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
|
5.50
|
-
|
-
|
|||||||||||||
|
NYMEX
Based Derivatives - (Appalachian and Michigan Basins)
|
||||||||||||||||||
|
Jan-05
|
Jan
2006 – Mar 2006
|
156,000
|
5.00
|
78,000
|
8.50
|
|||||||||||||
|
Sep-05
|
Jan
2006 – Mar 2006
|
156,000
|
10.50
|
-
|
-
|
|||||||||||||
|
Mar-05
|
Apr
2006 – Oct 2006
|
78,000
|
5.50
|
39,000
|
7.40
|
|||||||||||||
|
Jul-05
|
Apr
2006 – Oct 2006
|
61,000
|
6.25
|
30,000
|
8.98
|
|||||||||||||
|
Jul-05
|
Nov
2006 – Mar 2007
|
68,000
|
7.00
|
34,000
|
9.27
|
|||||||||||||
|
Feb-06
|
Nov
2006 – Mar 2007
|
34,000
|
8.00
|
-
|
-
|
|||||||||||||
|
Feb-06
|
Nov
2006 – Mar 2007
|
34,000
|
8.50
|
34,000
|
13.73
|
|||||||||||||
|
Feb-06
|
Apr
2007 – Oct 2007
|
34,000
|
7.00
|
-
|
-
|
|||||||||||||
|
Feb-06
|
Apr
2007 – Oct 2007
|
34,000
|
7.50
|
34,000
|
10.83
|
|||||||||||||
|
NYMEX
Based Derivatives (NECO)
|
||||||||||||||||||
|
Jan-05
|
Jan
2006 – Mar 2006
|
150,000
|
5.00
|
75,000
|
8.45
|
|||||||||||||
|
Panhandle
Based Derivatives (NECO)
|
||||||||||||||||||
|
Sep-05
|
Jan
2006 – Mar 2006
|
100,000
|
10.00
|
-
|
-
|
|||||||||||||
|
Mar-05
|
Apr
2006 – Oct 2006
|
150,000
|
5.00
|
75,000
|
8.62
|
|||||||||||||
|
Jul-05
|
Nov
2006 – Mar 2007
|
150,000
|
6.50
|
75,000
|
8.56
|
|||||||||||||
|
Feb-06
|
Apr
2007 – Oct 2007
|
60,000
|
6.00
|
-
|
-
|
|||||||||||||
|
Feb-06
|
Apr
2007 – Oct 2007
|
60,000
|
6.50
|
60,000
|
9.80
|
|||||||||||||
Well
Operations and Pipeline Income
Well
operations and pipeline income for the year ended December 31, 2005, were $8.8
million compared to $7.7 million for the year ended December 31, 2004, an
increase of approximately $1.1 million or 14.3%. The increase was due to an
increase in the number of wells and pipeline systems operated by the Company
for
public drilling programs as well as for third parties.
Oil
and Gas Price Risk Management Losses, Net
Oil
and
gas price risk management loss, net for the year ended December 31, 2005, was
$9.4 million compared to approximately $3.1 million for the year ended December
31, 2004, an increase of $6.3 million. For the year ended December 31, 2005,
the
Company recorded unrealized losses of $3 million and realized losses of $6.4
million compared to the year ended December 31, 2004, which is comprised of
unrealized losses of $1.5 million and realized losses of $1.6 million. The
Company’s strategy in its derivative policy is to provide protection on
declining oil and natural gas prices. During 2005, the Company experienced
rising oil and natural gas pricing environment, this trend caused the Company
to
record losses in its derivative transactions. In a declining oil and natural
gas
pricing environment the Company would, in theory, record gains in its derivative
transaction activities. Oil and gas price risk management 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 marketing
activities).
Other
Income
Other
income for the year ended December 31, 2005, was $2.2 million compared to $1.7
million for the year ended December 31, 2004, an increase of $0.5
million.
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, 2005, were $20.4 million compared to $17.7
million for the year ended December 31, 2004, an increase of approximately
$2.7
million or 15.3%. The increase was due to the increased production costs and
severance and property taxes on the increased volumes and higher average sales
prices of natural gas and oil sold, along with the increased number of wells
and
pipelines operated by the Company. Lifting costs per Mcfe increased from a
restated $1.12 per Mcf for the year ended December 31, 2004, to $1.19 per Mcfe
for the year ended December 31, 2005, due to increased severance and property
taxes on the significantly increased oil and gas sales prices along with
additional well workovers and production enhancements work performed.
Exploration
Costs
The
Company drilled eight exploratory wells in 2005 of which five were deemed to
be
dry holes. In the fourth quarter of 2005, four Kansas wells were drilled,
plugged and abandoned for a total combined cost of $0.3 million, including
lease
acreage cost of $0.1 million, was expensed due to impairment. Also in the fourth
quarter, the Coffeepot Springs #24-34 well in Colorado was determined to be
uneconomical at a total dry hole cost of approximately $5.4 million, including
lease acreage cost of $0.1 million, and expensed due to impairment. In the
second quarter of 2005, it was determined the Fox Federal #1-13 well, which
was
drilled in 2004 in Colorado, was also an uneconomic well and total costs of
approximately $5.4 million, including lease acreage cost of $0.4 million, was
expensed due to impairment. These exploratory dry hole expenses were expensed
in
the period in which it was determined that the well was unsuccessful in
accordance with the successful efforts method of accounting. All costs were
incurred 100% by the Company because the drilling fund partnerships did not
participate in these exploratory wells.
General
and Administrative Costs
General
and administrative expenses for the year ended December 31, 2005, increased
to
$7 million compared to $4.5 million for the year ended December 31, 2004, an
increase of approximately $2.5 million or 55.6%. The increase was primarily
due
to increased costs of complying with the various provisions of Sarbanes-Oxley,
in particular Section 404 (Internal Controls), the cost of the Company's
financial statement restatements and increased personnel costs for the increased
number of employees.
Depreciation,
Depletion, and Amortization
Depreciation,
depletion, and amortization costs for the year ended December 31, 2005,
increased to $21.1 million from approximately $18.2 million for the year ended
December 31, 2004, an increase of approximately $2.9 million
or
15.9%.
Such
increase was due to the significantly increased production and investment in
oil
and gas properties by the Company as referred to above.
Gain
on Sale of Leaseholds
For
the
year ended December 31, 2005, the Company recognized a gain on sale of
leaseholds totaling $7.7 million, $6.2 million for the sale to an unaffiliated
entity of undeveloped leases in Garfield County, Colorado and $1.5 million
for
the sale to an unaffiliated party of some Pennsylvania wells. The Company
recognized no gains on the sale of leaseholds in 2004.
Interest
Income
The
increase in interest income from 2004 to 2005 of approximately $0.7 was
primarily attributable to higher average cash balances and higher interest
rates.
Interest
Expense
Interest
expense was relatively unchanged for the year ended December 31, 2005, compared
the year ended December 31, 2004. The Company utilizes its daily cash balances
to reduce its line of credit to lower its cost of borrowing. The average
outstanding debt balances for the year ended December 31, 2005, was $4.1 million
compared to $11.3 million for the year ended December 31, 2004.
Provision
for Income Taxes
The
effective income tax rate for the Company's provision for income taxes decreased
from 37.9% for the year ended December 31, 2004, to 37.3% for the year ended
December 31, 2005, primarily as a result of the domestic production activities
deduction.
Liquidity
and Capital Resources
The
Company funds its operations through a combination of cash flow from operations
and use of the Company's credit facility. Operating cash flow is generated
by
sales of natural gas and oil from the Company's well interests, natural gas
marketing, profits from well drilling and operating activities from the
Company's drilling programs and others, and natural gas gathering and
transportation. Cash payments from Company-sponsored partnerships are used
to
drill and complete wells for the partnerships, with operating cash flow accruing
to the Company to the extent payments exceed drilling costs. The Company
utilizes its revolving credit arrangement to meet the cash flow requirements
of
its operating and investment activities. Management of the Company believes
that
such credit arrangements are adequate to meet its cash and liquidity
requirements.
In
July
2006, the Company sold to an unaffiliated company a portion of its undeveloped
leaseholds in Grand Valley Field, Colorado, for cash proceeds of $353.6 million.
Proceeds in the amount of $300 million were transferred to a qualified
intermediary to be held in trust pursuant to the terms of a "like-kind exchange"
agreement. In January 2007, the Company acquired, in accordance with the
"like-kind exchange" agreement, oil and gas properties totaling $191.5 million.
Following the payment of approximately $20 million in federal taxes, the Company
will have available approximately $90 million in cash to fund 2007 drilling
activities. Approximately $18.6 million, including direct costs of the
acquisition, of the non-designated proceeds was utilized in 2006 to fund the
acquisition of Unioil. The remaining unused portion of the like-kind funds
were
utilized to purchase a variety of other oil and gas properties and to pay down
the outstanding balance of the Company's credit facility.
Natural
Gas Pricing and Pipeline Capacity
The
Company sells natural gas under contracts that are priced based on spot prices
or price indexes that reflect current market prices for the commodity. As a
result, variations in the market are reflected in the revenue the Company
receives. The price of natural gas has varied substantially over short periods
of time in the past, and there is every reason to expect a continuation of
that
variability in the future. During 2006, prices for natural gas decreased from
the last part of 2005 but were still close to record levels, and future
expectations as reflected in NYMEX futures market are for continuing high price
levels for 2007 and beyond. Strong domestic and international demand for energy
and inadequate short term supplies are believed to be key causes of the strong
prices. High prices could encourage the development of new energy sources and
reduced consumption as users find more efficient ways to use energy or
substitute other energy forms. High energy prices could also slow global
economic growth, further reducing demand. As a result, the energy price outlook
could change rapidly from current expectations. Reduced natural gas prices
would
reduce the profitability and cash flow from the Company's gas production
operations.
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 would help to
maintain a balance between supply and demand. However, there may be times in
which oversupply situations occur 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
Pricing
Oil
prices were near or above record levels for most of 2005 and continued through
2006. The Company's oil prices are largely determined by oil prices in the
world
market. Global supply and demand and geopolitical factors are the key
determinants of oil prices. The rapid growth of energy use in developing
countries, most notably China, is driving a rapid increase in worldwide oil
consumption. Higher prices could result in reduced consumption and/or increasing
supplies that could moderate the current high price levels. Over the past
several years, oil has been an increasing part of the Company's production
mix.
As a result, higher oil prices have contributed to the Company's increased
revenue from oil and gas sales more than in the past, and the Company would
suffer a greater impact if oil prices were to decrease. Oil sales accounted
for
33% of the Company's oil and gas sales during 2006 compared to 21.6% in
2005.
Oil
and Gas Derivative Activities
Because
of the uncertainty surrounding natural gas and oil prices, the Company has
used
various derivative instruments to manage some of the impact of fluctuations
in
prices. The Company has in place a series of floors and ceilings on part of
natural gas and oil production, which extend through October 2008. 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 the Company. See the section titled "Oil and Gas Derivative
Activities" as discussed in results of operations for a more detailed analysis
of the Company's current derivative positions.
The
Company uses derivative investments to protect prices for its partners' share
of
production as well as its own production. Actual wellhead prices will vary
based
on local contract conditions, gathering and other costs and factors. The Company
records the fair value of its partners' share of outstanding derivatives and
the
partners' share of the corresponding obligation or benefit in accounts
receivable or other liabilities as appropriate.
The
Company’s derivative transactions do not currently qualify for hedge accounting
under SFAS No. 133. Therefore, the Company records its derivative gains and
losses, both realized and unrealized, through oil and gas price risk management
for its share of production. The Company is required to mark-to-market its
derivative positions at the end of each period and record the adjustment to
the
consolidated statement of income under oil and gas price risk management. This
may and does cause wide variability in profits from period to period. In 2005,
the Company's recognized oil and gas price risk management losses, net of $9.4
million compared to oil and gas price risk management gains, net of $9.1 million
in 2006.
