may not be able to develop, discover or acquire additional reserves to replace
its current and future production at acceptable costs. As a result, the
Company's future operations, financial condition and results of operations
would
be adversely affected.
Prospects
drilled by the Company may not yield natural gas or oil in commercially viable
quantities.
A
prospect is a property on which the Company's geologists have identified what
they believe, based on available information, to be indications of natural
gas
or oil bearing rocks. However, the use of available data and other technologies
and the study of producing fields in the same area will not enable the
geologists to 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. If a well is determined to be dry or uneconomic, which can
occur even though it contains some oil or 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 oil and gas to be profitable. If the Company drills a dry
hole or non-profitable well on current and future prospects, the profitability
of its operations will decline and the value of the Company 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.
The
Company may not be able to identify enough attractive prospects on a timely
basis to meet its own development needs and those of the partnerships it forms
for investors, which could limit the Company’s development opportunities and/or
force it to reduce partnership activity.
The
Company’s geologists have identified a number of potential drilling locations on
existing acreage. These drilling locations must be replaced as they are drilled
for the Company to continue to grow its reserves and production, and for it
to
be able to continue its partnership drilling activities. The Company’s ability
to identify and acquire new drilling locations depends on a number of
uncertainties, including the availability of capital, regulatory approvals,
oil
and natural gas prices, competition, costs, availability of drilling rigs,
drilling results and the ability of the Company’s geologists to successfully
identify potentially successful new areas to develop. Because of these
uncertainties, the Company’s profitability and growth opportunities may be
limited by the timely availability of new drilling locations, and it could
be
forced to terminate or curtail its partnership activities because of a lack
of
suitable prospects for the partnerships. As
a
result, the Company's operations and profitability could be adversely
affected.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could adversely affect the Company’s business, financial
condition and results of operations.
Drilling
activities are subject to many risks, including the risk that the Company will
not discover commercially productive reservoirs. Drilling for oil and natural
gas can be unprofitable, not only from dry holes, but from productive wells
that
do not produce sufficient revenues to return a profit. In addition, drilling
and
producing operations may be curtailed, delayed or canceled as a result of other
factors, including unusual or unexpected geological formations, pressures,
fires, blowouts, loss of drilling fluid circulation, title problems, facility
or
equipment malfunctions, unexpected operational events, shortages or delivery
delays of equipment and services, compliance with environmental and other
governmental requirements, and adverse weather conditions.
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. The Company maintains insurance against various losses and
liabilities arising from operations; however, insurance against all operational
risks is not available. Additionally, the Company 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
impact on the Company’s business activities, financial condition and results of
operations.
Increased
drilling activity, particularly in the Rocky Mountain Region, may create a
shortage of drilling rigs, service providers, or materials, forcing the Company
to curtail its drilling operations for itself and its partnerships thereby
reducing revenue and profits from new oil and gas wells and from the Company’s
drilling and completion activities.
With
high
levels of oil and gas prices, many oil and gas companies have increased their
levels of drilling and completing new wells and reworking 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. In particular, 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 the Company’s inability to
complete all of the drilling it has planned. This could result in less drilling
by the Company and the temporary or permanent loss of part or all of its
partnership drilling activity and less profitability for the Company.
The
Company’s drilling and development segment receives virtually all of its revenue
from the partnerships it sponsors, and a reduction or loss of that business
could reduce or eliminate the revenue and profits associated with those
activities.
The
Company’s drilling margins associated with its limited partnership programs are
dependent upon the capital raised by the Company as a sponsor of limited
partnerships. The Company sells oil and natural gas partnerships through a
network of non-affiliated NASD broker dealers. The largest of those broker
dealers sold about 11% of the partnership units in 2006. Investors in the
partnerships benefit from the tax deductions generated by the intangible
drilling costs and the cash flow generated by the partnerships. If the tax
laws
were changed to reduce or eliminate the tax advantages, if the cash flow from
the partnerships were to decline due to poor performing wells or lower energy
prices, or if the brokers decide to stop offering the Company’s partnerships for
some reason, the sales of the partnership units would decline, reducing or
eliminating the revenue and profits associated with the drilling and development
business segment. As a result, the Company's operations and profitability would
be adversely affected.
Under
the Successful Efforts accounting method used by the Company unsuccessful
exploratory wells must be expensed in the period when they are determined to
be
non-productive which results in a reduction of the Company's net income and
profitability and could have a negative impact on the Company’s stock
price.
The
Company conducted exploratory drilling in 2006 and plans to continue exploratory
drilling in 2007 in order to identify additional opportunities for future
development. Under the "successful efforts" method of accounting used by the
Company, 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, the Company
anticipates that some or all of its exploratory wells may not be productive.
The
costs of such unsuccessful exploratory wells could result in a significant
reduction in the Company’s profitability in periods when the costs are required
to be expensed.
The
Company may incur substantial impairment write-down, if the price of oil and
natural gas declines or due to revisions in its estimates of its
reserves.
If
oil
and natural gas prices decline, if development costs exceed previous estimates,
or if management's estimate of the recoverable reserves on a property is revised
downward, the Company may be required to record additional non-cash impairment
write-downs in the future, which would result in a negative impact to its
financial position. The Company reviews its proved oil and gas properties for
impairment on a quarterly basis. To determine if a depletable unit is impaired,
the Company compares the carrying value of the depletable unit to the
undiscounted future net cash flows by applying management's estimates of future
oil and gas prices to the estimated future production of oil and gas reserves
over the economic life of the property. Future net cash flows are based upon
the
Company’s independent reserve engineers' estimates of proved reserves. In
addition, other factors such as probable and possible reserves are taken into
consideration when justified by economic conditions. For each property
determined to be impaired, the Company recognizes an impairment loss equal
to
the difference between the estimated fair value and the carrying value of the
property on a depletable unit basis. Fair value is estimated to be the present
value of the aforementioned expected future net cash flows. Any impairment
charge incurred is recorded as a reduction to the asset value. This calculation
is subject to a large degree of judgment, including the determination of the
future depletable units, future cash flows and fair value. In 2006, the Company
recorded an impairment charge of $1.5 million related to its Nesson Field in
North Dakota. There were no impairments during 2005 or 2004.
Rising
finding and development costs may impair the Company’s profitability.
In
order
to continue to grow and maintain its profitability, the Company must annually
add new reserves exceeding its 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, production, reserves and profitability will decline
over
time. Given the relative maturity of most gas 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 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 on a
per
unit basis, particularly in the Rocky Mountain Region, and the Company believes
these values may continue to increase in 2007. This increase in finding and
development costs is resulting in higher depreciation, depletion and
amortization rates. If the upward trend in finding and development costs
continues, the Company will be exposed to an increased likelihood of a
write-down in carrying value of its natural gas and oil properties in response
to falling prices and reduced profitability of operations.
The
Company’s development and exploration operations require substantial capital and
it may be unable to obtain needed capital or financing on satisfactory terms,
which could lead to a loss of properties and a decline in natural gas and oil
reserves and production.
The
oil
and natural gas industry is capital intensive. The Company makes and expects
to
continue to make substantial capital expenditures in its business and operations
for the exploration for and development, production and acquisition of oil
and
natural gas reserves. The Company finances capital expenditures primarily with
cash generated by operations and proceeds from bank borrowings. Cash flows
from
operations and access to capital are subject to a number of variables, including
the Company’s proved reserves, the level of oil and natural gas the Company is
able to produce from existing wells, the prices at which oil and natural gas
are
sold, and the Company’s ability to acquire, locate and produce new
reserves.
If
the
Company’s revenues or the borrowing base under its revolving credit facility
decrease as a result of lower oil and natural gas prices, or it incurs operating
difficulties, declines in reserves or for any other reason, it may have limited
ability to obtain the capital necessary to sustain its operations at planned
levels.
If
additional capital is needed, the Company may not be able to obtain debt or
equity financing on favorable terms, or at all. If cash generated by operations
or sale of limited partnerships or available under the revolving credit facility
is not sufficient to meet the capital requirements, failure to obtain additional
financing could result in a curtailment of the exploration and development
of
the Company’s prospects, which in turn could lead to a possible loss of
properties and a decline in its natural gas and oil reserves and a decline
in
its profitability.
The
Company’s credit facility and other debt financing have substantial restrictions
and financial covenants and the Company may have difficulty obtaining additional
credit, which could adversely affect its operations.
The
Company depends on its revolving credit facility for future capital needs.
The
terms of the borrowing agreement require the Company to comply with certain
financial covenants and ratios. The Company’s 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
its
control. The Company’s 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 its
existing indebtedness to be immediately due and payable.
The
revolving credit facility limits the amounts the Company can borrow to a
borrowing base amount, determined by the lenders in their sole discretion,
based
upon projected revenues from the oil and natural gas properties securing its
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 the
Company must pledge other oil and natural gas properties as additional
collateral. The Company does not currently have any substantial unpledged
properties, and it may not have the financial resources in the future to make
any mandatory principal prepayments required under the revolving credit
facility. The Company’s inability to borrow additional funds under its credit
facility could adversely affect its operations.
A
substantial part of the Company’s oil and gas production is located in the Rocky
Mountains, making it vulnerable to risks associated with operating in one major
geographic area.
The
Company’s operations are becoming increasingly focused on the Rocky Mountain
Region, which means its producing properties and new drilling opportunities
are
geographically concentrated in that area. As a result, the Company, the success
of its operations, and its profitability may be disproportionately exposed
to
the impact of delays or interruptions of production from existing or planned
new
wells by significant governmental regulation, transportation capacity
constraints, curtailment of production, interruption of transportation, or
fluctuations in prices of oil and natural gas produced from the wells in the
region.
Seasonal
weather conditions and lease stipulations adversely affect the Company’s ability
to conduct drilling activities in some of the areas where it
operates.
Oil
and
natural gas operations in the Rocky Mountains are adversely affected by seasonal
weather conditions and lease stipulations designed to protect various wildlife.
In certain areas, including parts of the Piceance Basin in Colorado, drilling
and other oil and natural gas activities are restricted or prohibited by lease
stipulations, or prevented by weather conditions, for up to six months out
of
the year. This limits 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 operations and materially
increase operating and capital costs and therefore adversely affect
profitability.
Properties
that the Company buys may not produce as projected and the Company may be unable
to determine reserve potential, identify liabilities associated with the
properties or obtain protection from sellers against those
liabilities.
One
of
the Company’s growth strategies is to acquire producing oil and natural gas
reserves in its current areas of operations and in new areas. However, reviews
of potential acquisitions are inherently incomplete because it generally is
not
feasible to review in depth every individual property. Ordinarily, the Company
focuses review efforts on the higher value properties and will sample the
remainder. However, even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer
to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, are not
necessarily observable or detectable even when an inspection is undertaken.
Even
when problems are identified, the Company may choose to assume certain
environmental and other risks and liabilities in connection with acquired
properties.
The
Company has limited control over activities on properties it does not operate,
which could reduce its production and revenues.
The
Company operates most of the wells in which it owns an interest. However, there
are some wells the Company does not operate because it participates through
joint operating agreements under which it owns partial interests in oil and
natural gas properties operated by other entities. If the Company does not
operate the properties in which it owns an interest, it does 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 the Company’s profitability. The success and
timing of drilling and development activities on properties operated by others
therefore depends upon a number of factors outside of the Company’s control,
including the operator’s timing and amount of capital expenditures, expertise
and financial resources, inclusion of other participants in drilling wells,
and
use of technology.
Market
conditions or operational impediments could hinder access to oil and natural
gas
markets or delay production.
Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder access to oil and natural gas markets
or
delay production. The availability of a ready market for oil and natural gas
production depends on a number of factors, including the demand for and supply
of oil and natural gas and the proximity of reserves to pipelines and terminal
facilities. The Company’s ability to market its 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 the Company’s
business. The Company 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, the Company would be unable to realize revenue from those wells until
production arrangements were made to deliver the production to market and its
profitability would be adversely affected.
The
Company’s derivative activities could result in financial losses or could reduce
its income.
To
achieve a more predictable cash flow, to reduce exposure to adverse fluctuations
in the prices of oil and natural gas and to allow its gas marketing company
to
offer pricing options to gas sellers and purchasers, the Company uses
derivatives for a portion of its oil and natural gas production from its own
wells, its partnerships and for gas purchases and sales by its marketing
subsidiary. These arrangements expose the Company 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 received. In
addition, derivative arrangements may limit the benefit from changes in the
prices for oil and natural gas and may require the use of Company resources
to
meet cash margin requirements. Since the Company’s derivatives do not currently
qualify for use of hedge accounting, changes in the fair value of derivatives
are recorded in the statements of income and earnings are subject to greater
volatility.
The
inability of one or more of the Company’s customers to meet their obligations
may adversely affect the Company’s financial results.
Substantially
all of the Company’s accounts receivable result from oil and natural gas sales
or joint interest billings to third parties in the energy industry. This
concentration of customers and joint interest owners may impact the Company’s
overall credit risk in that these entities may be similarly affected by changes
in economic and other conditions. In addition, the Company’s oil and natural gas
derivatives as well as the derivatives used by its marketing subsidiary expose
the Company to credit risk in the event of nonperformance by counterparties.
The
Company depends on a limited number of key personnel who would be difficult
to
replace.
The
Company depends on the performance of its executive officers and other key
employees. The loss of any member of senior management or other key employees
could negatively impact the Company’s ability to execute its strategy.
Terrorist
attacks or similar hostilities may adversely impact the Company’s results of
operations.
Increasing
terrorist attacks around the world have created many economic and political
uncertainties, some of which may materially adversely impact the Company’s
business. Uncertainty surrounding military strikes or a sustained military
campaign may affect the Company’s 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 the Company’s operations to increased risks and depending on their
ultimate magnitude, could have a material adverse effect on its business,
results of operations, financial condition and prospects.
The
Company’s insurance coverage may not be sufficient to cover some liabilities or
losses that the Company may incur.
The
occurrence of a significant accident or other event not fully covered by
insurance could have a material adverse effect on the Company’s operations and
financial condition. Insurance does not protect the Company against all
operational risks. The Company does not carry business interruption insurance
at
levels that would provide enough funds for it to continue operating without
access to other funds. For some risks, the Company may not obtain insurance
if
it believes the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable.
The
Company may not be able to keep pace with technological developments in its
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 others use or develop new technologies, the Company may
be
placed at a competitive disadvantage, and competitive pressures may force it
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 the Company can. The
Company 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 the Company uses now or in the future were to become obsolete
or if it was unable to use the most advanced commercially available technology,
its business, financial condition and results of operations could be materially
adversely affected.
Competition
in the oil and natural gas industry is intense, which may adversely affect
the
Company’s ability to succeed.
The
oil
and natural gas industry is intensely competitive, and the Company competes
with
other companies that have greater resources. Many of these companies not only
explore for and produce oil and natural gas, 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 oil
and
natural gas properties and exploratory prospects or define, evaluate, bid for
and purchase a greater number of properties and prospects than the Company’s
financial or human resources permit. In addition, these companies may have
a
greater ability to continue exploration activities during periods of low oil
and
natural gas 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 the Company can, which would adversely affect the Company’s
competitive position. The Company’s ability to acquire additional properties and
to discover reserves in the future will be dependent upon its ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment. In addition, because many companies in its
industry have greater financial and human resources, the Company may be at
a
disadvantage in bidding for exploratory prospects and producing oil and natural
gas properties. These factors could adversely affect the success of the
Company’s operations and its profitability.
The
Company is subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or feasibility of
doing
business.
The
Company’s 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 oil and natural gas wells. Under
these laws and regulations, the Company 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 the Company 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, in some cases, federal requirements for
obtaining environmental assessments, environmental impact studies and/or plans
of development before commencing exploration and production activities. In
addition, the Company’s activities are subject to the regulation by oil and
natural gas-producing states of conservation practices and protection of
correlative rights. These regulations affect operations and limit the quantity
of oil and natural gas that can be produced and sold. A major risk inherent
in
the Company’s 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 the Company’s ability to explore on or develop its properties.
Additionally, the oil and natural gas regulatory environment could change in
ways that might substantially increase the financial and managerial costs to
comply with the requirements of these laws and regulations and, consequently,
adversely affect profitability. Furthermore, the Company may be put at a
competitive disadvantage to larger companies in the industry who can spread
these additional costs over a greater number of wells and larger operating
staff. See “Business — Governmental Regulation — Regulation of Oil and
Natural Gas Exploration and Production” and “Business — Governmental
Regulation — Environmental Regulations” for a description of the laws and
regulations that affect us.
If
litigation were commenced against the Company for alleged royalty practices
and
payments, the cost of our defending the lawsuit could be significant and any
resulting judgments against the Company could have a material adverse impact
upon our financial condition.
Recent
litigation has commenced against several companies in the Company's industry
regarding royalty practices and payments in jurisdictions where the Company
conducts business. While the Company's business model differs from those of
the
litigants in those cases, and the Company has not been named in any litigation,
has not had similar litigation commenced, and has not been threatened with
such
litigation, there can be no assurance that the Company will not become a party
to such litigation or to similar litigation in the future. If litigation of
this
nature were commenced against us, even if the ultimate outcome of the litigation
resulted in a judgment for the Company, the cost of defending the Company 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 the Company's
management would have to appropriate to the defense. Although the Company cannot
predict an eventual outcome were litigation to be commenced against us, a
judgment in favor of the plaintiffs could have a material adverse impact upon
the Company's financial condition.
Material
weaknesses in the Company’s internal control over financial reporting and
disclosure controls and procedures could adversely impact the reliability of
its
internal control over financial reporting, its ability to timely file certain
reports with the SEC, the liquidity of the market for its common stock and
its
ability to raise investment capital to support its drilling operations in the
future.
Management
has assessed the effectiveness of internal control over financial reporting
as
of December 31, 2006, and this assessment identified material weaknesses in
internal control over financial reporting and disclosure controls and
procedures. For discussion of these material weaknesses and the Company’s
remediation plans, please see Part II, Item 9A, “Controls and Procedures” of
this report. As a result of these material weaknesses, management concluded
that
the Company's internal control over financial reporting and disclosure controls
and procedures were not effective as of December 31, 2006.
Material
weaknesses were also identified during management’s assessment of the internal
control environment as of December 31, 2005. A description of these material
weaknesses can be found in Part II, Item 9A, “Controls and Procedures” of the
Annual Report for fiscal year 2005. As a result of these material weaknesses,
management concluded that the Company's internal control over financial
reporting was not effective as of December 31, 2005.
The
Company’s material weaknesses have led to restatements of its consolidated
financial statements in connection with the filing of its annual report on
Form
10-K for the year ended December 31, 2005. These material weaknesses have also
contributed to the delays the Company has experienced in filing its annual
reports on Form 10-K for the years ended December 31, 2006 and 2005. In
addition, the Company did not timely file with the SEC its Form 10-Q for the
quarters ended March 31, 2007 and 2006. A continued inability to timely file
its
periodic reports with the SEC could involve a number of significant risks,
which
could have an adverse impact on the Company’s operations, on the market for its
stock and investors generally, including:
|
·
|
The
potential delisting of the Company’s common stock. The Company's failure
to file its periodic reports timely constitutes a violation of the
listing
standards of the NASDAQ Stock Market. If the NASDAQ Stock Market
ceases to
grant the Company extensions of time in which to file its reports,
NASDAQ
has the right to begin proceedings to delist the Company’s common stock.