Drilling
Programs
On
September 1, 2006, the Company funded its 2006 partnership, Rockies Region
2006
Limited Partnership, with subscriptions of approximately $90 million. Upon
closing on September 1, 2006, the Company, as managing general partner,
contributed in cash a total of $38.9 million for its contribution to the total
capital of the partnership. After payment of sales commissions and associated
expenses, including a management fee of $1.3 million to the Company, the
partnership had a total of approximately $118 million available for future
drilling. Drilling operations commenced on September 1, 2006, and will continue
through the first quarter of 2007. All of the 2006 partnership's 97 wells have
been drilled as of March 31, 2007.
The
Company invests, as its equity contribution to each drilling partnership, a
sum
equal to approximately 43% of the aggregate subscriptions received in the
current drilling partnership being offered. As a result, the Company is subject
to substantial cash commitments at the closing of each drilling partnership.
No
assurance can be made that the Company will continue to receive this level
of
funding from these or future programs.
Substantially
all of the Company's drilling programs contain a provision allowing investors
to
request that the Company purchase their partnership units. This provision is
in
effect any time beginning with the third anniversary of the first cash
distribution. If investors request that the Company repurchase their units,
the
provision provides that the Company is obligated to purchase an aggregate of
10%
of the initial subscriptions per calendar year (at a minimum price of four
times
the most recent 12 months' cash distributions), subject to the Company's
financial ability to do so. The maximum annual 10% purchase obligation, if
requested by the investors, is currently approximately $12.3 million. The
Company has adequate liquidity to meet this obligation. During 2006, the Company
spent $0.8 million acquiring additional partnership interests under this
provision. As of December 31, 2006, pursuant to this provision, outstanding
purchase offers to investing partners totaled $0.2 million. In 2007, $0.1
million of such outstanding offers were consummated prior to their expiration
on
or before February 28, 2007.
Drilling
Activity
During
2006, the Company, for its own account and on behalf of its drilling fund
partnerships, drilled a total of 118 wells with one developmental dry hole.
The
Company drilled 81 successful wells in its Wattenberg Field in the
Denver-Julesburg Basin and 30 successful wells in the Piceance Basin in western
Colorado. Also in 2006, the Company and its drilling fund partnerships drilled
four wells in North Dakota.
During
2006, the Company drilled several development wells outside of the drilling
fund
partnerships. The Company drilled 34 wells on its northeast Colorado properties
and participated in 10 additional wells which were drilled by joint venture
partners. Of these 44 wells, 41 were successful. The Company also drilled 41
Wattenberg Field wells and 19 Piceance Basin wells for its own account, of
which
58 were successful. The Company also drilled a successful developmental gas
well
in the Michigan Basin. In North Dakota, the Company and other joint venture
partners drilled one successful development well.
In
2006,
the Company included its drilling fund partnerships in its exploratory well
drilling activities by drilling two such wells within the parameters of the
partnership. One well in Wyoming was classified as dry and expensed in
accordance with the successful efforts method of accounting while the other
well
drilled in North Dakota was successful. The Company drilled for its own benefit
one well in North Dakota, as well as participated with other joint venture
partners, outside of the partnerships, in the drilling of six exploratory wells
also in North Dakota, all of which were considered successful.
The
company incurred exploratory dry hole costs of $1.8 million for the year ended
2006, of which $1.3 million was from one well drilled in Wyoming. The remaining
$0.5 million of expenses were incurred on wells previously classified as dry
holes in 2005.
Costs
of Oil and Gas Properties
Costs
incurred by the Company in oil and gas property acquisition, exploration and
development for the year ended December 31, 2006, are presented below (in
thousands):
|
Acquisition
of properties:
|
||||
|
Unproved
properties
|
$ |
11,926
|
||
|
Proved
properties
|
802
|
|||
|
Development
costs
|
114,487
|
|||
|
Exploration
costs
|
20,894
|
|||
|
Total
costs incurred
|
$ |
148,109
|
||
Treasury
Share Purchases
On
January 13, 2006, the Company announced that
its
Board of Directors had authorized the purchase of up to 10% (1,627,500 shares)
of the Company's 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. In October 2006, the Company completed
its
January 2006 program. Total shares purchased 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 have subsequently been retired.
On
October 16, 2006, the Board of Directors of the Company approved a second 2006
purchase program authorizing the Company to purchase up to 10% (1,477,109
shares) of the Company’s then outstanding common stock 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.
Working
Capital
The
Company's working capital as of December 31, 2006, is $29.2
million. The Company manages its working capital needs by only
drawing from its credit facility of $200 million as liabilities come due and
cash is required. At December 31, 2006, the Company had an activated
line of credit with an additional borrowing capacity, in excess of amounts
outstanding, of $18 million.
As
of
December 31, 2006, the Company had $300 million of cash in a “like-kind
exchange” trust, of which $109 million is classified in the consolidated balance
sheet as cash and the remaining $191.5 million is classified as designated
cash,
a non-current asset, as it represents the amount subsequently qualifying for
"like-kind exchange" treatment and used for the acquisition of oil and gas
properties completed in January 2007. At December 31, 2006, the Company has
adequate liquidity when considering these funds along with the credit facility
to meet both its working capital requirements and plans for continued investment
in oil and gas well drilling over the next year.
Long-Term
Debt
The
Company has a credit facility with JPMorgan Chase Bank, N.A. and BNP Paribas
of
$200 million subject to and secured by required levels of oil and gas reserves.
The current borrowing base, based upon oil and gas reserves, is $135 million.
The Company is required to pay a commitment fee of 0.25 to 0.375% per annum
on
the unused portion of the activated credit facility. Interest accrues at an
Alternative Base Rate, as defined in the credit facility or adjusted LIBOR
("London Interbank Market Rate") at the Company's discretion. No principal
payments are required until the credit agreement expires on November 4, 2010.
During March 2007, due to various reporting and processing delays, the Company
requested a waiver related to the Security assignment provisions of its credit
facility. During March 2007, the waiver was granted and the corresponding
Borrowing Base was reduced to $100 million from $135 million. See Note 5 to
the
consolidated financial statements for further information.
On
December 19, 2006, the Company executed pursuant to its credit facility a
short-term, non-revolving overline note in the amount of $20 million to be
repaid on or before January 31, 2007. The note was paid in full on January
31,
2007. Interest on the overline note accrued at a per annum rate equal to the
alternate base rate plus 0.80% until December 22, 2006, at which time the rate
converted to a Eurodollar borrowing for a one month period at a per annum rate
equal to an adjusted LIBOR rate plus 2.30%. The overline note is reflected
on
the consolidated balance sheet as a current liability.
As
of
December 31, 2006 and 2005, the outstanding balances under the facility,
including the overline note, were $137 million and $24 million, respectively.
Any amounts outstanding under the credit facility are secured by substantially
all properties of the Company. The credit agreement requires, among other
things, the existence of satisfactory levels of natural gas reserves and the
maintenance of certain working capital and tangible net worth ratios. At
December 31, 2006, an outstanding balance of $67 million was subject to a prime
interest rate of 8.375%; the overline note in the amount of $20 million was
subject to an interest rate of 9.05% and the remaining outstanding balance
of
$50 million was subject to a LIBOR rate of 7.0%. As previously discussed, the
Company requested and was granted a waiver related to the Security provisions
of
its credit facility. Additionally, the Company requested and was granted a
waiver related to the delay in the delivery of its consolidated financial
statements for the year ended December 31, 2006, and three months ended March
31, 2007, until May 31, 2007, and June 30, 2007, respectively.
Contractual
Obligations and Contingent Commitments
Contractual
obligations and contingent commitments and due dates are as
follows:
|
(in
thousands)
|
Payments
due by period
|
|||||||||||||||||||
|
Contractual
Obligations and Contingent Commitments
|
Total
|
Less
than
1
year
|
1-3
years
|
3-5
years
|
More
than
5
years
|
|||||||||||||||
|
Long-Term
Debt
|
$ |
117,000
|
$ |
-
|
$ |
-
|
$ |
117,000
|
$ |
-
|
||||||||||
|
Operating
Leases
|
2,049
|
502
|
988
|
555
|
4
|
|||||||||||||||
|
Drilling
Obligations (1)
|
28,725
|
11,125
|
17,600
|
-
|
-
|
|||||||||||||||
|
Asset
Retirement Obligations
|
11,966
|
100
|
200
|
200
|
11,466
|
|||||||||||||||
|
Drilling
Rig Commitments
|
36,054
|
12,556
|
21,635
|
1,863
|
-
|
|||||||||||||||
|
Derivative
Agreements (2)
|
2,545
|
2,545
|
-
|
-
|
-
|
|||||||||||||||
|
Other
Liabilities
|
10,371
|
40
|
702
|
4,011
|
5,618
|
|||||||||||||||
|
Total
|
$ |
208,710
|
$ |
26,868
|
$ |
41,125
|
$ |
123,629
|
$ |
17,088
|
||||||||||
|
(1)
|
Represents
the Company's obligations to drill. Failure to drill wells as specified
in
the related agreements will result in the Company having to pay liquidated
damages. A total of $25.6 million is reflected on the consolidated
balance
sheet as a deferred gain on sale of leaseholds. See Note 12 to
consolidated financial statements.
|
| (2) |
Amounts
represent gross liability related to fair value of derivatives. Includes
fair values of derivatives for RNG and PDC's share of oil and gas
production and derivative contracts entered into by the Company on
behalf
of the affiliate partnerships as the managing general partner. The
Company
has a corresponding receivable from the partnerships of $0.1 million
as of
December 31, 2006.
|
Long-term
debt in the above table does not include interest, as interest rates are
variable and principal balances fluctuate significantly from period to period.
The Company continues to pursue capital investment opportunities in producing
natural gas properties as well as its plan to participate in its sponsored
natural gas drilling partnerships, while pursuing opportunities for operating
improvements and cost efficiencies. Management believes that the Company has
adequate capital to meet its operating requirements.
Commitments
and Contingencies
As
managing general partner of 76 partnerships (see Item 1. Business - Drilling
and
Development), the Company has liability for any potential casualty losses in
excess of the partnership assets and insurance. In January 2007, the Company
purchased the remaining working interests in 44 of the 76 partnerships, which
were sponsored by the Company in the late 1980s and 1990s (see Note 16 to the
consolidated financial statements). The Company’s management believes its and
its subcontractors' casualty insurance coverage is adequate to meet this
potential obligation.
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.
Sale
of Undeveloped Leaseholds
In
July
2006, the Company sold to Marathon Oil Company, an unaffiliated company, a
portion of its undeveloped leasehold located in Grand Valley Field, Garfield
County, Colorado. The sale encompassed 100% of the working interest in
approximately 8,700 acres, including approximately 6,400 acres of the Company's
Chevron leasehold and 2,300 acres of the Company's Puckett Land Company
leasehold. The Company retained approximately 475 undeveloped locations on
10
acre spacing on the Grand Valley Field leasehold in addition to all of its
producing properties in the field. The proceeds from the sale were $353.6
million.
The
Company recorded a gain on sale of leaseholds of $328 million and a deferred
gain on sale of leaseholds of $25.6 million. The Company is obligated to either
drill 16 wells on specifically identified acreage over the next three years
(five by December 31, 2007, another five by December 31, 2008, and another
six
by December 31, 2009) or pay liquidated damages of $1.6 million per un-drilled
well. The Company expects to drill the wells for its own benefit and, as such,
will record the costs of the wells drilled in accordance with its oil and gas
properties accounting policy. For each well the Company drills, the Company
will
recognize $1.6 million of the deferred gain when drilling is complete.
Alternatively, should the Company not first drill the wells, the unaffiliated
company has the option to drill the wells for its benefit and, should it decide
to exercise its option, with each well drilled, the Company would recognize
both
$1.6 million of the amount deferred and $0.4 million to be paid to the Company
by the unaffiliated company. At December 31, 2006, $8 million of the deferred
gain on sale of leaseholds is classified as short-term and included in other
current liabilities in the accompanying consolidated balance sheet.
In
conjunction with the sale, the Company entered into a “like-kind exchange”
("LKE") agreement, in accordance with Section 1031 of the Internal Revenue
Code,
with a “qualified intermediary.” Proceeds in the amount of $300 million were
transferred directly to the qualified intermediary to be held in trust pursuant
to the terms of the LKE agreement. The Company had until mid-January 2007 to
close any acquisition of suitable like-kind property, allowing the Company
to
take advantage of the income tax deferral benefits of a LKE transaction. See
below a discussion of the acquisition of suitable like-kind
properties.
Acquisition
of Oil and Gas Properties
Unioil
On
December 6, 2006, the Company completed its cash tender offer and purchased
approximately 95.5%, or 9,112,750 shares, of the outstanding common stock of
Unioil, an independent energy company with properties in northern Colorado
and
southern Wyoming. The acquisition of more than 90% of the outstanding shares
of
common stock allowed the Company to effect a short-form merger of Unioil and
a
wholly owned subsidiary of the Company, resulting in the acquisition of the
remaining 428,719 shares of Unioil. Each share of Unioil common stock not
tendered through the offer was converted into the right to receive $1.91 in
cash, the same consideration paid for shares in the tender offer. The total
price paid for 100% of Unioil’s outstanding common stock was $18.6 million,
including $0.4 million in direct costs of the acquisition. The acquisition
was
accounted for using the purchase method of accounting under SFAS No. 141,
Business
Combinations.
Acquisition
of Section 1031 - LKE Properties
In
January 2007, the Company completed its acquisitions of suitable like-kind
properties in accordance with the LKE agreement it entered into in connection
with its sale of undeveloped leaseholds located in Grand Valley Field, Garfield
Country, Colorado in July 2006. The Company paid cash consideration for the
acquired oil and gas properties totaling $191.5 million, as described below.
EXCO
Resources Inc.
On
January 5, 2007, the Company completed its purchase of EXCO Resources Inc.’s
producing properties and remaining undeveloped drilling locations and acreage
in
the Wattenberg Field area of the DJ Basin, Colorado. The cash consideration
paid
for the EXCO properties was $130.9 million. The acquisition included
substantially all of EXCO’s assets in the area and encompassed 144 oil and gas
wells (approximating 25.5 Bcfe, net of royalty interests, proved developed
reserves as of December 31, 2005) and 8,160 acres of leasehold. The wells and
leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties,
Colorado. The Company will operate the assets and holds a majority working
interest in the properties.
Company-Sponsored
Partnerships.
On
January 10, 2007, the Company completed the purchase of a majority interest
in
44 Company-sponsored partnerships for $58.8 million. This transaction was not
effected pursuant to purchase requests by investor partners (see "Drilling
Programs"). The wells are located in the Appalachian Basin, Michigan, and
Colorado. The transaction resulted in an increase in the Company’s net interest
in 718 wells that are currently operated by the Company.
Other.
The
Company acquired from unaffiliated parties undeveloped leaseholds in Erath
County, Texas for $1.8 million.
Other
Acquisitions
On
February 22, 2007, the Company acquired from an unaffiliated party 28 producing
wells and associated undeveloped acreage located in Colorado (Wattenberg Field)
for a purchase price of $11.8 million. The acquisition encompasses current
daily
production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil
per
day), net to the interests acquired, 100 or more undeveloped drilling locations,
19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable
reserves.
Critical
Accounting Policies and Estimates
The
Company has identified the following policies as critical to business operations
and the understanding of its results of operations. This is not a comprehensive
list of all of the accounting policies. In many cases, the accounting treatment
of a particular transaction is specifically dictated by accounting principles
generally accepted in the United States, with no need for management's judgment
in their application. There are also areas in which management's judgment in
selecting any available alternative would not produce a materially different
result. However, certain of the Company’s accounting policies are particularly
important to the portrayal of its financial position and results of operations
and may require the application of significant judgment by management; as a
result, they are subject to an inherent degree of uncertainty. In applying
those
policies, management uses its judgment to determine the appropriate assumptions
to be used in the determination of certain estimates. Those estimates are based
on historical experience, observation of trends in the industry, and information
available from other outside sources, as appropriate. For a more detailed
discussion on the application of these and other accounting policies, see “Note
1 - Summary of significant accounting policies” in the financial statements and
related notes. The Company’s critical accounting policies and estimates are as
follows:
Principles
of Consolidation
The
accompanying consolidated financial statements include the accounts of Petroleum
Development Corporation and its wholly owned subsidiaries, Riley Natural Gas,
Unioil and PDC
Securities Incorporated. All material intercompany accounts and transactions
have been eliminated in consolidation. The Company accounts for its investment
in interests in oil and gas limited partnerships under the proportionate
consolidation method. Under this method, the Company’s financial statements
include its pro rata share of assets, liabilities and revenues and expenses
respectively of the Company-sponsored limited partnerships in which it
participates. The Company’s proportionate share of all significant transactions
between the Company and the Company-sponsored limited partnerships is
eliminated.
Revenue
Recognition
The
Company's drilling segment recognizes revenue from drilling contracts with
sponsored drilling programs using the percentage of completion method based
upon
the percentage of contract costs incurred to date to the estimated total
contract costs for each contract. The Company utilizes this method since
reasonably dependable estimates of the total estimated costs can be made and
recognized revenues are subject to revisions as a contract progresses, the
term
of which can range from three to twelve months. In addition, the Company offers
its drilling services under two types of contractual arrangements, cost-plus
or
footage-based service contracts, which result in differing risk and reward
relationships and consequently, different revenue reporting policies pursuant
to
Emerging Issues Task Force ("EITF") No. 99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent.
The
first
cost-plus drilling service arrangement was entered into in late 2005, with
drilling activity commencing in the first quarter of 2006. Although the Company
acts overall as a principal in the transaction and takes title to products
and
services acquired necessary for drilling, the Company acts as an agent, with
little risk of loss during the performance of the drilling activities.
Consistent with the provisions of EITF 99-19, the Company’s services provided
under the cost-plus drilling agreements are reported net of recovered costs.
The
Company entered into its second cost-plus drilling arrangement in September
2006
and commenced drilling immediately. It is the Company’s intent that all future
drilling arrangements will be on a cost-plus basis.
Footage-based
contracts provide for the drilling, completion and equipping of wells at
footage
rates and are generally completed within nine to twelve months after the
commencement of drilling. The Company provides geological,
engineering, and drilling supervision on the drilling and completion process
and
uses subcontractors to perform drilling and completion services at a fixed
footage-based rate and accordingly has risk of loss in performing services
under
these arrangements. Accordingly, the Company reports revenue under
these agreements gross of related expenses. Anticipated losses, if
any, on uncompleted contracts are recorded at the time that the estimated
total
costs exceed the estimated total contract revenue. At December 31,
2006 and 2005, the loss contract reserve was $0.3 million and $0.8 million,
respectively.
Natural
gas marketing is reported on the gross accounting method, based on the nature
of
the agreements between RNG, its suppliers and its customers. RNG, the Company’s
marketing subsidiary, purchases gas from many small producers and bundles the
gas together to sell in larger amounts to purchasers of natural gas for a price
advantage. RNG has latitude in establishing price and discretion in supplier
and
purchaser selection. Natural gas marketing revenues and expenses reflect the
full cost and revenue of those transactions because RNG takes title to the
gas
it purchases from the various producers and bears the risks and rewards of
that
ownership. Both the realized and unrealized gains or losses of the RNG commodity
based derivative transactions for natural gas marketing activities are included
in gas sales from marketing activities or cost of gas marketing activities,
as
applicable.
Sales
of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection
of revenue from the sale is reasonably assured and the sales price is fixed
or
determinable. Natural gas is sold by the Company under contracts with terms
ranging from one month to three years. Virtually all of the Company’s contract
pricing provisions are tied to a market index, 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 believes that the pricing provisions of its natural gas
contracts are customary in the industry.
The
Company currently uses the “net-back” method of accounting for transportation
arrangements of natural gas sales. The Company sells gas at the wellhead and
collects a price and recognizes revenues based on the wellhead sales price
since
transportation costs downstream of the wellhead are incurred by its customers
and reflected in the wellhead price.
Sales
of
oil are recognized when persuasive evidence of a sales arrangement exists,
the
oil is verified as produced and is delivered to a purchaser, collection of
revenue from the sale is reasonably assured and the sales price is determinable.
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
at prices and in accordance with arrangements that are customary in the oil
industry.
Well
operations and pipeline income are recognized when persuasive evidence of an
arrangement exists, services have been rendered, collection of revenues is
reasonably assured and the sales price is fixed or determinable. The Company
is
paid a monthly operating fee for each well it operates for outside owners
including the limited partnerships sponsored by the Company. The fee covers
monthly operating and accounting costs, insurance and other recurring costs.
The
Company may also receive additional compensation for special non-recurring
activities, such as reworks and recompletions.
Valuation
of Accounts Receivable
Management
reviews accounts receivable to determine which are doubtful of collection.
In
making the determination of the appropriate allowance for doubtful accounts,
management considers the Company's history of write-offs, customer relationships
and the overall credit worthiness of its customers, and well production data
for
receivables related to well operations.
Accounting
for Derivatives Contracts at Fair Value
The
Company uses derivative instruments to manage its commodity and financial market
risks. Accounting requirements for derivatives and hedging activities are
complex; interpretation of these requirements by standard-setting bodies is
ongoing. The Company currently does not use hedge accounting treatment for
its
derivatives.
Derivatives
are reported on the consolidated balance sheets at fair value. Changes in fair
value of derivatives are recorded in earnings in the consolidated statements
of
income as none of the Company’s derivatives qualified for hedge accounting under
the provisions of SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities.
The
measurement of fair value is based on actively quoted market prices, if
available. Otherwise, the Company seeks indicative price information from
external sources, including broker quotes and industry publications. If pricing
information from external sources is not available, measurement involves
management's judgment and estimates. These estimates are based on valuation
methodologies considered appropriate by the Company's management. For individual
contracts, the use of different assumptions could have a material effect on
the
contract's estimated fair value.
Use
of Estimates in Long-Lived Asset Impairment Testing
Impairment
testing for long-lived assets and intangible assets with definite and indefinite
lives is required when circumstances indicate those assets may be impaired.
In
performing an impairment test, the Company estimates the future cash flows
associated with individual assets or groups of assets. Impairment is recognized
when the undiscounted estimated future cash flows are less than the related
asset's carrying amount. In those circumstances, the asset must be written
down
to its fair value, which, in the absence of market price information, may be
estimated as the present value of its expected future net cash flows, using
an
appropriate discount rate. Although cash flow estimates used by the Company
are
based on the relevant information available at the time the estimates are made,
estimates of future cash flows are, by nature, highly uncertain and may vary
significantly from actual results.
Oil
and Gas Properties
The
Company accounts for its oil and gas properties under the successful efforts
method of accounting. Costs of proved developed producing properties, successful
exploratory wells and development dry hole costs are depreciated or depleted
by
the unit-of-production method based on estimated proved developed producing
oil
and gas reserves. Property acquisition costs are depreciated or depleted on
the
unit-of-production method based on estimated proved oil and gas reserves. The
Company obtains new reserve reports from independent petroleum engineers
annually as of December 31st of each year. The Company adjusts oil and gas
reserves for any major acquisitions, new drilling and divestitures during the
year as needed.