The Company had a hearing before the NASDAQ Listing Qualifications
Panel
("Panel") on May 10, 2007, regarding the Company's failure to file
timely
its Form 10-K for the year ended December 31, 2006. The Panel also
considered the Company's failure to file timely its Form 10-Q for
the
period ended March 31, 2007. It is possible that the Panel might
order the
delisting of the Company's stock from NASDAQ. The delisting of the
Company’s common stock could have a material adverse effect on the Company
by:
|
|
·
|
reducing
the liquidity and market price for its common stock;
|
|
·
|
reducing
the number of investors willing to hold or acquire its common stock,
which
in turn could further reduce its stock's liquidity;
and
|
|
·
|
limiting
the ability of investors to sell the Company’s common
stock.
|
If
the
Company is unable to prepare and file its annual report on Form 10-K in a timely
manner, and to a lesser degree, if the Company is unable to prepare and file
one
or more of its quarterly reports on Form 10-Q in a timely manner, the Company
might be unable to raise capital for Company operations, either by its selling
of its securities or through a borrowing facility. In this regard, under those
circumstances the Company could be faced with any of the following
risks:
|
·
|
If
the Company were unable to file its financial statements because
it is
unable to file its annual report on Form 10-K and/or its quarterly
financial reports on Form 10-Q, the Company would not be able to
raise
capital from the public markets through the sale of its stock or
debt
securities through an SEC-registered public offering. Likewise, the
Company’s inability to file its required periodic reports with the SEC in
a timely fashion may hinder its ability to raise capital through
the
private placement of its
securities.
|
|
·
|
A
major component of the Company's business plan is to raise drilling
capital through its public and private sales of partnership interests.
If
the Company is unable to file its annual reports and/or quarterly
reports
in a timely fashion, it will not be able to access the public markets
through an SEC-registered securities offering; and it may have difficulty
in accessing the private placement market for capital through an
SEC-exempt securities offering.
|
|
·
|
The
Company’s credit facility with JPMorgan Chase and BNP Paribas ("Lenders")
requires the Company to be current in its filing of its required
periodic
reports with the SEC. If the Company is unable to file its annual
reports
and/or quarterly reports with the SEC when due, the Lenders might
declare
the credit facility to be in default and any loans then outstanding
under
the credit facility would be immediately due and payable. Additionally,
even if the Lenders did not declare a default and accelerate repayment
of
outstanding amounts, the Company might not be able to borrow further
amounts under the facility. Moreover, the Company under those
circumstances might not be able to negotiate and arrange alternative
financing to support its drilling operations. See Note 5 to consolidated
financial statements for discussion related to the current waiver
the
Company has received under the credit
facility.
|
If
the
Company is unable to raise drilling capital and funding for its operations
as
cited in the three preceding paragraphs, then it would be likely that its
drilling operations would be materially adversely affected; and that its ability
to grow the Company in the historical manner would be severely hampered.
Moreover, it is likely that the Company’s business operations could be
materially adversely damaged.
|
·
|
Currently,
the Company has several employee and director stock benefit plans
in which
its common stock available under the plans has been registered by
SEC Form
S-8 under the Securities Act of 1933. Under SEC regulations, the
Company’s
failure to file with the SEC required annual reports on Form 10-K
will
cause its Form S-8 registration statement to be stale - that is,
not
current as to information about the Company. The result is that the
Form
S-8 would no longer be in compliance with the requirements of the
Securities Act, compliance with which allowed the Company to offer
these
stock benefits to Company employees for their investment. Consequently,
if
the Company does not file its annual reports with the SEC in a timely
fashion, the Company will have to suspend the availability of these
plans,
including the Company's 401(k) and Profit Sharing Plan, to allow
Company
employees to exercise any Company stock options that they hold or
to
choose to invest in Company common stock under the 401(k) and Profit
Sharing Plan. Additionally, those Company employees who own shares
of the
Company's common stock might find it more difficult to sell their
shares
in the market if the Company's common stock is delisted from the
NASDAQ
Stock Market.
|
Furthermore,
the number of subsequent failures to timely file any future periodic reports
with the SEC could increase the likelihood, frequency of occurrence, and
severity of the impact of any of the risks described above.
Since
the
identification of these material weaknesses, the Company has implemented and
is
continuing to implement various procedures intended to improve its internal
control over financial reporting and disclosure controls and procedures. No
assurance can be given that the Company will be effective in remedying all
identified deficiencies in its internal control over financial reporting and
disclosure controls and procedures. The Company has implemented procedures
to
remediate the material weaknesses identified during fiscal year 2005, and while
management believes that the reconciliation, capitalization assessment,
valuation, completeness determination and monitoring procedures and controls
implemented since December 31, 2006, will, when demonstrated to be operating
effectively, allow management to conclude that the material weaknesses
identified in 2006 have been remediated, there can also be no assurance that
the
material weaknesses will be rectified in a timely fashion or that additional
material weaknesses will not arise and be identified.
ITEM
1B. UNRESOLVED STAFF COMMENTS
In
September 2006, the Company received written comments from the staff of the
SEC
regarding its Annual Report on Form 10-K for the year ended December 31, 2005
("2005 Form 10-K"), to which the Company has subsequently provided responses.
The staff have since indicated to the Company that they have no further
outstanding comments related to the Company's 2005 Form 10-K. As a result,
the
Company does not believe it has any currently outstanding comments with the
staff with regard to its own filings.
However,
the Company, as managing general partner, has not yet filed all
Company-sponsored partnerships' 2005 Forms 10-K, related to which the Company
has previously issued filings on Forms 8-K (dated August 25, 2005, and November
15, 2005) advising that, due to errors in its accounting policies and practices,
no reliance should be placed on the related financial information, nor on the
auditors' opinion related thereto. As of the date of this filing, the Company
has not completed the corrections of these errors and is delinquent in its
filing requirements for 24 such Company-sponsored partnerships with regard
to
the year ended December 31, 2005. Additionally, for each of the same
Company-sponsored partnerships, the Company has not filed related Forms 10-Q
for
the quarterly periods ended March 31, 2006, June 30, 2006, September 30, 2006,
and March 31, 2007, or Forms 10-K for the year ended December 31,
2006.
ITEM
2. PROPERTIES
Summary
of Productive Wells
The
table
below shows the number of the Company's productive gross and net wells at
December 31, 2006.
|
Productive
Wells
|
|||||||||||||
|
Gas
|
Oil
|
||||||||||||
|
Location
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||
|
Colorado
|
1,445
|
794.0
|
25
|
19.3
|
|||||||||
|
Kansas
|
40
|
39.0
|
-
|
-
|
|||||||||
|
Michigan
|
199
|
106.0
|
7
|
2.7
|
|||||||||
|
North
Dakota
|
5
|
1.1
|
12
|
6.2
|
|||||||||
|
Pennsylvania
|
420
|
93.1
|
-
|
-
|
|||||||||
|
Tennessee
|
1
|
0.7
|
35
|
13.7
|
|||||||||
|
West
Virginia
|
905
|
515.9
|
4
|
1.7
|
|||||||||
|
Wyoming
|
-
|
-
|
3
|
0.7
|
|||||||||
|
Total
|
3,015
|
1,549.8
|
86
|
44.3
|
|||||||||
Oil
and Gas Reserves
All
of
the Company's natural gas and oil reserves are located in the United States.
The
Company's approximate net proved reserves were estimated by independent
petroleum engineers, to be 279,078 MMcf of natural gas and 7,272 MBbls of oil
at
December 31, 2006, 247,288 MMcf of natural gas and 4,538 MBbls of oil at
December 31, 2005, and 197,549 MMcf of natural gas and 3,316 MBbls of oil at
December 31, 2004.
The
Company's approximate net proved developed reserves were estimated, by
independent petroleum engineers, to be 158,978 MMcf of natural gas and 4,629
MBbls of oil at December 31, 2006, 155,354 MMcf of natural gas and 3,860 MBbls
of oil at December 31, 2005, and 146,152 MMcf of natural gas and 3,190 MBbls
of
oil at December 31, 2004.
The
Company utilized the services of two independent petroleum engineers for its
2006 independent reserve report. Wright & Company prepared the reserve
report for the Appalachian and Michigan Basin and Northeast Colorado ("NECO")
properties. Ryder Scott Company, LLP prepared the reserve report for the Rocky
Mountain Region, with the exception of the NECO properties. Wright & Company
prepared all of the reserve reports for the Company for 2005 and 2004 with
the
exception of 2005 North Dakota wells which were prepared by Ryder Scott
Company.
The
Company's oil and natural gas reserves by region are as follows as of December
31, 2006:
|
Oil
(MBbl)
|
Gas
(MMcf)
|
Natural
Gas
Equivalent
(MMcfe)
|
%
|
||||||||||
|
Proved
Developed Reserves
|
|||||||||||||
|
Appalachian
Basin
|
29
|
35,840
|
36,014
|
19.3
|
%
|
||||||||
|
Michigan
Basin
|
36
|
20,331
|
20,547
|
11.0
|
%
|
||||||||
|
Rocky
Mountain Region
|
4,564
|
102,807
|
130,191
|
69.7
|
%
|
||||||||
|
Total
Proved Developed Reserves
|
4,629
|
158,978
|
186,752
|
100.0
|
%
|
||||||||
|
Proved
Undeveloped Reserves
|
|||||||||||||
|
Appalachian
Basin
|
-
|
-
|
-
|
0.0
|
%
|
||||||||
|
Michigan
Basin
|
-
|
685
|
685
|
0.5
|
%
|
||||||||
|
Rocky
Mountain Region
|
2,643
|
119,415
|
135,273
|
99.5
|
%
|
||||||||
|
Total
Proved Undeveloped
|
2,643
|
120,100
|
135,958
|
100.0
|
%
|
||||||||
|
Total
Proved Reserves
|
|||||||||||||
|
Appalachian
Basin
|
29
|
35,840
|
36,014
|
11.2
|
%
|
||||||||
|
Michigan
Basin
|
36
|
21,016
|
21,232
|
6.6
|
%
|
||||||||
|
Rocky
Mountain Region
|
7,207
|
222,222
|
265,464
|
82.2
|
%
|
||||||||
|
Total
Proved Reserves
|
7,272
|
279,078
|
322,710
|
100.0
|
%
|
||||||||
No
major
discovery or other favorable or adverse event that would cause a significant
change in estimated reserves on the properties owned by the Company as of
December 31, 2006, is believed by the Company to have occurred since December
31, 2006, with the exception of the following acquisitions:
|
·
|
In
January 2007, the Company acquired 144 oil and gas wells and 8,160
acres
of leasehold in the Wattenberg Field area of the DJ Basin, Colorado
and an
increased net interest in 718 wells currently operated by the
Company.
|
|
·
|
In
February 2007, the Company acquired 28 producing wells and associated
undeveloped acreage in the Wattenberg Field.
|
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.
The
standardized measure of discounted future estimated net cash flows attributable
to the Company's proved oil and gas reserves, giving effect to future estimated
income tax expenses, was estimated by the Company’s independent petroleum
engineers to be $215.7 million as of December 31, 2006, $405.4 million as of
December 31, 2005, and $229.4 million as of December 31, 2004. These amounts
are
based on December 31 commodity prices in the respective years. The values
expressed are estimates only, and may not reflect realizable values or fair
market values of the natural gas and oil ultimately extracted and recovered.
The
standardized measure of discounted future net cash flows may not accurately
reflect proceeds of production to be received in the future from the sale of
natural gas and oil currently owned and does not necessarily reflect the actual
costs that would be incurred to acquire equivalent natural gas and oil
reserves.
Net
Proved Natural Gas and Oil Reserves
The
proved reserves of natural gas and oil of the Company as estimated by the
Company’s independent petroleum engineers at December 31, 2006, are set forth
below. These reserves have been prepared in compliance with the rules of the
SEC
based on December 31, 2006, prices. These reserve estimates were not filed
with
another Federal authority or agency since the Company filed its Form 10-K with
the SEC on May 31, 2006, for the year ended December 31, 2005. An analysis
of
the change in estimated quantities of natural gas and oil reserves from January
1, 2006 to December 31, 2006, all of which are located within the United States,
is shown below:
|
Natural
Gas
(MMcf)
|
Oil
(MBbl)
|
||||||
|
Proved
developed and undeveloped reserves:
|
|||||||
|
Beginning
of year
|
247,288
|
4,538
|
|||||
|
Revisions
of previous estimates
|
(28,067
|
)
|
35
|
||||
|
Beginning
of year as revised
|
219,221
|
4,573
|
|||||
|
New
discoveries and extensions
|
|||||||
|
Rocky
Mountain region
|
70,499
|
3,148
|
|||||
|
Dispositions
to partnerships
|
(1,215
|
)
|
(92
|
)
|
|||
|
Acquisitions
|
|||||||
|
Michigan
basin
|
35
|
-
|
|||||
|
Rocky
Mountain region
|
3,477
|
274
|
|||||
|
Appalachian
basin
|
222
|
-
|
|||||
|
Production
|
(13,161
|
)
|
(631
|
)
|
|||
|
End
of year
|
279,078
|
7,272
|
|||||
|
Proved
developed reserves:
|
|||||||
|
Beginning
of year
|
155,354
|
3,860
|
|||||
|
End
of year
|
158,978
|
4,629
|
|||||
Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Natural Gas and Oil Reserves
Summarized
in the following table is information for the Company with respect to the
standardized measure of discounted future net cash flows relating to proved
natural gas and oil reserves at December 31, 2006. Future cash inflows are
computed by applying year-end prices of natural gas and oil relating to the
Company's proved reserves to year-end quantities of those reserves. Future
production, development, site restoration and abandonment costs are derived
based on current costs, assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the statutory rate in effect
at December 31, 2006, to the future pretax net cash flows, less the tax basis
of
the properties, and gives effect to permanent differences, tax credits and
allowances related to the properties. (in thousands)
|
Future
estimated cash flows
|
$
|
1,804,796
|
||
|
Future
estimated production costs
|
(571,346
|
)
|
||
|
Future
estimated development costs
|
(373,460
|
)
|
||
|
Future
estimated income tax expense
|
(334,536
|
)
|
||
|
Future
net cash flows
|
525,454
|
|||
|
10%
annual discount for estimated timing of cash flows
|
(309,792
|
)
|
||
|
Standardized
measure of discounted future estimated net cash flows
|
$
|
215,662
|
The
following table summarizes the principal sources of change in the standardized
measure of discounted future estimated net cash flows from January 1, 2006,
through December 31, 2006: (in thousands)
|
Sales
of oil and gas production net of production costs
|
$
|
(94,337
|
)
|
|
|
Net
changes in prices and production costs
|
(299,721
|
)
|
||
|
Extensions,
discoveries, and improved recovery, less related costs
|
46,109
|
|||
|
Sales
of reserves
|
(3,356
|
)
|
||
|
Purchase
of reserves
|
11,003
|
|||
|
Development
costs incurred during the period
|
20,051
|
|||
|
Revisions
of previous quantity estimates
|
(23,146
|
)
|
||
|
Changes
in estimated income taxes
|
120,818
|
|||
|
Accretion
of discount
|
62,838
|
|||
|
Timing
and other
|
(30,027
|
)
|
||
|
Total
|
$
|
(189,768
|
)
|
It
is
necessary to emphasize that the data presented should not be viewed as
representing the expected cash flow from, or current value of, existing proved
reserves, because the computations are based on a large number of estimates
and
assumptions. Reserve quantities cannot be measured with precision, and their
estimation requires many judgmental determinations and frequent revisions.
The
required projection of production and related expenditures over time requires
further estimates with respect to pipeline availability, rates of demand and
governmental control. Actual future prices and costs are likely to be
substantially different from the current prices and costs utilized in the
computation of reported amounts. Any analysis or evaluation of the reported
amounts should give specific recognition to the computational methods and their
inherent limitations.
Substantially
all of the Company's natural gas and oil reserves have been mortgaged or pledged
as security for the Company's credit agreement. See Note 5 to the notes to
the
Company's financial statements.
Oil
and Natural Gas Leases
The
following table sets forth the by state leased acres available to the Company
for development of oil and natural gas as of December 31, 2006.
|
Colorado
|
42,900
|
|||
|
Kansas
|
23,000
|
|||
|
Michigan
|
200
|
|||
|
New
York
|
12,800
|
|||
|
North
Dakota
|
89,600
|
|||
|
Wyoming
|
32,000
|
|||
|
Total
|
200,500
|
Title
to Properties
The
Company’s management believes that it holds good and indefeasible title to its
properties, in accordance with standards generally accepted in the natural
gas
industry, subject to such exceptions stated in the opinion of counsel employed
in the various areas in which the Company conducts its exploration activities.
Those exceptions, in the Company's judgment, do not detract substantially from
the use of such property. As is customary in the natural gas industry, only
a
perfunctory title examination is conducted at the time the properties believed
to be suitable for drilling operations are acquired by the Company. Prior to
the
commencement of drilling operations, a title examination is conducted and
curative work is performed with respect to defects which the Company deems
to be
significant. A title examination has been performed with respect to
substantially all of the Company's producing properties. No single property
owned by the Company represents a material portion of the Company's holdings.
The
properties owned by the Company are subject to royalty, overriding royalty
and
other outstanding interests customary in the industry. The properties are also
subject to burdens such as liens incident to operating agreements, current
taxes, development obligations under natural gas and oil leases, farm-out
arrangements and other encumbrances, easements and restrictions. The Company
does not believe that any of these burdens will materially interfere with the
use of the properties.
Facilities
The
Company completed the construction of its new corporate headquarters in
Bridgeport, West Virginia, which was occupied in December 2006. The Company
intends to begin construction of a second office building adjacent to its new
corporate headquarters in 2007. The Company’s prior Bridgeport offices,
consisting of two buildings, will be placed on the market and available for
sale
sometime in 2007. The Company has an operating lease for its Denver Office
in
Denver, Colorado.
The
Company owns a field operating facility in each of Harrison and Gilmer Counties,
West Virginia, Alpena County, Michigan and Weld County, Colorado. The Company
has operating leases for two field offices in Colorado and one in
Pennsylvania.
ITEM
3. LEGAL PROCEEDINGS
From
time
to time the Company is a party to various legal proceedings in the ordinary
course of business. The Company is not currently a party to any litigation
that
it believes would have a materially adverse affect on the Company's business,
financial condition, results of operations, or liquidity.
Recent
litigation has commenced against several companies in our industry regarding
royalty practices and payments in jurisdictions where the Company conducts
business. While the Company's business model differs from those of the litigants
in those cases, and the Company has not been named in any litigation, has not
had similar litigation commenced, nor has such litigation been threatened,
there
can be no assurance that the Company will not be a party to any litigation
or to
similar litigation in the future.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
No
matters were submitted to a vote of security holders during the fourth quarter
of the fiscal year covered by this report.