Exploration
costs, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory well drilling costs, including
the
cost of stratigraphic test wells, are initially capitalized but charged to
expense if the well is determined to be nonproductive. The status of each
in-progress well is reviewed quarterly to determine the proper accounting
treatment under the successful efforts method of accounting. Exploratory well
costs continue to be capitalized as long as the well has found a sufficient
quantity of reserves to justify its completion as a producing well, requiring
the Company to assess its reserves and the economic and operating viability
of
wells. If an in-progress exploratory well is found to be unsuccessful (referred
to as a dry hole) prior to the issuance of the financial statements, the costs
are expensed to exploration costs. If management is unable to make a final
determination about the productive status of a well prior to issuance of the
financial statements, the well is classified as “Suspended Well Costs” until
management has had sufficient time to conduct additional completion or testing
operations to evaluate the pertinent geological and engineering data obtained.
At the time when management is able to make a final determination of a well’s
productive status, the well is removed from the suspended well status and the
proper accounting treatment is recorded. The determination of an exploratory
well's ability to produce is made within one year from the completion of
drilling activities.
The
acquisition costs of unproved properties are capitalized when incurred, until
such properties are transferred to proved properties or charged to expense
when
expired, impaired or amortized. Unproved oil and gas properties with
individually significant acquisition costs are periodically assessed, and any
impairment in value is charged to expense. The amount of impairment recognized
on unproved properties which are not individually significant is determined
by
amortizing the costs of such properties within appropriate fields based on
the
Company's historical experience, acquisition dates and average lease terms.
Amortization of remaining lease costs for all other insignificant properties
is
recorded over the average remaining lives of the leases. The valuation of
unproved properties is subjective and requires management of the Company to
make
estimates and assumptions which, with the passage of time, may prove to be
materially different from actual realizable values.
Upon
sale
or retirement of significant portions of or complete fields of depreciable
or
depletable property, the book value thereof, less proceeds or salvage value,
is
credited or charged to income. Upon sale of individual wells, the proceeds
are
credited to property costs.
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. These
estimates of future product prices may differ from current market prices of
oil
and gas. Any downward revisions to management's estimates of future production
or product prices could result in an impairment of the Company's oil and gas
properties in subsequent periods. If net capitalized costs exceed undiscounted
future net cash flows, the measurement of impairment is based on estimated
fair
value which would consider future discounted cash flows.
Deferred
Income Tax Asset Valuation Allowance
Deferred
income tax assets are recognized for deductible temporary differences, net
operating loss carry-forwards, and credit carry-forwards if it is more likely
than not that the tax benefits will be realized. To the extent a deferred tax
asset is not expected to be realized under the preceding criteria, a valuation
allowance has been established. The factors which the Company considers in
assessing whether or not it will realize the value of deferred income tax assets
involve judgments and estimates of both amount and timing, which could differ
from actual results achieved in future periods.
The
judgments used in applying the above policies are based on management's
evaluation of the relevant facts and circumstances as of the date of the
financial statements. Actual results may differ from those estimates.
Evaluation
of Errors
The
Company has historically utilized the "roll-over" method, by which only the
current period effect is considered, of assessing the materiality of
misstatements. In 2006, the Company became subject to the provisions of SEC
Staff Accounting Bulletin (“SAB”) No. 108, and now utilizes the dual method of
assessing materiality - both "roll-over" and "iron curtain" methods, by which
the full reversing effect of cumulative errors is considered each period.
Recent
Accounting Standards
See
Note
1, Summary
of Significant Accounting Policies - Recent Accounting
Standards,
to the
consolidated financial statements.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET
RISK.
Market-Sensitive
Instruments and Risk Management
The
Company's primary market risk exposures are interest rate risk and commodity
price risk. These exposures are discussed in detail below:
Interest
Rate Risk
The
Company's exposure to market risk for changes in interest rates relates
primarily to the Company's interest-bearing cash and cash equivalents,
designated cash and long-term debt. Interest-bearing cash and cash equivalents
includes money market funds, short-term certificates of deposit and checking
and
savings accounts with various banks. The amount of interest-bearing cash and
cash equivalents as of December 31, 2006, is $405.1 million with an average
interest rate of 4.9%. As of December 31, 2006, the Company had long-term debt
of $117 million subject to a prime interest rate of 8.375%. As of December
31,
2006, the outstanding balance under the facility, including the overline note,
was $137 million, of which the overline note in the amount of $20 million was
subject to an interest rate of 9.05%, $67 million was subject to an Alternative
Base Rate, as defined in the credit facility, of 8.375% and the remaining
outstanding balance of $50 million was subject to LIBOR of 7.0%.
Commodity
Price Risk
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
create 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, oversupply situations
may
occur from time to time, which may affect the quantity of and price at which
the
Company can sell its oil and gas. 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 the Company's control.
The
Company utilizes commodity based derivative instruments to manage a portion
of
its exposure to price risk from its oil and natural gas sales and marketing
activities. These instruments consist of NYMEX-traded natural gas futures
contracts and option contracts for Appalachian and Michigan production,
PEPL-based contracts and NYMEX-traded contracts for NECO production and
CIG-based contracts for other Colorado production. These derivative instruments
have the effect of locking in for specified periods (at predetermined prices
or
ranges of prices) the prices the Company will receive for the volume to which
the derivative relates and, in the case of RNG, the cost of gas supplies
purchased for marketing activities. As a result, while these derivatives are
structured to reduce the Company's exposure to changes in price associated
with
the derivative commodity, they also limit the benefit the Company might
otherwise have received from price changes associated with the derivative
commodity. RNG also enters into fixed-price physical purchase and sale
agreements that are derivative contracts. The Company's policy prohibits the
use
of oil and natural gas future and option contracts for speculative
purposes.
The
following tables summarize the open derivative and fixed-price purchase and
sale
contracts for RNG and PDC as of December 31, 2006 and 2005.
Riley
Natural Gas
Open
Derivative Positions
(dollars
in thousands, except average price data)
|
Commodity
|
Type
|
Quantity
Gas-MMbtu
|
Weighted
Average
Price
|
Total
Contract
Amount
|
Fair
Value
|
|||||||||||||
|
Total
Positions as of December 31, 2006
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Purchases
|
246,900
|
$ |
7.34
|
$ |
1,811
|
$ | (304 | ) | |||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Sales
|
1,952,150
|
8.42
|
16,444
|
2,815
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Purchases
|
90,000
|
0.42
|
38
|
(12 | ) | ||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Sales
|
20,000
|
0.50
|
10
|
4
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Option Purchases
|
220,000
|
5.50
|
1,210
|
64
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Option Sales
|
110,000
|
10.10
|
1,111
|
(39 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Purchases
|
1,964,150
|
8.27
|
16,244
|
(1,974 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Sales
|
114,974
|
9.62
|
1,106
|
310
|
|||||||||||||
|
Natural
Gas
|
Physical
Basis Purchases
|
20,000
|
0.45
|
9
|
(3 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Basis Sales
|
90,000
|
0.44
|
39
|
14
|
|||||||||||||
|
Positions
maturing in 12 months following December 31, 2006
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Purchases
|
246,900
|
$ |
7.34
|
$ |
1,811
|
$ | (304 | ) | |||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Sales
|
1,637,150
|
8.37
|
13,697
|
2,637
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Purchases
|
90,000
|
0.42
|
38
|
(12 | ) | ||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Sales
|
20,000
|
0.50
|
10
|
4
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Option Purchases
|
220,000
|
5.50
|
1,210
|
64
|
|||||||||||||
|
Natural
Gas
|
Cash
Settled Option Sales
|
110,000
|
10.10
|
1,111
|
(39 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Purchases
|
1,649,150
|
8.27
|
13,641
|
(2,027 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Sales
|
114,974
|
9.62
|
1,105
|
310
|
|||||||||||||
|
Natural
Gas
|
Physical
Basis Purchases
|
20,000
|
0.45
|
9
|
(3 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Basis Sales
|
90,000
|
0.44
|
39
|
14
|
|||||||||||||
|
Prior
Year Total Positions as of December 31, 2005
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Purchases
|
1,025,500
|
$ |
9.05
|
$ |
9,283
|
$ |
1,983
|
||||||||||
|
Natural
Gas
|
Cash
Settled Futures/Swaps Sales
|
3,149,000
|
7.95
|
25,018
|
(8,689 | ) | ||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Purchases
|
450,000
|
0.91
|
409
|
(158 | ) | ||||||||||||
|
Natural
Gas
|
Cash
Settled Basis Swap Sales
|
240,000
|
0.50
|
120
|
4
|
|||||||||||||
|
Natural
Gas
|
Physical
Purchases
|
2,819,000
|
8.32
|
23,456
|
7,858
|
|||||||||||||
|
Natural
Gas
|
Physical
Sales
|
585,222
|
10.72
|
6,272
|
(670 | ) | ||||||||||||
|
Natural
Gas
|
Physical
Basis Purchases
|
240,000
|
0.45
|
108
|
8
|
|||||||||||||
|
Natural
Gas
|
Physical
Basis Sales
|
450,000
|
0.94
|
420
|
169
|
|||||||||||||
Petroleum
Development Corporation
Open
Derivative Positions
(dollars
in thousands, except average price data)
|
Commodity
|
Type
|
Quantity
Gas-MMbtu
Oil-Barrels
|
Weighted
Average
Price
|
Total
Contract
Amount
|
Fair
Value
|
|||||||||||||
|
Total
Positions as of December 31, 2006
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Option Sales
|
17,390,000
|
$ |
5.56
|
$ |
96,613
|
$ |
12,597
|
||||||||||
|
Natural
Gas
|
Cash
Settled Option Purchases
|
2,155,000
|
10.34
|
22,287
|
(14 | ) | ||||||||||||
|
Oil
|
Cash
Settled Option Purchases
|
300,000
|
50.00
|
15,000
|
155
|
|||||||||||||
|
Positions
maturing in 12 months following December 31, 2006
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Option Sales
|
15,530,000
|
$ |
5.53
|
$ |
85,850
|
$ |
11,682
|
||||||||||
|
Natural
Gas
|
Cash
Settled Option Purchases
|
2,155,000
|
10.34
|
22,287
|
(14 | ) | ||||||||||||
|
Oil
|
Cash
Settled Option Purchases
|
300,000
|
50.00
|
15,000
|
155
|
|||||||||||||
|
Prior
Year Total Positions as of December 31, 2005
|
||||||||||||||||||
|
Natural
Gas
|
Cash
Settled Option Sales
|
5,665,000
|
$ |
8.17
|
$ |
46,273
|
$ | (12,531 | ) | |||||||||
|
Natural
Gas
|
Cash
Settled Option Purchases
|
14,030,000
|
6.36
|
89,210
|
2,660
|
|||||||||||||
In
addition to including the gross assets and liabilities related to the Company's
share of oil and gas production, the above tables and the accompanying
consolidated balance sheets include the gross assets and liabilities related
to
derivative contracts entered into by the Company on behalf of the affiliate
partnerships as the managing general partner. The accompanying consolidated
balance sheets include the fair value of derivatives and a corresponding net
payable to the partnerships of $7.5 million as of December 31, 2006, and a
net
receivable from the partnerships of $5.4 million as of December 31, 2005. In
addition to the short-term fair value of derivatives shown on the accompanying
consolidated balance sheets, there are long-term assets and long-term
liabilities which total to a net long-term asset of approximately $0.9 million
as of December 31, 2006, and which total a net long-term asset of approximately
$1.3 million as of December 31, 2005, respectively, related to the fair value
of
derivatives included in accompanying balance sheets.
By
using
derivative financial instruments to manage exposures to changes in interest
rates and commodity prices, the Company exposes itself to credit risk and market
risk. Credit risk is the failure of the counterparty to perform under the terms
of the derivative contract. When the fair value of a derivative contract is
positive, the counterparty owes the Company, which creates repayment risk.