PART
II
ITEM
5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
The
authorized capital stock of the Company consists of 50,000,000 shares of common
stock, par value $0.01 per share. There were 14,887,530 shares of common stock
issued and outstanding as of April 30, 2007. The common stock of the Company
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 the
Company's common stock as reported on the NASDAQ Global Select Market for the
periods indicated below.
|
High
|
Low
|
||||||
|
2006
|
|||||||
|
First
Quarter
|
$
|
46.06
|
$
|
32.46
|
|||
|
Second
Quarter
|
45.07
|
32.89
|
|||||
|
Third
Quarter
|
44.54
|
33.32
|
|||||
|
Fourth
Quarter
|
46.61
|
36.96
|
|||||
|
2005
|
|||||||
|
First
Quarter
|
44.19
|
35.72
|
|||||
|
Second
Quarter
|
37.28
|
22.65
|
|||||
|
Third
Quarter
|
40.00
|
32.54
|
|||||
|
Fourth
Quarter
|
39.55
|
30.53
|
|||||
As
of
April 30, 2007, there were approximately 908 record holders of the Company's
common stock.
The
Company has not paid any dividends on its common stock and currently intends
to
retain earnings for use in its business. Therefore, it does not expect to
declare cash dividends in the foreseeable future.
|
ISSUER
PURCHASES OF EQUITY SECURITIES
|
|||||||||||||
|
Period
|
Total
Number
of
Shares
Purchased
|
Average
Price
Paid
per Share
|
Total
Number
of
Shares
Purchased
as
Part
of Publicly
Announced
Plans
or
Programs
|
Maximum
Number of
Shares
that May
Yet
Be Purchased
Under
the Plans
or
Programs
|
|||||||||
|
October
1 - 20, 2006
|
334,242
|
$
|
40.93
|
334,242
|
1,477,109
|
||||||||
|
Total
|
334,242
|
$
|
40.93
|
334,242
|
1,477,109
|
||||||||
In
January 2006, the Company announced that its Board of Directors had authorized
the Company to purchase up to 10% (1,627,500 shares) of its outstanding common
stock during 2006. Stock purchases under this program were made in the open
market or in private transactions, at times and in amounts that management
deemed appropriate. On
October 20, 2006, the Company completed its January 2006 share purchase program.
Total shares purchased in 2006 pursuant to the program were 1,627,500 common
shares at a cost of $66.3 million ($40.75 average price paid per share),
including 100,000 shares from an executive officer of the Company at a cost
of
$4.1 million ($40.66 price paid per share). All shares purchased in accordance
with the program were subsequently retired.
On
October 16, 2006, the Board of Directors of the Company approved a second 2006
share purchase program authorizing the Company to purchase up to 10% of the
Company’s 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 management deems appropriate. The
Company may terminate or limit the stock purchase program at any time.
ITEM
6. SELECTED FINANCIAL DATA (in thousands, except per share
data)
|
Year
Ended December 31,
|
||||||||||||||||
|
2006
|
2005
|
2004
|
2003
|
2002
|
||||||||||||
|
|
|
|
|
|||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil
and gas well drilling operations
|
$
|
17,917
|
$
|
99,963
|
$
|
94,076
|
$
|
57,510
|
$
|
45,842
|
||||||
|
Gas
sales from marketing activities
|
131,325
|
121,104
|
94,627
|
73,132
|
43,537
|
|||||||||||
|
Oil
and gas sales
|
115,189
|
102,559
|
69,492
|
48,394
|
22,688
|
|||||||||||
|
Well
operations and pipeline income
|
10,704
|
8,760
|
7,677
|
6,907
|
5,771
|
|||||||||||
|
Oil
and gas price risk management gains (losses), net
|
9,147
|
(9,368
|
)
|
(3,085
|
)
|
(812
|
)
|
(370
|
)
|
|||||||
|
Other
income
|
2,221
|
2,180
|
1,696
|
3,338
|
2,549
|
|||||||||||
|
Total
revenues
|
286,503
|
325,198
|
264,483
|
188,469
|
120,017
|
|||||||||||
|
Costs
and expenses:
|
||||||||||||||||
|
Cost
of oil and gas well drilling operations
|
12,617
|
88,185
|
77,696
|
46,946
|
37,859
|
|||||||||||
|
Cost
of gas marketing activities
|
130,150
|
119,644
|
92,881
|
72,361
|
43,168
|
|||||||||||
|
Oil
and gas production and well operations costs
|
29,021
|
20,400
|
17,713
|
13,630
|
8,672
|
|||||||||||
|
Exploration
cost
|
8,131
|
11,115
|
-
|
-
|
-
|
|||||||||||
|
General
and administrative expense
|
19,047
|
6,960
|
4,506
|
4,975
|
4,392
|
|||||||||||
|
Depreciation,
depletion and amortization
|
33,735
|
21,116
|
18,156
|
15,313
|
12,602
|
|||||||||||
|
Total
costs and expenses
|
232,701
|
267,420
|
210,952
|
153,225
|
106,693
|
|||||||||||
|
Gain
on sale of leaseholds
|
328,000
|
7,669
|
-
|
-
|
-
|
|||||||||||
|
Income
from operations
|
381,802
|
65,447
|
53,531
|
35,244
|
13,324
|
|||||||||||
|
Interest
income
|
8,050
|
898
|
185
|
190
|
248
|
|||||||||||
|
Interest
expense
|
(2,443
|
)
|
(217
|
)
|
(238
|
)
|
(816
|
)
|
(1,505
|
)
|
||||||
|
Income
before income taxes and cumulative effect of change in accounting
principle
|
387,409
|
66,128
|
53,478
|
34,618
|
12,067
|
|||||||||||
|
Income
taxes
|
149,637
|
24,676
|
20,250
|
11,934
|
3,186
|
|||||||||||
|
Income
before cumulative effect of change in accounting principle
|
237,772
|
41,452
|
33,228
|
22,684
|
8,881
|
|||||||||||
|
Cumulative
effect of change in accounting principle (net of taxes of
$1,392)
|
-
|
-
|
-
|
(2,271
|
)
|
-
|
||||||||||
|
Net
income
|
$
|
237,772
|
$
|
41,452
|
$
|
33,228
|
$
|
20,413
|
$
|
8,881
|
||||||
|
Basic
earnings per common share
|
$
|
15.18
|
$
|
2.53
|
$
|
2.05
|
$
|
1.30
|
$
|
0.56
|
||||||
|
Diluted
earnings per share
|
$
|
15.11
|
$
|
2.52
|
$
|
2.00
|
$
|
1.25
|
$
|
0.55
|
||||||
|
December
31,
|
||||||||||||||||
|
2006
|
2005
|
2004
|
2003
|
2002
|
||||||||||||
|
Total
Assets
|
$
|
884,287
|
$
|
444,361
|
$
|
329,453
|
$
|
294,004
|
$
|
198,838
|
||||||
|
Working
Capital (Deficit)
|
$
|
29,180
|
$
|
(16,763
|
)
|
$
|
231
|
$
|
7,287
|
$
|
2,645
|
|||||
|
Long-Term
Debt
|
$
|
117,000
|
$
|
24,000
|
$
|
21,000
|
$
|
53,000
|
$
|
25,000
|
||||||
|
Stockholders'
Equity
|
$
|
360,144
|
$
|
188,265
|
$
|
154,021
|
$
|
112,559
|
$
|
92,887
|
||||||
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Safe
Harbor Statement Under the Private Securities Litigation Reform Act of
1995
Statements,
other than historical facts, contained in this Annual Report on Form 10-K,
including statements of estimated oil and gas production and reserves, drilling
plans, future cash flows, anticipated capital expenditures and Management's
strategies, plans and objectives, are "forward looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. Although the Company’s
management believes that its forward looking statements are based on reasonable
assumptions, it cautions that such statements are subject to a wide range of
risks and uncertainties incidental to the exploration for, acquisition,
development, production and marketing of oil and gas, and it can give no
assurance that its estimates and expectations will be realized. Important
factors that could cause actual results to differ materially from the forward
looking statements include, but are not limited to, changes in production
volumes, worldwide demand, and commodity prices for petroleum natural resources;
the timing and extent of the Company's success in discovering, acquiring,
developing and producing oil and gas reserves; the Company's ability to acquire
leases, drilling rigs, supplies and services at reasonable prices; the
availability of capital to the Company; the Company’s ability to raise funds
through its Partnership Drilling Programs; risks incident to the drilling and
operation of oil and gas wells; future production and development costs; the
effect of existing and future laws, governmental regulations and the political
and economic climate of the United States; the effect of oil and gas derivatives
activities; and conditions in the capital markets. Other risk factors are
discussed elsewhere in this Form 10-K.
Results
of Operations
Management
Overview
The
Company recorded strong revenues and cash flows for 2006. Although average
commodity prices declined during 2006 compared to 2005, a record 24% production
increase more than compensated for the price decline, as oil and gas sales
increased $12.6 million over 2005. The recent trend in declining profit margins
on the Company's oil and gas well drilling operations segment reversed during
the latter part of the year, as the Company switched from footage-based drilling
contracts, which lead to the declining margins, to cost-plus contracts where
the
Company does not bear the risk of cost changes on the wells it drills for the
partnerships. However, this change in type of contract, which allowed the
Company to recognize a contracted rate of profit from oil and gas well drilling
operations, resulted in an equal $74.6 million decline in revenue and related
costs. See "Drilling Operations" below for further discussion.
The
principal business event of the year was the sale of undeveloped property in
the
Grand Valley Field in the third quarter for a gain of $328 million, with
approximately $26 million in additional gains on the transaction deferred to
future periods, to be recognized if wells are drilled on certain properties.
The
proceeds of the sale, the qualification of the sale for like-kind exchange
tax
status and the property purchased during 2006 and 2007 have substantially
strengthened the Company's financial position and positioned it for continuing
growth in the coming periods.
Year
Ended December 31, 2006, Compared to December 31, 2005
Revenues
Total
revenues for the year ended December 31, 2006, were $286.5 million compared
to
$325.2 million for the year ended December 31, 2005, a decrease of approximately
$38.7
million,
or 11.9%.