The
Company minimizes the credit or repayment risk in derivative instruments by
entering into transactions with high-quality counterparties. There were no
counterparty defaults during the years ended December 31, 2006, 2005 and
2004.
The
average NYMEX closing prices for natural gas for the years 2006, 2005 and 2004,
were $7.23 Mmbtu, $8.62 Mmbtu and $6.14 Mmbtu. The average NYMEX closing prices
for oil for the years 2006, 2005 and 2004, were $64.73 bbl, $55.34 bbl and
$41.44 bbl. Future near-term gas prices will be affected by various supply
and
demand factors such as weather, government and environmental regulation and
new
drilling activities within the industry.
Disclosure
of Limitations
Because
the information above incorporates only those exposures that exist at December
31, 2006, it does not consider those exposures or positions which could arise
after that date. As a result, the Company's ultimate realized gain or loss
with
respect to interest rate and commodity price fluctuations will depend on the
exposures that arise during the period, the Company's hedging strategies at
the
time, and interest rates and commodity prices at the time.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
The
response to this Item is set forth herein in a separate section of this Report,
beginning on Page F-1.
Index
to financial statements.
ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM
9A. CONTROLS AND PROCEDURES
|
(1)
|
Evaluation
of Disclosure Controls and Procedures
|
As
of the
end of the period covered by this report, the management of the Company, under
the supervision and with the participation of the Company's Chief Executive
Officer and Chief Financial Officer, carried out an evaluation of the Company's
disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange
Act. Based on that evaluation, the Chief Executive Officer and Chief Financial
Officer concluded that, as of December 31, 2006, the Company's disclosure
controls and procedures were not effective in enabling the Company to record,
process, summarize and report, in a timely manner, the information that the
Company is required to disclose in its Exchange Act reports due to the
existence, at December 31, 2006, of three material weaknesses described below
in
section (2), "Management’s Report on Internal Control over Financial Reporting
."
|
(2)
|
Management’s
Report on Internal Control over Financial
Reporting
|
Management
is responsible for establishing and maintaining adequate internal control
over
financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f)
of the Exchange Act. Internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability
of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject
to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with policies or procedures may
deteriorate.
Management
has assessed the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2006, based upon the criteria established in
“Internal Control - Integrated Framework” issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”). Based on this evaluation,
management concluded that three material weaknesses, which are control
deficiencies, or combinations of control deficiencies, that result in more
than
a remote likelihood that a material misstatement of the annual or interim
financial statements will not be prevented or detected, existed at December
31,
2006. The Company’s assessment, as of December 31, 2006, identified the
following material weaknesses:
|
·
|
The
Company did not have effective policies and procedures to ensure
the
timely reconciliation, review and adjustment of significant balance
sheet
and income statement accounts. As a result, material misstatements
were
identified during the Company's closing process in certain significant
balance sheet and income statement accounts and corrected prior to
the
issuance of the Company’s 2006 consolidated financial statements. This
deficiency resulted in a more than remote likelihood that a material
misstatement of the Company’s annual or interim financial statements would
not be prevented or detected.
|
|
·
|
The
Company did not have effective policies and procedures, or personnel
with
sufficient technical expertise to ensure proper accounting for derivative
instruments. Specifically, the Company’s internal control processes did
not ensure the completeness of all derivative contracts related to
oil and
gas sales, and also did not ensure the determination of the fair
value of
certain derivatives. As a result, misstatements were identified in
the
fair value of derivatives and related income statement accounts and
corrected prior to the issuance of the Company’s 2006 consolidated
financial statements. This deficiency resulted in a more than remote
likelihood that a material misstatement of the Company’s annual or interim
financial statements would not be prevented or
detected.
|
|
|
·
|
The
Company did not have effective policies and procedures to ensure
proper
accounting for oil and gas properties. Specifically, the
Company’s review procedures were not sufficient to ensure that the
calculations of depreciation and depletion were performed accurately
and
that the capitalization of costs was performed in accordance with
the
applicable authoritative accounting guidance. As a result,
misstatements were identified in 2006 in depreciation, depletion
and
amortization expense, and corrected prior to the issuance of the
Company’s
consolidated financial statements. This deficiency resulted in
a more than remote likelihood that a material misstatement of the
Company’s annual or interim financial statements would not be prevented
or
detected.
|
Management
has concluded that, as a result of the material weaknesses noted above, the
Company did not maintain effective internal control over financial reporting
as
of December 31, 2006, based on criteria set forth in the COSO
Framework.
The
Company acquired Unioil on December 6, 2006, and management excluded from its
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2006, Unioil's internal control over financial
reporting associated with total assets of $26.1 million and total revenues
of
$0.3 million included in the consolidated financial statements of the Company
as
of and for the year ended December 31, 2006.
The
Company’s independent registered public accounting firm, KPMG LLP, has issued an
audit report on Management’s assessment of the Company’s internal control over
financial reporting as of December 31, 2006, which is included in this annual
report on Form 10-K
(3) Changes
in Internal Control over Financial Reporting
Changes
in Internal Control over Financial Reporting During the Quarter Ended December
31, 2006
There
have been changes in the Company's internal control over financial reporting
(as
such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange
Act of 1934) during the most recent fiscal quarter that have materially affected
or are reasonably likely to materially affect the Company's internal control
over financial reporting.
During
the fourth quarter of 2006, management completed implementing, documented and
tested internal control over financial reporting which, as noted below, have
allowed management to conclude that there are no longer material weaknesses
in
its accounting for asset retirement obligations, proportionate consolidation
and
income taxes.
Status
of December 31, 2005, Evaluation and Related Material Weaknesses in Internal
Control Over Financial Reporting
In
connection with the preparation of the Company's Annual Report on Form 10-K
for
the year ended December 31, 2005 ("2005 10-K"), an evaluation was completed
under the supervision and with the participation of the Company's management,
including the Chief Executive Officer and the Chief Financial Officer, of
the
effectiveness of the design and operation of the Company's disclosure controls
and procedures (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange
Act). The Company concluded that, as of December 31, 2005, certain
control deficiencies in its internal control over financial reporting
constituted material weaknesses within the meaning of the Public Company
Accounting Oversight Board's Auditing Standard No. 2. Specifically,
deficiencies related to the Company’s accounting for derivatives, oil and gas
properties, asset retirement obligations, proportionate consolidation and
income
taxes were determined to be material weaknesses. Beginning in 2005
and throughout all four fiscal quarters of 2006, management undertook
remediation efforts, described in further detail below, to address and remediate
these material weaknesses, and ultimately remediated three of these material
weaknesses.
The
Company has evaluated remediation efforts initiated to address material
weaknesses identified by the Company - and disclosed in its December 31, 2005,
annual report on Form 10-K as part of management’s evaluation of internal
control over financial reporting, and in its March 31, June 30, and September
30, 2006, quarterly reports on Forms 10-Q, as part of its evaluation of
disclosure controls and procedures in those periods. Based upon that evaluation,
the Company’s Chief Executive Officer and Chief Financial Officer have concluded
that, as of December 31, 2006, the Company no longer has deficiencies in its
internal control over financial reporting which represent material weaknesses
in
its accounting related to asset retirement obligations, proportionate
consolidation and income taxes.
Remediation
Efforts Undertaken to Address and Correct 2005 Material Weaknesses in Internal
Control Over Financial Reporting
In
order
to address and remediate the above-mentioned December 31, 2005 material
weaknesses, the following changes in the Company’s internal control over
financial reporting that have materially affected, or are reasonably likely
to
materially affect, the Company’s internal control over financial reporting were
made during the year ended December 31, 2006, ultimately resulting in management
concluding that three of those material weaknesses have been
corrected:
|
•
|
In
November 2006, the accounting and finance group was reorganized to
include
a new position of Chief Accounting Officer ("CAO"), which reports
directly
to the Chief Financial Officer. The CAO's responsibilities include
the
proper application of generally accepted accounting principles, and
the
supervision of the Company’s Sarbanes-Oxley compliance program. Mr. Darwin
Stump, CPA, formerly the Chief Financial Officer assumed the new
position
of CAO in November 2006.
|
|
·
|
Concurrently,
in November 2006, the Company appointed a new Chief Financial Officer
and
Treasurer, who has significant oil and gas industry and accounting
experience. In addition to his finance responsibilities, the new
Chief
Financial Officer has assumed a leadership role in guiding the Company’s
Sarbanes-Oxley compliance program.
|
|
·
|
Additional
controls and procedures were designed by the Company during 2006
over the
creation and reporting of the Company’s income tax provision and
accounting for other miscellaneous taxes. In addition, in December
2006,
the Company hired a Director of Taxation with significant and relevant
experience with another publicly held company, including the preparation
and review of tax provisions, tax-related disclosures and footnotes
for
financial statement reports and SEC filings. These additional controls
were tested as part of the Company’s year end Sarbanes-Oxley compliance
effort and were determined to be operating effectively by management.
|
|
·
|
During
2006, the Company expanded the size of its financial accounting and
reporting team by hiring professionals with significant and relevant
experience. Specifically, an additional certified public accountant
was
hired in the first quarter of 2006 and two additional certified public
accountants were hired during the second quarter of 2006, including
a
corporate financial reporting director, a partnership financial reporting
director, and an exploration and production (“E&P”) accountant.
|
|
·
|
Continuing
the process begun and reported during 2005, the Company enhanced
its
training program for its financial accounting and reporting team;
formal
training has been conducted during 2005 and 2006, including oil and
gas
accounting and other topics specific to the areas of the Company’s
internal control over financial reporting for which material weaknesses
were reported as of December 31, 2005, and through all four quarters
of
2006.
|
|
·
|
Starting
during the fourth quarter 2005 and continuing through 2006, the Company
subscribed to online accounting research and other accounting technical
resources including GAAP and SEC reporting checklists and has utilized
these resources to assist in the preparation of its financial statements
and SEC filings. Additionally, the online research tool has been
used as a
source of periodic informal training and education in supporting
and
enhancing the technical expertise of the financial accounting and
reporting team. Company finance, accounting and financial reporting
personnel have utilized these resources throughout 2006.
|
|
·
|
The
Company engaged a team of independent, highly experienced advisors
and
consultants, through all fiscal quarters in 2006, to assist with
various
accounting research, projects and monitoring activities. The advisors
and
consultants assist the Company with addressing accounting and reporting
issues including, but not limited to, derivatives, oil and gas activities,
new accounting standards and rules, transaction-specific accounting
issues, SEC reporting and on-going monitoring of changes that may
impact
the Company's application of accounting principles.
|
|
·
|
During
2005 and continuing in 2006, the Company re-evaluated and improved
its
documentation, policies and procedures, and templates with respect
to its
accounting for derivatives, oil and gas property depreciation, depletion
and amortization, proportionate consolidation, asset retirement
obligations and income taxes, and the related disclosures in its
financial
statements. The corrected policies and procedures were employed by
the
Company in the preparation of each of its 2006 periodic financial
statements on Form 10-Q, and in this annual report on Form 10-K.
Senior
management - both operating and financial reporting management -
has
played a significant role in performing appropriate and sufficient
monitoring and review control activities focusing on the appropriate
application of the correct policies and procedures in the Company’s
periodic financial reporting.
|
Report
of Independent Registered Public Accounting Firm
The
Board
of Directors and Shareholders
Petroleum
Development Corporation:
We
have
audited management’s assessment, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting (Item 9A(2)), that Petroleum
Development Corporation and subsidiaries (the Company) did not maintain
effective internal control over financial reporting as of December 31, 2006
because of the effect of the material weaknesses identified in management's
assessment based on criteria established in Internal
Control-Integrated Framework issued
by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The
Company’s management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion
on
management’s assessment and an opinion on the effectiveness of the Company’s
internal control over financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain
to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors
of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
A
material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. Management has identified and included in its assessment the
following material weaknesses as of December 31, 2006:
|
·
|
The
Company did not have effective policies and procedures to ensure
the
timely reconciliation, review and adjustment of significant balance
sheet
and income statement accounts. As a result, material misstatements
were
identified during the Company's closing process in certain significant
balance sheet and income statement accounts of the Company’s 2006
consolidated financial statements. This deficiency resulted in a
more than
remote likelihood that a material misstatement of the Company’s annual or
interim financial statements would not be prevented or
detected.
|
|
·
|
The
Company did not have effective policies and procedures, or personnel
with
sufficient technical expertise to ensure proper accounting for derivative
instruments. Specifically, the Company’s internal control processes did
not ensure the completeness of all derivative contracts related to
oil and
gas sales, and also did not ensure the determination of the fair
value of
certain derivatives. As a result, misstatements were identified in
the
fair value of derivatives and related income statement accounts of
the
Company’s 2006 consolidated financial statements. This deficiency resulted
in a more than remote likelihood that a material misstatement of
the
Company’s annual or interim financial statements would not be prevented or
detected.
|
|
|
·
|
The
Company did not have effective policies and procedures to ensure
proper
accounting for oil and gas properties. Specifically, the
Company’s review procedures were not sufficient to ensure that the
calculations of depreciation and depletion were performed accurately
and
that the capitalization of costs was performed in accordance with
the
applicable authoritative accounting guidance. As a result,
misstatements were identified in 2006 in depreciation, depletion
and
amortization expense of the Company’s consolidated financial
statements. This deficiency resulted in a more than remote
likelihood that a material misstatement of the Company’s annual or interim
financial statements would not be prevented or
detected.
|
In
our
opinion, management’s assessment that Petroleum Development Corporation did not
maintain effective internal control over financial reporting as of December
31,
2006, is fairly stated, in all material respects, based on the criteria
established in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO). Also, in our opinion, because of the effect of the material
weaknesses described above on the achievement of the objectives of the control
criteria, Petroleum Development Corporation did not maintain effective internal
control over financial reporting as of December 31, 2006, based on the criteria
established in Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
The
Company acquired Unioil on December 6, 2006, and management excluded from its
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2006, Unioil’s internal control over financial
reporting associated with total assets of $26.1 million and total revenues
of
$0.3 million included in the consolidated financial statements of the Company
as
of and for the year ended December 31, 2006. Our audit of internal control
over
financial reporting of the Company also excluded an evaluation of the internal
control over financial reporting of Unioil.
We
also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Petroleum
Development Corporation and subsidiaries as of December 31, 2006 and 2005,
and
the related consolidated statements of income, shareholders’ equity and cash
flows for each of the years in the three-year period ended December 31, 2006.
The aforementioned material weaknesses were considered in determining the
nature, timing and extent of audit tests applied in our audit of the 2006
consolidated financial statements, and this report does not affect our report
dated May 22, 2007, which expressed an unqualified opinion on those consolidated
financial statements.
KPMG
LLP
Pittsburgh,
Pennsylvania
May
22,
2007
ITEM
9B. OTHER INFORMATION
None.
PART
III
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
The
executive officers and directors of the Company, their principal occupations
for
the past five years and additional information is set forth below.
|
Name
|
Age
|
Position(s)
|
Director
Since
|
Directorship
Term
Expires
|
||||
|
Steven
R. Williams
|
56
|
Chairman,
Chief Executive Officer and Director
|
1983
|
2009
|
||||
|
Thomas
E. Riley
|
54
|
President
and Director
|
2004
|
2007
|
||||
|
Richard
W. McCullough
|
55
|
Chief
Financial Officer and Treasurer
|
-
|
-
|
||||
|
Darwin
L. Stump
|
52
|
Chief
Accounting Officer
|
-
|
-
|
||||
|
Eric
R. Stearns
|
49
|
Executive
Vice President, Exploration and Production
|
-
|
-
|
||||
|
Vincent
F. D'Annunzio
|
54
|
Director
|
1989
|
2007
|
||||
|
Jeffrey
C. Swoveland
|
52
|
Director
|
1991
|
2008
|
||||
|
Kimberly
Luff Wakim
|
49
|
Director
|
2003
|
2009
|
||||
|
David
C. Parke
|
40
|
Director
|
2003
|
2008
|
||||
|
Anthony
J. Crisafio
|
54
|
Director
|
2006
|
2009
|
Steven
R. Williams
was
elected Chairman and Chief Executive Officer in January 2004. Mr. Williams
served as President from March 1983 until December 2004 and has been a Director
of the Company since 1983.
Thomas
E. Riley
was
elected Director in January 2004 by the Board of Directors and assumed the
position of President in December 2004. Previously Mr. Riley was appointed
Executive Vice President of Production, Natural Gas Marketing and Business
Development in November 2003. Prior thereto, Mr. Riley served as Vice President
Gas Marketing and Acquisitions of the Company since April 1996. Prior to joining
the Company, Mr. Riley was president of Riley Natural Gas Company, a natural
gas
marketing company which the Company acquired in April 1996.
Richard
W. McCullough
was
appointed Chief Financial Officer and Treasurer in November 2006. Prior to
joining the Company, Mr. McCullough served as president and chief executive
officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas
supplies. From 2001 to 2003, Mr. McCullough served as an investment banker
with
J.P. Morgan Securities, Atlanta, Georgia, and served in the public finance
utility group supporting bankers nationally in all natural gas matters.
Additionally, Mr. McCullough has held senior positions with Progress Energy,
Deloitte and Touche, and the Municipal Gas Authority of Georgia. Mr. McCullough,
a CPA, was a practicing certified public accountant for eight
years.
Darwin
L. Stump
was
appointed Chief Accounting Officer in November 2006. Mr. Stump has been an
officer of the Company since April 1995 and held the position of Chief Financial
Officer and Treasurer from 2003 until November 2006. Previously, Mr. Stump
served as Corporate Controller from 1980 until November 2003. Mr. Stump, a
CPA,
was a senior accountant with Main Hurdman, Certified Public Accountants prior
to
joining the Company.
Eric
R. Stearns
was
appointed Executive Vice President of Exploration and Production in December
2004. Prior to his current position, Mr. Stearns was Executive Vice President
of
Exploration and Development since November 2003, having previously served as
Vice President of Exploration and Development since April 1995. Mr. Stearns
joined the Company as a geologist in 1985 after working for Hywell, Incorporated
and for Petroleum Consultants.
Vincent
F. D'Annunzio
has
served as president of Beverage Distributors, Inc. located in Clarksburg, West
Virginia since 1985.
Jeffrey
C. Swoveland
has
served as chief financial officer of Body Media, a life-science company
specializing in the design and development of wearable body monitoring products
and services, since September, 2000. Prior thereto, Mr. Swoveland held various
positions, including vice president of finance, treasurer and interim chief
financial officer, with Equitable Resources, Inc., a diversified natural gas
company, from 1997 to September 2000. Mr. Swoveland serves as a member of the
board of directors of Linn Energy, LLC, a public, independent natural gas and
oil company.
Kimberly
Luff Wakim,
an
Attorney and Certified Public Accountant, is a partner with the law firm Thorp,
Reed & Armstrong LLP. Ms. Wakim joined Thorp Reed & Armstrong LLP in
1990.
David
C. Parke
is a
managing director in the investment banking group of Boenning & Scattergood,
Inc., West Conshohocken, Pennsylvania, a full-service investment banking firm.
Prior to joining Boenning & Scattergood in November 2006, he was a director
with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an
investment banking firm, from October 2003 to November 2006. From 1992 through
2003, Mr. Parke was director of corporate finance of Investec, Inc., and its
predecessor Pennsylvania Merchant Group Ltd., investment banking companies.
Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate
finance departments of Wheat First Butcher & Singer, now part of Wachovia
Securities, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke serves
as a member of the board of directors of Zunicom, Inc., a public company
providing business communication services to the hospitality
industry.
Anthony
J. Crisafio
was
elected to the Board in October 2006. Mr. Crisafio, a certified public
accountant, serves as an independent business consultant, providing financial
and operational advice to businesses and has done so since 1995. He owned two
small businesses during the period of 1991 to 2002. Additionally, Mr. Crisafio
has served as the chief operating officer of Cinema World, Inc. from 1989 until
1993 and was a partner with Ernst & Young from 1986 until 1989.
Corporate
Governance
In
January 2005, the Company adopted Corporate Governance Guidelines to promote
the
effective functioning of its Board of Directors and related
committees.
Board
of Directors
The
Company's By-Laws provide that the number of members of the Board of Directors
("Board") shall be designated from time to time by a resolution of the Board
and, in absence of such designation, the number of directors shall be seven.
The
Board shall be divided into three separate classes of directors which are
required to be as nearly equal in number as practicable. At each annual meeting
of stockholders one class of directors, whose term expires, will be elected
to a
term of three years. The classes are staggered so that the term of one class
expires each year. There is no family relationship between any director or
executive officer and any other director or executive officer of the Company.
There are no arrangements or understandings between any director or officer
and
any other person pursuant to which the person was selected as an
officer.
Director
Independence
The
Company has determined that all of its directors, other than Messrs. Williams
and Riley, are independent under NASDAQ Marketplace Rule 4200 and the Exchange
Act.
Committees
of the Board
The
following table identifies the current membership and chair of the five standing
committees of the Board:.
|
Name
|
Audit
|
Compensation
|
Executive
|
Nominating/
Corporate
Governance
|
Planning/
Finance
|
|||||
|
Jeffrey
C. Swoveland
|
Chair
|
-
|
Member
|
-
|
Member
|
|||||
|
Kimberly
Luff Wakim
|
Member
|
-
|
-
|
Member
|
-
|
|||||
|
Vincent
F. D'Annunzio
|
-
|
Member
|
Member
|
Chair
|
-
|
|||||
|
David
C. Parke
|
Member
|
Chair
|
-
|
Member
|
Chair
|
|||||
|
Anthony
J. Crisafio
|
Member
|
Member
|
-
|
-
|
-
|
|||||
|
Steven
R. Williams
|
-
|
-
|
Chair
|
-
|
-
|
|||||
|
Thomas
E. Riley
|
-
|
-
|
Member
|
-
|
Member
|
The
Audit
Committee of the Board is comprised entirely of persons whom the Board has
determined to be independent under NASDAQ Rule 4200(a)(15). Mr. Swoveland chairs
the committee; other audit committee members are Ms. Wakim, Mr. Parke and Mr.
Crisafio. The Board has determined that Mr. Swoveland and the other Audit
Committee members, with the exception of Mr. Parke, qualify as audit committee
financial experts as defined by SEC regulations and are all, without exception,
independent of management. The audit committee’s purpose is to assist the Board
in monitoring the integrity of the financial reporting process, systems of
internal controls and financial statements of the Company, and compliance by
the
Company with legal and regulatory requirements. Additionally, the committee
is
directly responsible for the appointment, compensation and oversight of the
independent auditors employed by the Company for the purpose of preparing or
issuing an audit report or related work and to assess the need for an internal
audit function and recommend its establishment when deemed appropriate.
The
independent directors conduct meetings ("executive sessions") without the
presence of management at each scheduled Board meeting. Mr. Swoveland serves
as
Presiding Independent Director of the Board.
Communications
with Directors
Shareholders
wishing to communicate with the Board or a committee may do so by writing to
the
attention of the Board or Committee at the corporate headquarters or by emailing
the Board at board@petd.com, with "Board" or appropriate committee in the
subject line.