The
decrease was primarily attributable to a decrease in drilling revenues of $82.1
million partially offset by the increased oil and gas sales from both gas
marketing activities and the Company’s share of production for a total of $22.9
million and the swing from a $9.4 million loss in oil and gas price risk
management for the year ended December 31, 2005, to a gain of $9.1 million
for
the year ended December 31, 2006. See "Drilling Operations" below for an
explanation of the impact the new cost-plus drilling arrangements and related
accounting had on drilling revenues for the year 2006.
Costs
and Expenses
Total
costs and expenses for the year ended December 31, 2006, were $232.7 million
compared to $267.4 million for the year ended December 31, 2005, a decrease
of
approximately $34.7 million, or 13%. The decrease was primarily
attributable to decreases in the cost of oil and gas well drilling operations
of
$75.6 million and exploration cost of $3 million offset in part by increases
in
the cost of gas marketing activities of $10.5 million, oil and gas production
and well operations costs of $8.6 million, general and administrative expenses
of $12.1 million and depreciation, depletion and amortization of $12.6 million.
See "Drilling Operations” below for an explanation of the impact of the new cost
plus drilling arrangements and related accounting had on drilling expenses
for
the year 2006.
Drilling
Operations
During
the first quarter of 2006, the Company began operating and recognizing revenues
for its cost-plus service arrangements with new partnerships, in addition to
its
footage-based drilling arrangements on earlier partnerships. The cost-plus
drilling arrangements became effective with the private program partnership
funded by the Company in December 2005 and continued in the 2006 partnership
funded on September 1, 2006. Drilling revenues for the year ended December
31,
2006, were $17.9 million, net of $74.6 million of costs related to drilling
arrangements accounted for on the cost-plus basis, compared to $100 million
for
the year ended December 31, 2005, a decrease of $82.1 million. The decrease
was
primarily due to the change in the Company’s drilling contracts, which resulted
in net revenue recognition related to the new contracts.
The
costs
of oil and gas well drilling operations for the year ended December 31, 2006,
was $12.6 million compared to $88.2 million for the year ended December 31,
2005, a decrease of $75.6 million. The decrease in costs is primarily
attributable to the Company’s revenue reporting for its new cost-plus drilling
arrangements, which reduced drilling costs by $74.6 million for the year as
discussed above.
The
new
cost-plus drilling arrangement eliminates the Company's risk of loss from the
contract drilling services it provides the partnerships. The Company’s drilling
revenues and corresponding costs are presented net as a one-lined income
statement item representing only the gross profit portion of the drilling
arrangement. The new cost-plus contract impacted the current year period by
reducing drilling revenues and drilling costs by $74.6 million as outlined
in
the table below (in millions):
|
Year
ended December 31,
|
|||||||||||||
|
2006
|
2005
|
||||||||||||
|
Drilling
Service
Revenue/Cost
|
Direct
Reimbursed
Cost
|
Revenue/Cost
Including
reimbursement
from
Partnerships
|
Drilling
Service
Revenue/Cost
|
||||||||||
|
Oil
and gas well drilling operations
|
$
|
17.9
|
$
|
74.6
|
$
|
92.5
|
$
|
100.0
|
|||||
|
Total
revenues
|
$
|
286.5
|
$
|
74.6
|
$
|
361.1
|
$
|
325.2
|
|||||
|
Cost
of oil and gas well drilling operations
|
$
|
12.6
|
$
|
74.6
|
$
|
87.2
|
$
|
88.2
|
|||||
|
Total
costs and expenses
|
$
|
232.7
|
$
|
74.6
|
$
|
307.3
|
$
|
267.4
|
|||||
Although
the Company changed to cost-plus drilling arrangements with its two recent
partnerships, prior footage-based contracts continue to be in effect, and
realized a loss of $2.1 million during 2006. This loss contributed to the
decrease in the drilling and development segment gross margin from $11.8 million
for the year ended December 31, 2005, to $5.3 million
for the year ended December 31, 2006. This loss was due to some drilling and
completion difficulties incurred and significantly increasing well drilling
and
completion costs, particularly the costs of fracturing and rising steel costs
for casing and other well equipment and oil field services. Future partnerships
will be drilled on a “cost-plus basis,” which should reduce these fluctuations
in drilling gross margins. See Note 1 to the consolidated financial
statements.
Natural
Gas Marketing Activities
Natural
gas sales from the marketing activities of RNG, the Company's marketing
subsidiary, increased for the year ended December 31, 2006, to $131.3 million
compared to $121.1 million for the year ended December 31, 2005, an increase
of
approximately $10.2 million, or 8.4%. The increase was the result of a 9%
increase in volumes sold at prices 17.2% lower than 2005 levels and significant
unrealized gains on derivative transactions which amounted to approximately
$12.3 million for the year ended December 31, 2006, compared to unrealized
losses of $8.5 million for the year ended December 31, 2005.
The
costs
of gas marketing activities for the year ended December 31, 2006, were $130.2
million compared to $119.6 million for the year ended December 31, 2005, an
increase of $10.6 million, or 8.9%. The increase was due to higher average
volumes of natural gas purchased for resale and a significant increase in
unrealized losses on derivative transactions, which amounted to approximately
$11.9 million for the year ended December 31, 2006, compared to an unrealized
gain of $8.3 million for the year ended December 31, 2005. Income before income
taxes for the Company's natural gas marketing subsidiary increased from $1.7
million for the year ended December 31, 2005, to $1.8 million for the year
ended
December 31, 2006. Based on the nature of the Company's gas marketing
activities, derivatives did not have a significant impact on the Company's
net
margins from marketing activities during either period.
Oil
and Gas Sales
Oil
and
gas sales from the Company's producing properties for the year ended December
31, 2006, were $115.2 million compared to $102.6 million for the year ended
December 31, 2005, an increase of $12.6 million, or 12.3%. The increase was
due
to a 24% increase in volumes sold at lower average sales prices of natural
gas
and, in part, to higher average sales prices and higher volumes sold of oil.
The
volume of natural gas sold for the year ended December 31, 2006, was 13.2 Bcf
at
an average price of $5.91 per Mcf compared to 11.0 Bcf at an average sales
price
of $7.29 per Mcf for the year ended December 31, 2005. Oil sales for the year
ended December 31, 2006, were 631,000 barrels at an average sales price of
$59.33 per barrel compared to 439,000 barrels at an average sales price of
$50.56 per barrel for the year ended December 31, 2005. The increase in natural
gas and oil volumes was the result of the Company's increased investment in
oil
and gas properties, primarily the increase in net wells drilled for the
Company’s own account, recompletions of existing wells, and the investment in
oil and gas properties it owns in drilling program partnerships.
Oil
and Gas Production
The
Company's oil and gas production by area of operations along with average sales
price (excluding derivative gains and losses) is presented below:
|
Year
Ended December 31, 2006
|
Year
Ended December 31, 2005
|
||||||||||||||||||
|
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Natural
Gas
Equivalents
(Mcfe)*
|
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Natural
Gas
Equivalents
(Mcfe)*
|
||||||||||||||
|
Appalachian
Region
|
1,837
|
1,451,729
|
1,462,751
|
3,973
|
1,631,552
|
1,655,390
|
|||||||||||||
|
Michigan
Region
|
4,439
|
1,399,852
|
1,426,486
|
4,732
|
1,555,958
|
1,584,350
|
|||||||||||||
|
Rocky
Mountain Region
|
625,119
|
10,309,203
|
14,059,917
|
430,266
|
7,843,250
|
10,424,846
|
|||||||||||||
|
Total
|
631,395
|
13,160,784
|
16,949,154
|
438,971
|
11,030,760
|
13,664,586
|
|||||||||||||
|
Average
Sales Price
|
$
|
59.33
|
$
|
5.91
|
$
|
6.80
|
$
|
50.56
|
$
|
7.29
|
$
|
7.51
|
|||||||
*Six
Bbl
equals one Mcfe
Financial
results depend upon many factors, particularly the price of natural gas and
the
Company’s ability to market its production effectively. Natural gas and oil
prices have been among the most volatile of all commodity prices. These price
variations can have a material impact on the Company’s financial results.
Natural gas and oil prices also vary by region, and locality, depending upon
the
distance to markets, and the supply and demand relationships in that region
or
locality. This can be especially true in the Rocky Mountain Region. The
combination of increased drilling activity and the lack of local markets can
entail a local oversupply situation from time to time. There are a number of
different pipelines in various stages of construction which will help to
maintain a balance between supply and demand. However, there may be times in
which there may be oversupply situations for short or longer terms, which may
affect the amount of gas or oil that the Company can sell, and the price at
which it sells gas or oil. Like most other producers in the region, the Company
relies on major interstate pipeline companies to construct these facilities,
so
their timing is not within its control.
Oil
and Gas Derivative Activities
Because
of uncertainty surrounding natural gas prices, the Company has used various
derivative instruments to manage some of the impact of fluctuations in prices.
Through October 2008, the Company has in place a series of floors and ceilings
associated with part of its natural gas production. Under the arrangements,
if
the applicable index rises above the ceiling price, the Company pays the
counterparty; however, if the index drops below the floor, the counterparty
pays
us. During the three months ended December 31, 2006, the Company averaged
natural gas volumes sold of 1,283,000 Mcf per month and oil sales of 52,000
barrels per month. The positions in effect as of May 10, 2007, on the Company's
share of production (the
table below does not include positions related to RNG activities or derivative
contracts entered into by the Company on behalf of the affiliate Partnerships
as
the Managing General Partner)
by area
are shown in the following table.
|
Floors
|
Ceilings
|
|||||||||||||||||
|
Monthly
Quantity
Gas-MMbtu
Oil-Bbls
|
Contract
Price
|
Monthly
Quantity
MMbtu
|
Contract
Price
|
|||||||||||||||
|
Month
Set
|
Months
Covered
|
|||||||||||||||||
|
Colorado
Interstate Gas (CIG) Based Hedges (Piceance Basin)
|
||||||||||||||||||
|
Feb-06
|
May
2007 – Oct 2007
|
44,000
|
$ |
5.50
|
-
|
$ |
-
|
|||||||||||
|
Sep-06
|
May
2007 – Oct 2007
|
194,500
|
4.50
|
-
|
-
|
|||||||||||||
|
Dec-06
|
Nov
2007 – Mar 2008
|
100,000
|
5.25
|
-
|
-
|
|||||||||||||
|
Jan-07
|
Nov
2007 – Mar 2008
|
100,000
|
5.25
|
100,000
|
9.80
|
|||||||||||||
|
May-07
|
Apr
2008 – Oct 2008
|
197,250
|
5.50
|
197,250
|
10.35
|
|||||||||||||
|
NYMEX
Based Hedges - (Appalachian and Michigan Basins)
|
||||||||||||||||||
|
Feb-06
|
May
2007 – Oct 2007
|
85,000
|
7.00
|
-
|
-
|
|||||||||||||
|
Feb-06
|
May
2007 – Oct 2007
|
85,000
|
7.50
|
34,000
|
10.83
|
|||||||||||||
|
Sep-06
|
May
2007 – Oct 2007
|
85,000
|
6.25
|
-
|
-
|
|||||||||||||
|
Jan-07
|
May
2007 – Oct 2007
|
85,000
|
5.25
|
-
|
-
|
|||||||||||||
|
Dec-06
|
Nov
2007 – Mar 2008
|
144,500
|
7.00
|
-
|
-
|
|||||||||||||
|
Jan-07
|
Nov
2007 – Mar 2008
|
144,500
|
7.00
|
153,000
|
13.70
|
|||||||||||||
|
Jan-07
|
Apr
2008 – Oct 2008
|
144,500
|
6.50
|
153,000
|
10.80
|
|||||||||||||
|
Panhandle
Based Hedges (NECO)
|
||||||||||||||||||
|
Feb-06
|
May
2007 – Oct 2007
|
60,000
|
6.00
|
-
|
-
|
|||||||||||||
|
Feb-06
|
May
2007 – Oct 2007
|
60,000
|
6.50
|
60,000
|
9.80
|
|||||||||||||
|
Jan-07
|
May
2007 – Oct 2007
|
90,000
|
4.50
|
-
|
-
|
|||||||||||||
|
Dec-06
|
Nov
2007 – Mar 2008
|
70,000
|
5.75
|
-
|
-
|
|||||||||||||
|
Jan-07
|
Nov
2007 – Mar 2008
|
90,000
|
6.00
|
90,000
|
11.25
|
|||||||||||||
|
Jan-07
|
Apr
2008 – Oct 2008
|
90,000
|
5.50
|
90,000
|
9.85
|
|||||||||||||
|
DJ
Basin
|
||||||||||||||||||
|
Jan-07
|
May
2007 – Oct 2007
|
161,000
|
4.00
|
-
|
-
|
|||||||||||||
|
Jan-07
|
Nov
2007 – Mar 2008
|
90,000
|
5.25
|
90,000
|
9.80
|
|||||||||||||
|
May-07
|
Apr
2008 – Oct 2008
|
216,000
|
5.50
|
216,000
|
10.35
|
|||||||||||||
|
DJ
Basin EXCO Property Acquisition
|
||||||||||||||||||
|
Jan-07
|
May
2007 – Oct 2007
|
60,000
|
4.00
|
-
|
-
|
|||||||||||||
|
Jan-07
|
Nov
2007 – Mar 2008
|
30,000
|
5.25
|
30,000
|
9.80
|
|||||||||||||
|
May-07
|
Apr
2008 – Oct 2008
|
90,000
|
5.50
|
90,000
|
10.35
|
|||||||||||||
|
Oil
– NYMEX Based (Wattenberg/ND)
|
||||||||||||||||||
|
Sep-06
|
May
2007 – Oct 2007
|
12,350
|
50.00
|
-
|
-
|
|||||||||||||
Well
Operations and Pipeline Income
Well
operations and pipeline income for the year ended December 31, 2006, were $10.7
million compared to $8.8 million for the year ended December 31, 2005, an
increase of approximately $1.9 million, or 21.6%. The increase was due to an
increase in the number of wells and pipeline systems operated by the Company
for
drilling partnerships, as well as for third parties.
Oil
and Gas Price Risk Management Gains (Losses), Net
Oil
and
gas price risk management gains (losses), net for the year ended December 31,
2006, was an aggregate gain of $9.1 million compared to a loss of approximately
$9.4 million for the year ended December 31, 2005, a favorable change of $18.5
million. For the year ended December 31, 2006, the Company recorded realized
gains of $1.9 million and unrealized gains of $7.2 million compared to the
year
ended December 31, 2005, which is comprised of unrealized losses of $3 million
and realized losses of $6.4 million. The Company’s strategy is to provide
protection in the event of declining oil and natural gas prices. During 2006,
the Company experienced decreasing natural gas and rising oil pricing
environments. This trend and the timing, extent and nature of the derivative
trades executed caused the Company to record gains in its derivative
transactions as a result of gains on the natural gas positions. Oil and gas
price risk management gains (losses), net is comprised of the change in fair
value of oil and natural gas derivatives related to oil and gas production
(this
line item does not include commodity-based derivative transactions related
to
transactions from gas marketing activities, which are included in the revenues
and expenses of the related purchase and sales transactions).
Other
Income
Other
income, consisting primarily of management fees associated with
Company-sponsored drilling programs, was relatively unchanged at $2.2 million
for each of the years ended December 31, 2006 and 2005.
Oil
and Gas Production and Well Operations Costs
Oil
and gas production and well
operations costs from the Company’s producing properties for the year ended
December 31, 2006, were $29.0 million compared to $20.4 million for the year
ended December 31, 2005, an increase of approximately $8.6 million, or
42.2%. The increase was due to the increased production costs
associated with the 24% increase in production volumes, along with the increased
number of wells and pipelines operated by the Company. Lifting costs
per Mcfe increased from $1.19 per Mcfe for the year ended December 31, 2005,
to
$1.23 per Mcfe for the year ended December 31, 2006, due to the significant
inflation of oil field production services along with additional well workovers
and production enhancements work performed.
Exploration
Cost
The
Company’s exploration cost for December 31, 2006, decreased $3 million from
$11.1 million for the same period last year to $8.1 million. The
decrease is primarily attributable to fewer exploratory dry holes being drilled
in 2006. In 2006, exploratory dry hole expenses were $1.8 million
compared to $11.1 million in 2005. In 2006, the Company recorded an
impairment charge of $1.5 million on its Nesson Field in North Dakota and
incurred geological and geophysical costs of $2.2 million which relate to
an
exploratory seismic program initiated on the Company’s Northeast Colorado
properties. The Company anticipates additional geological and
geophysical activities and related costs in 2007.
General
and Administrative Expense
General
and administrative expense for
the year ended December 31, 2006, increased to $19 million compared to $7
million for the year ended December 31, 2005, an increase of approximately
$12
million, or 171.4%. A substantial portion of the increase was
attributable to the costs of the Company’s financial statement restatement and
the restatement of the Company-sponsored partnerships’ financial
statements. In addition, the Company continues to experience a high
level of costs complying with the various provisions of Sarbanes-Oxley, in
particular Section 404 (internal and external costs of assessing Internal
Controls over Financial Reporting). Approximately $3.2 million of the
increase is attributable to the external costs incurred in connection with
restatement of financial statements and compliance with the provisions of
Sarbanes-Oxley. Finally, the Company added over 39 new
employees in 2006 and experienced increased payroll and payroll-related costs
of
$4.3 million.
Depreciation,
Depletion, and Amortization
Depreciation,
depletion, and
amortization costs for the year ended December 31, 2006, increased to $33.7
million from approximately $21.1 million for the year ended December 31,
2005,
an increase of approximately $12.6 million, or 59.7%. The increase
was due to the 24% increase in production volumes, significant investments
in
oil and gas properties by the Company in 2006, and increased per unit cost
of
depreciation, depletion and amortization as a result of rising costs of
drilling, completing and equipping wells.
Gain
on Sale of Leaseholds
Gain
on
sale of leaseholds for the year ended December 31, 2006, was $328 million
compared to $7.7 million in 2005, an increase of $320.3 million. The increase
is
attributable to the sale of undeveloped leaseholds in Garfield County, Colorado
in the third quarter of 2006, for which a portion of the gain to be recognized
was deferred to future periods. See Note 15 to consolidated financial
statements. The prior year period included a gain of $6.2 million for the sale
of a portion of one of the Company’s undeveloped leases in Garfield County,
Colorado and a gain of $1.5 million for the sale to an unaffiliated party of
some Pennsylvania wells.
Interest
Income
For
the
year ended December 31, 2006, interest income increased $7.2 million to $8.1
million compared to $0.9 million for the prior year period. The increase was
primarily due to the interest income on the temporary investment, in cash
equivalents, of cash proceeds of $353.6 million from the sale of undeveloped
leaseholds.
Interest
Expense
Interest
expense for the year ended December 31, 2006, was $2.4 compared to $0.2 million
for the year ended December 31, 2005, an increase of $2.2 million. The increase
in interest expense was due to rising interest rates on significantly higher
average outstanding balances of the credit facility, offset in part by $1.6
million of capitalized construction period interest. The Company utilizes its
daily cash balances to reduce its line of credit to lower its cost of borrowing.
The average outstanding debt balance for the year ended December 31, 2006,
was
$44.2 million compared to $4.1 million for the year ended December 31, 2005.