Code
of Ethics
In
January 2003, the Company adopted its Code of Business Conduct and Ethics,
as
amended (the “Code of Conduct”) applicable to all directors, officers,
employees, agents and representatives of the Company and consultants. The
Company's principal executive officer, principal financial officer and principal
accounting officer are subject to additional specific provisions under the
Code
of Conduct. The Company's Code of Conduct is posted on its website at
www.petd.com. In the event of an amendment to, or a waiver of, including an
implicit waiver, the Code of Conduct, the Company will disclose the information
on its internet website.
Section
16(a) Beneficial Ownership Reporting Compliance
Section
16(a) of the Exchange Act requires the Company's officers and directors, and
persons who own more than 10% of a Company's equity securities, to file reports
of ownership and changes in ownership with the Securities and Exchange
Commission. Officers, directors and holders of more than 10% of the Common
Stock
are required by regulations promulgated by the Commission pursuant to the
Exchange Act to furnish the Company with copies of all Section 16(a) forms
they
file. The Company assists officers and directors, and will assist beneficial
owners, if any, of more than 10% of the Common Stock, in complying with the
reporting requirements of Section 16(a) of the Exchange Act.
Based
solely on its review of the copies of such forms received by it, the Company
believes that since January 1, 2006, all Section 16(a) filing requirements
applicable to its directors, officers and greater than 10% beneficial owners
were met.
ITEM
11. EXECUTIVE COMPENSATION
EXECUTIVE
COMPENSATION
Compensation
Discussion and Analysis
The
Compensation Committee of the Board of Directors ("Board") of Petroleum
Development Corporation (the “Committee”), which consists of three independent
Board members, developed and recommended for Board approval the compensation
program for 2006 for the Chief Executive Officer ("CEO") and the other executive
officers listed in the “2006 Summary Compensation Table” (collectively, the
"named executive officers" or "executive officers") appearing below. The
Committee’s recommendations of compensation for the executive officers were
approved by the Board. For 2007 executive compensation, the Board authorized
the
Committee to make final determinations for all elements of compensation for
the
executive officers, which the Committee did after reviewing its proposals with
all other independent board members who are not part of the Committee. The
Committee also negotiates terms of employment agreements with the executive
officers. Prior to determining executive compensation, the Compensation
Committee consults with the CEO for his evaluation of performance and
recommendation for compensation of the other executive officers.
The
Compensation Committee utilized the compensation consulting service of Towers
Perrin ("Consultant") in recent years. Over the past 18 months, the Consultant:
conducted a competitive benchmarking of the Company's executive and non-employee
director compensation programs, helped the Committee in its redesign of the
Long-Term Incentive ("LTI") program in 2007 as described below, and led an
educational session focused on new SEC pay disclosure rules. The Consultant
also
assisted the Company with the design of a retention-based stock plan for
non-officers. The Committee periodically assesses the effectiveness and
competitiveness of the Company’s executive compensation structure with the
assistance of the Consultant, and utilizes the assistance of the Consultant
in
assessing the value and cost of various proposed compensation arrangements.
The
Consultant is engaged by, and reports directly to, the Committee.
Compensation
Philosophy
The
Committee considers many factors in establishing the compensation packages
for
the executive officers of the Company. The ultimate goal is to provide
compensation that is fair to both the Company and the executive officers, that
motivates behavior that will enhance the value of the Company, that avoids
encouraging behavior that does not serve the best interests of the Company
and
that will allow the Company to attract and retain executive
officers.
Objectives
of Compensation Program
The
Committee’s philosophy is to provide compensation packages that will attract,
motivate and retain executive talent and deliver rewards for superior
performance and consequences for underperformance. Specifically, the objectives
of the Committee’s executive compensation practices are to:
|
·
|
Offer
a total compensation program that is competitive with the compensation
practices of those peer companies with which the Company competes
for
talent;
|
|
·
|
Tie
a significant portion of executive compensation to the Company’s
achievement of pre-established financial and operating objectives
and to
personal objectives established for each executive
individually;
|
|
·
|
Provide
a significant portion of overall compensation in the form of equity-based
compensation in order to align the interests of the Company’s executives
with those of the Company’s shareholders;
and
|
|
·
|
Structure
a significant proportion of total compensation in a fashion that
promotes
executive retention.
|
The
Committee seeks to attract executive talent by offering competitive base
salaries, annual performance incentive opportunities under the Company’s
Short-Term Incentive (“STI”) program and the potential for long-term rewards
under the Company’s equity-based LTI program. The Committee believes that to
attract and retain a highly-skilled executive team, the Company’s compensation
practices must be competitive with those of other employers with which the
Company competes for talent.
Pay-for-Performance
The
Committee believes that significant portions of executive compensation should
be
closely linked to both the Company’s and the individual’s performance. The
Committee’s pay-for-performance philosophy is reflected in the Company’s
compensation practices, which tie a significant portion of executive
compensation to the achievement of financial and operating objectives of the
Company and also to take into account personal objectives and performance.
The
Committee believes that using solely financial objectives could unduly reward
or
punish executives for financial performance resulting from issues beyond the
executive’s control, such as changes in energy prices. On the other hand using
solely operating measures could result in compensation practices that did not
align the executive’s interests with those of the shareholders. As a result, the
Committee has chosen to use a combination of financial and operating measures
as
determinants for STI compensation. This philosophy is reflected in annual
incentive awards, which are directly linked to the achievement of short-term
financial and operating objectives, set by the Committee and have potential
payouts ranging from zero to 200% of target for each of the three components.
During 2006, the targets were increases in diluted earnings per share, increases
in production, and the Committee’s assessment of other factors related to the
individual’s performance and development. The following table summarized the
criteria used in determining the bonus amount.
|
Criteria
|
Lower
Threshold
Amount
|
Target
Bonus
|
Maximum
Bonus
|
Percent
of
Total
Maximum
Bonus
|
||||||||||||
|
Production
increase based on Mcfe
|
6 | % | 10 | % | 14 | % | 40 | % | ||||||||
|
Diluted
earnings per share
|
$ |
2.42
|
$ |
2.66
|
$ |
3.03
|
30 | % | ||||||||
|
Discretionary
evaluation
|
Compensation
Committee Determination
|
30 | % | |||||||||||||
The
Committee also ties compensation to performance through equity-based LTI awards
that are designed to motivate executives to meet the Company’s long-term
performance goals and to tie their interests to those of the shareholders.
In
2006, the LTI awards consisted of restricted stock and stock options that vest
25% per year over a period of four years. For 2007, all of the LTI awards are
restricted stock, a portion of which vest over time. The balance of the
restricted stock awards will be long-term incentive performance shares (“LTIP
shares”). The LTIP shares will vest only if certain minimum thresholds of stock
price appreciation are met. One-half of the LTIP shares will vest and be issued
based upon an annual stock price increase of approximately 12%. An additional
25% of the awarded LTIP shares will vest and be issued at annualized increased
hurdles of 16% and an additional 25% at 20%. The stock price will be measured
based on the average daily closing price for each of the three monthly periods:
December 2009, 2010 and 2011. Any shares not vested in 2009 or 2010 will remain
eligible to be vested in future years; however, any unvested shares at December
31, 2011 will be forfeited. The Committee decided to use three measurement
dates
to take into account the volatility of energy prices and their impact on the
stock price of the Company.
As
a
result of the structure of the STI and LTI compensation, a significant amount
of
variable compensation under the Company’s compensation program is contingent on
the achievement of key financial and operating objectives of the Company and
on
increasing the value of the shares of the Company’s stock.
For
2006,
30% of the Company’s STI compensation program also accounts for individual
performance through individual objectives and evaluation of individual executive
performance by the Committee, which enables the Committee to differentiate
among
executives and emphasize the link between personal performance and compensation.
For 2007, 100% of Mr. Stump's STI is discretionary and for the other executive
officers, their STI performance based award percentages remain unchanged from
2006.
The
Role of Equity-Based Compensation
The
Company’s LTI program is an integral part of the Company’s overall executive
compensation program. The LTI program is intended to serve a number of
objectives. These include aligning the interests of executives with those of
the
Company’s shareholders, and focusing senior executives on the achievement of
well-defined, long-term performance objectives that are aligned with the
Company’s corporate strategy, thereby establishing a direct relationship between
compensation and shareholder value. The program also furthers the goal of
executive retention, since the executive officer will forfeit any unvested
awards in the event the officer voluntarily terminates employment with the
Company without "good reason."
In
making
long-term incentive awards, the Committee uses a pre-determined market-based
value approach. The Committee determines the dollar value of awards in the
marketplace using a valuation methodology. The Committee establishes the desired
dollar value for each executive officer relative to the market. The
corresponding number of equity instruments to be awarded is then determined
using the same valuation methodology, based on prevailing factors in advance
of
the award date. The valuation for financial statement purposes is subsequently
re-calculated based on the prevailing factors at the time of the
award.
The
value-based approach can cause the number of equity instruments needed to be
granted from year to year to vary, even though the awards may have the same
dollar value. This can be caused by, among other things, fluctuations in the
Company’s common stock price at the time of grant. This issue is further
addressed in the Long-Term Incentives section.
Use
of Benchmarking to Establish Target Compensation Levels
In
furtherance of its compensation objectives, the Committee compared the Company’s
compensation levels with those of a group of 14 companies in 2006, and 15
companies in 2007, in setting compensation targets. These groups, collectively,
are referred to as the “Peer Group.” This benchmarking is done with respect to
each of the key elements of the Company’s executive compensation programs
discussed above (salary, STI and LTI compensation), as well as the compensation
of individual executives based on their position in the overall compensation
hierarchy. The Committee uses data from the Peer Group to establish a dollar
target level for each key element to deliver compensation to each executive
at
approximately the 50th percentile of the Peer Group, with adjustments made
based
on the executive’s individual performance. Targeting the 50th percentile helps
ensure that the Company’s compensation practices will be competitive in terms of
attracting and retaining executive talent, while performance based compensation
provides for variations due to superior or sub-par performance. Because
compensation for the Peer Group is for prior periods, the Committee attempts
to
anticipate future movements in compensation levels when it sets compensation
targets. For example, when setting compensation for 2006, the most recent
compensation information available was from the 2005 proxy statements for
compensation paid in 2004. As more up to date information becomes available,
it
is reviewed by the Committee to evaluate whether future compensation plans
should be adjusted to take unanticipated changes in actual compensation of
the
Peer Group into account.
The
2006
Peer Group was comprised of the following companies:
|
•
Unit Corporation
|
•
St. Mary Land & Exploration Company
|
•
Cabot Oil & Gas Corporation
|
||
|
•
Penn Virginia Corporation
|
•
Whiting Petroleum Corporation
|
•
Range Resources Corporation
|
||
|
•
Encore Acquisition Company
|
•
Berry Petroleum Company
|
•
KCS Energy Incorporated
|
||
|
•
Quicksilver Resources Inc
|
•
Clayton Williams Energy Incorporated
|
•
Brigham Exploration Company
|
||
|
•
Magnum Hunter Resources Incorporated
|
•
Cimarex Energy Company
|
For
2007,
Forest Oil Corporation, Comstock Resources Incorporated and Bill Barrett
Corporation were added to the Peer Group. Cimarex acquired Magnum Hunter in
2005
and these companies were removed from the Peer Group as they were no longer
comparable due to size. The Committee believes that the Peer Group represents
companies with similar operations, of similar complexity, and with which the
Company believes it competes for executive talent.
Review
of Overall Compensation
The
Committee reviews for each of the executive officers the total dollar value
of
the officer’s annual compensation, including salary, STI, LTI compensation,
perquisites, deferred compensation accruals and other compensation. The
Committee also reviews shareholdings and accumulated unrealized gains under
prior equity-based compensation awards, and amounts payable to the executive
officer upon termination of the executive’s employment under various different
circumstances, including retirement and termination in connection with a change
in control. See 2006 Summary Compensation Table below.