Provision
for Income Taxes
The
effective income tax rate for the Company's provision for income taxes increased
from 37.3% for the year ended December 31, 2005, to 38.6% for the year ended
December 31, 2006, primarily as a result of the gain on sale of leasehold being
taxed at the full federal and state statutory rates because there are no
offsetting permanent deductions, such as percentage depletion, available on
such
a sale. In addition, the domestic production activities deduction was not
utilized in 2006 due to the Company’s decision, for tax purposes only, to
expense the majority of its intangible drilling costs.
Year
Ended December 31, 2005, Compared to December 31,
2004
Revenues
Total
revenues for the year ended December 31, 2005, were $325.2 million compared
to
$264.5 million for the year ended December 31, 2004, an increase of
approximately $60.7
million,
or 22.9%.
The
increase was a result of increased drilling revenues, gas sales from natural
gas
marketing activities, oil and gas sales, well operations and pipeline income,
and other income partially offset by increased oil and gas price risk management
losses.
Costs
and Expenses
Total
costs and expenses for the year ended December 31, 2005, were $267.4 million
compared to $211 million for the year ended December 31, 2004, an increase
of
approximately $56.4 million or 26.7%. The increase was primarily the result
of
increased cost of oil and gas well drilling operations, cost of gas marketing
activities, oil and gas production and well operations cost, exploration costs,
general and administrative expenses and depreciation, depletion and
amortization.
Drilling
Operations
Drilling
revenues for the year ended December 31, 2005, were $100 million compared to
$94.1 million for the year ended December 31, 2004, an increase of approximately
$5.9 million or 6.3%. Such increase was due to the increased drilling funds
raised and drilled during the year through the Company's drilling programs.
The
Company-sponsored drilling programs in 2005 (two public and one private) raised
$116 million compared to $100 million in 2004. The Company believes higher
oil
and natural gas prices and the resulting improved performance of prior programs
are the reasons for the increase in drilling program sales.
Oil
and
gas well drilling operations costs for the year ended December 31, 2005, were
$88.2 million compared to $77.7 million for the year ended December 31, 2004,
an
increase of approximately $10.5 million or 13.5%. The increase was due to the
higher levels of drilling activity from public drilling programs referred to
above and increased costs from higher charges for services and materials
provided to the Company. The gross margin on the drilling activities for the
year ended December 31, 2005 was 11.8% compared with 17.4% for the year ended
December 31, 2004, a decrease in gross margin of approximately 5.6%. The
decrease was due to significantly increasing well drilling and completion costs,
particularly the costs of fracturing and rising steel costs for casing and
other
well equipment and oil field services. The
private drilling partnership funded on December 30, 2005, with wells to be
drilled during the first quarter of 2006 and future partnerships will be drilled
on a "cost plus basis"; that should reduce these fluctuations in drilling gross
margins.
This
new
cost-plus drilling arrangement eliminates the Company's risk of loss, thus
the
drilling revenues and corresponding costs will be netted to a one-lined income
statement item representing only the gross profit portion of the drilling
arrangement. This would have a significant effect on the Company's 2006 gross
drilling revenues and corresponding drilling expenses, but would not change
the
gross profit.
Natural
Gas Marketing Activities
Natural
gas sales from the marketing activities of RNG, the Company's marketing
subsidiary for the year ended December 31, 2005, were $121.1 million compared
to
$94.6 million for the year ended December 31, 2004, an increase of approximately
$26.5 million or 28.0%. The increase was the result of significantly higher
average natural gas sales prices and higher volumes sold offset in part by
an
increase in unrealized losses on derivative transactions which amounted to
approximately $8.5 million in 2005 compared to unrealized gains of $1.2 million
in 2004.
The
costs
of gas marketing activities for the year ended December 31, 2005, were $119.6
million compared to $92.9 million for the year ended December 31, 2004, an
increase of $26.7 million or 28.7%. The increase was due to higher average
volumes of natural gas purchased for resale and significantly higher average
purchase prices offset in part by an increase in unrealized gains on derivative
transactions which amounted to approximately $8.3 million in 2005 compared
to
unrealized losses of $0.8 million in 2004. Income before income taxes for the
Company's natural gas marketing subsidiary decreased from $1.8 million for
the
year ended December 31, 2004, to $1.7 million for the year ended December 31,
2005. Based on the nature of the Company's gas marketing activities, derivatives
did not have a significant impact on the Company's net margins from marketing
activities during either period.
Oil
and Gas Sales
Oil
and
gas sales from the Company's producing properties for the year ended December
31, 2005, were $102.6 million compared to $69.5 million for the year ended
December 31, 2004, an increase of $33.1 million or 47.6%. The increase was
due
to higher volumes sold at significantly higher average sales prices of oil
and
natural gas. The volume of natural gas sold for the year ended December 31,
2005, was 11 million Mcf at an average price of $7.29 per Mcf compared to 10.4
million Mcf at an average sales price of $5.30 per Mcf for the year ended
December 31, 2004. Oil sales for the year ended December 31, 2005, were 439,000
barrels at an average sales price of $50.56 per barrel compared to 381,000
barrels at an average sales price of $38.00 per barrel for the year ended
December 31, 2004. The increase in natural gas and oil volumes was the result
of
the Company's increased investment in oil and gas properties, primarily
recompletions of existing wells, wells drilled in the NECO, Colorado area of
operation, and the investment in oil and gas properties the Company owns in
the
public drilling program partnerships.
Oil
and Gas Production
The
Company's oil and gas production by area of operations along with average sales
price (excluding derivative losses) is presented below:
|
Year
Ended December 31, 2005
|
Year
Ended December 31, 2004
|
||||||||||||||||||
|
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Natural
Gas
Equivalents
(Mcfe)
|
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Natural
Gas
Equivalents
(Mcfe)
|
||||||||||||||
|
Appalachian
Region
|
3,973
|
1,631,552
|
1,655,390
|
4,893
|
1,812,407
|
1,841,765
|
|||||||||||||
|
Michigan
Region
|
4,732
|
1,555,958
|
1,584,350
|
5,786
|
1,728,435
|
1,763,151
|
|||||||||||||
|
Rocky
Mountain Region
|
430,266
|
7,843,250
|
10,424,846
|
370,482
|
6,831,032
|
9,053,924
|
|||||||||||||
|
Total
|
438,971
|
11,030,760
|
13,664,586
|
381,161
|
10,371,874
|
12,658,840
|
|||||||||||||
|
Average
Sales Price
|
$
|
50.56
|
$
|
7.29
|
$
|
7.51
|
$
|
38.00
|
$
|
5.30
|
$
|
5.49
|
|||||||
Financial
results depend upon many factors, particularly the price of natural gas and
the
Company’s ability to market its production effectively. In recent years, natural
gas and oil prices have been among the most volatile of all commodity prices.
These price variations can have a material impact on the Company’s financial
results. Natural gas prices in the Rocky Mountain Region continue to trail
prices which the Company receives for Appalachian and Michigan gas. The
Company’s management believes the lower prices in the Rocky Mountain Region,
including Colorado, reflect the higher costs to move gas to major market areas
compared to Michigan and the Appalachian Basin resulting in a lower price
compared to the eastern areas. In May 2003, a pipeline expansion project was
completed, leading to improved natural gas prices in the region which reduced
the local surplus. There is currently a substantial amount of drilling activity
in the Rockies, and if future additions to the pipeline system are not made
in a
timely fashion it is possible that pipeline constraints could create a local
oversupply situation in the future which could mean lower natural gas prices.
Like most other producers in the area the Company relies on major interstate
pipeline companies to construct these facilities, so their timing and
construction is not within its control.
Oil
and Gas Derivative Activities
Because
of uncertainty surrounding natural gas prices the Company has used various
derivative instruments to manage some of the impact of fluctuations in prices.
At April 30, 2006, the Company had in place, through October 2007, a series
of
floors and ceilings on part of natural gas production. Under the arrangements,
if the applicable index rises above the ceiling price, the Company pays the
counterparty, however if the index drops below the floor the counterparty pays
us. During the three months ended December 31, 2005, the Company averaged
natural gas volumes sold of 973,700 Mcf per month and oil sales of 36,050
barrels per month. The positions in effect as of April 30, 2006, on the
Company's share of production (the table below does not include positions
related to Riley Marketing activities or derivative contracts entered into
by
the Company on behalf of the affiliate Partnerships as the Managing General
Partner) by area are shown in the following table.
|
Floors
|
Ceilings
|
|||||||||||||||||
|
Month
Set
|
Contract
Term
|
Monthly
Quantity
Gas-MMbtu
Oil-Barrels
|
Contract
Price
|
Monthly
Quantity
Gas-MMbtu
Oil-Barrels
|
Contract
Price
|
|||||||||||||
|
Colorado
Interstate Gas (CIG) Based Derivatives (Piceance
Basin)
|
||||||||||||||||||
|
Jan-05
|
Jan
2006 – Mar 2006
|
60,000
|
$ |
4.50
|
30,000
|
$ |
7.15
|
|||||||||||
|
Jul-05
|
Jan
2006 – Mar 2006
|
27,500
|
6.50
|
13,750
|
8.27
|
|||||||||||||
|
Sep-05
|
Jan
2006 – Mar 2006
|
78,700
|
9.00
|
-
|
-
|
|||||||||||||
|
Mar-05
|
Apr
2006 – Oct 2006
|
42,000
|
4.50
|
21,000
|
7.25
|
|||||||||||||
|
Jul-05
|
Apr
2006 – Oct 2006
|
27,500
|
5.50
|
13,750
|
7.63
|
|||||||||||||
|
Jul-05
|
Nov
2006 – Mar 2007
|
27,500
|
6.00
|
13,750
|
8.40
|
|||||||||||||
|
Feb-06
|
Nov
2006 – Mar 2007
|
60,000
|
6.50
|
-
|
-
|
|||||||||||||
|
Feb-06
|
Apr
2007 – Oct 2007
|
44,000
|
||||||||||||||||