Consideration
of Prior Compensation
While
the
Committee considers all compensation previously paid to the executive officers,
including amounts realized or realizable under prior equity-based compensation
awards, the Committee believes that current compensation practices must be
competitive to retain the executives in light of prevailing market practices
and
to motivate the future performance of the executive officers. Accordingly,
wealth accumulation through superior past performance of the Company should
not
be punished through reductions in current compensation levels.
Elements
of Executive Compensation
To
accomplish the objectives of the executive compensation program, the Committee
uses four elements of compensation in varying proportions for the different
executive officers. These elements are base salary, STI, LTI, and other
benefits. The Committee uses cash payments (base salary and STI), awards tied
to
the Company's stock (LTI, which we also refer to as “equity-based compensation”)
and non-cash benefits in its overall compensation packages. The Committee
balances salary and performance-based compensation, and cash and non-cash
compensation, in a manner it believes best serves the objectives of the
Company’s compensation program. The Committee allocates among the different
elements of compensation in a manner similar to the median allocation of the
Peer Group, based on the level of the executive's position. Generally, it is
the
policy of the Committee that, as income levels increase, a greater proportion
of
the executive’s income should be in the form of STI and LTI compensation. For
example the CEO of the Company receives a higher percentage of his compensation
in the form of short and long term incentives compared to other executives,
as
is the case of CEOs in the Peer Group. The following table shows the breakdown
of target compensation among the three elements for 2006 and 2007 for each
executive officer.
Target
Compensation for Elements
as
a
Percentage of Total Target Compensation
|
2006
|
2007
|
|||||||||||||||||||||||
|
Name
|
Base
Salary
|
Bonus
Target
|
Equity
Target
|
Base
Salary
|
Bonus
Target
|
Equity
Target
|
||||||||||||||||||
|
Steven
R. Williams
|
31 | % | 23 | % | 46 | % | 33 | % | 24 | % | 43 | % | ||||||||||||
|
Thomas
E. Riley
|
36 | % | 18 | % | 46 | % | 36 | % | 22 | % | 42 | % | ||||||||||||
|
Eric
R. Stearns
|
37 | % | 19 | % | 44 | % | 36 | % | 23 | % | 41 | % | ||||||||||||
|
Richard
W. McCullough(1)
|
-
|
-
|
-
|
40 | % | 20 | % | 40 | % | |||||||||||||||
|
Darwin
L. Stump
|
39 | % | 19 | % | 42 | % | 44 | % | 22 | % | 34 | % | ||||||||||||
_______________
| (1) |
Mr.
McCullough was appointed as CFO in November 2006. The initial contract
period runs through 2008.
|
Base
Salary
The
Committee annually reviews the base salaries of the Chief Executive Officer
(“CEO”) and other executive officers. Salaries are also reviewed in the case of
promotions or other significant changes in responsibilities. In each case,
the
Committee takes into account the results achieved by the executive, his or
her
future potential, scope of responsibilities and experience, and competitive
salary practices of the Peer Group. Base salary is intended to provide a
baseline of compensation that is not contingent upon the Company’s performance.
After
reviewing the Peer Group salary levels and considering individual performance,
the Committee established Base Salary increases for 2006 of 8.5% for the CEO,
and between 5% and 8.7% for the other executive officers. The total compensation
of the executive officers approximated the mean of the Peer Group, although
the
spread between the highest and lowest is less than the Peer Group. This is
consistent throughout the elements of compensation, and reflects the goal of
the
Committee to encourage a strong team among the executive officers. For 2007,
the
Committee established Base Salary increases of 7.2% for the CEO, and between
0%
and 8.2% for the other executive officers. Mr. McCullough, the Company’s CFO,
will receive the compensation established in his employment contract, executed
in November 2006. Annual base salaries for the executive officers for 2006
and
2007 are shown in the following table:
|
Annual
Base Salaries
|
||||||||
|
Name
|
2006
|
2007
|
||||||
|
Steven
R. Williams
|
$ |
345,000
|
$ |
370,000
|
||||
|
Thomas
E. Riley
|
272,000
|
292,500
|
||||||
|
Eric
R. Stearns
|
251,000
|
271,500
|
||||||
|
Richard
W. McCullough
|
-
|
235,000
|
||||||
|
Darwin
L. Stump
|
220,500
|
220,500
|
||||||
Short-Term
Incentives
Annual
STI are tied to the Company’s overall performance for the fiscal year, as
measured against objective criteria set by the Committee, as well as the
Committee’s assessment of individual performance of each executive. For 2006, at
least 70% of the target STI payments are performance based awards measured
against objective criteria established early in the fiscal year. The remainder
may include additional awards based on performance goals, or may be awarded
at
the discretion of the Committee based on its assessment of the executive’s
performance. For 2007, 100% of Mr. Stump's STI is discretionary and for the
other executive officers, their STI performance based award percentages remain
unchanged from 2006. The Compensation Committee has decided to maintain
discretion over STI bonus amounts for Mr. Stump to emphasize the focus of his
role in 2007 on the continued development of the accounting functions of the
Company rather than on production targets and overall financial performance.
The
Committee, comprised entirely of independent directors, believes that some
discretion with respect to individual awards is desirable to compensate for
unusual and unexpected events.
Target
STI payments, expressed as a percentage of base salary, are set for each
executive officer prior to the beginning of the fiscal year based on job
responsibilities. STI payments for the year may range from zero up to 150%
of
the executive officer’s base salary, based on the achievement of the objective
criteria for performance based payments and the assessment by the Committee
for
individual goals. For fiscal year 2006 and again in 2007, target STI awards
for
the executive officers ranged from 50% to 75% of salary.
With
respect to the executive officers, the Committee establishes formulae to
determine the percentage of the target annual incentive payment that may be
payable for the fiscal year. The Committee does not have the discretion to
change any objective criteria once they have been established. However, the
Committee does retain discretion over 30% (in 2007, 100% for Mr. Stump) of
the
total target STI to allow some flexibility to award superior, or reflect the
effect of sub-par, personal performance that may not be captured by the
financial and operating criteria. In addition, the Committee has the authority
to recommend to the Board compensation for unusual events. In 2006, Eric
Stearns, the Executive Vice President of Exploration and Production, received
a
special bonus for his key role in the $354 million acreage sale to Marathon.
The
following table sets forth the STI threshold, target and maximum levels for
2006
and 2007 for the executives expressed as a percentage of base
salary.
|
Short-Term
Incentive Compensation
|
||||||||||||||||||||||||
|
2006
|
2007(1)
|
|||||||||||||||||||||||
|
%
of Base Salary
|
%
of Base Salary
|
|||||||||||||||||||||||
|
Name
|
Threshold
|
Target
|
Stretch
|
Threshold
|
Target
|
Stretch
|
||||||||||||||||||
|
Steven
R. Williams
|
0 | % | 75 | % | 150 | % | 0 | % | 75 | % | 150 | % | ||||||||||||
|
Thomas
E. Riley
|
0 | % | 50 | % | 100 | % | 0 | % | 62.5 | % | 125 | % | ||||||||||||
|
Eric
R. Stearns
|
0 | % | 50 | % | 100 | % | 0 | % | 62.5 | % | 125 | % | ||||||||||||
|
Richard
W. McCullough (2)
|
- | - | - | 0 | % | 50 | % | 100 | % | |||||||||||||||
|
Darwin
L. Stump
|
0 | % | 50 | % | 100 | % |
-
|
-
|
-
|
|||||||||||||||
_______________
| (1) |
In
2007, the target percentages apply to Messrs. Williams, Riley, Stearns
and
McCullough. For Mr. Stump, 100% of his STI is
discretionary.
|
|
(2)
|
Mr.
McCullough was appointed as CFO in November 2006. The initial contract
period runs through 2008.
|
Long-Term
Incentives
Historically,
the primary form of equity compensation awarded by the Company was qualified
and
non-qualified stock options. This form was selected because of the favorable
individual and corporate accounting and tax treatments provided by the
accounting and tax rules prevalent at the time, and the widespread use of stock
options in executive compensation. In 2004, the Committee began utilizing a
combination of restricted stock and options for executive compensation,
believing that the restricted stock was better appreciated by employees and
resulted in less dilution for the Shareholders. Beginning in 2006, the
accounting treatment for stock options changed as a result of the applicability
of Statement of Financial Accounting Standards No. 123(R), making the use of
stock options less attractive. As a result, the Committee assessed the
desirability of granting only shares of restricted stock to executives, and
concluded that shifting entirely to restricted stock would provide an equally
motivating form of incentive compensation, while permitting the issuance of
fewer shares, thereby reducing potential dilution to other shareholders. The
Committee did want to tie the value received by executives to performance for
a
portion of the equity compensation, thereby providing executives with a greater
incentive to focus on the long-term appreciation of the stock. To accomplish
this, a portion of the LTI for each executive consists of LTI performance shares
(“LTIP shares”), which require both the passage of time and specified increases
in the stock price to become vested.
The
Committee’s practice has been to determine the dollar amount of equity
compensation and to then grant a number of shares of restricted stock and
options that have a fair value equal to that amount on the date of grant. The
2007 awards were determined using the fair value of the awards based on the
average daily closing price of the Company's stock in December 2006. The
Consultant calculated the fair value utilizing methods they have developed
for
use with these types of equity valuations, including taking into account the
probability and/or timing of vesting under the performance criteria for the
LTIP
shares and the other restricted stock. For the purpose of recording an expense
for financial reporting purposes, the awards will be revalued based on the
prevailing capital markets factors at the time of the award.
In
April
2007, the Company corrected an administrative error in the stock option exercise
price of shares awarded the executive officers in March 2006, none of which
were
exercised. The administrative error related to the use of the closing price
of
the Company's common stock on the day prior to the award, rather than the
closing price on the day of the award in accordance with the Company's 2004
Long-Term Equity Compensation Plan. The need for the correction was identified
by the Company and the effect of the correction was not material to the fair
value of the awards, either at the time of the award or the time of the
correction.
For
2006,
the fair value of all Long-Term Incentive (“LTI”) awards was divided as follows:
70% for time vesting restricted stock and 30% for stock options (with both
types
of awards vesting 25% per year over a four year period). In 2007, a percentage
of the equity-based compensation awards are LTIP shares with the percentage
increasing for more highly compensated executives, and the balance of the awards
are time vesting restricted stock. For example, 50% of the CEO’s equity-based
compensation in 2007 will be LTIP shares, in contrast to 40% for the President
and 30% for the CAO. The following table summarizes LTI awards for 2006 and
2007, and the second table summarizes the target prices for the performance
vesting of the LTIP awards.
|
Long-Term
Incentive Compensation
|
||||||||||||||||||||||||
|
2006
|
2007
|
|||||||||||||||||||||||
|
Name
|
Percent
Of
Salary
|
Percent of Value
From
Time
Vesting
Restricted Stock
|
Percent
of Value
From
Stock
Options
|
Percent
Of
Salary
|
Percent of Value
From
Time
Vesting
Restricted Stock
|
Percent
of Value
From
LTIP
Stock
|
||||||||||||||||||
|
Steven
R. Williams
|
150 | % | 70 | % | 30 | % | 175 | % | 50 | % | 50 | % | ||||||||||||
|
Thomas
E. Riley
|
125 | % | 70 | % | 30 | % | 145 | % | 60 | % | 40 | % | ||||||||||||
|
Eric
R. Stearns
|
120 | % | 70 | % | 30 | % | 140 | % | 60 | % | 40 | % | ||||||||||||
|
Richard
W. McCullough(1)
|
100 | % | 70 | % | 30 | % |
-
|
-
|
-
|
|||||||||||||||
|
Darwin
L. Stump
|
110 | % | 70 | % | 30 | % | 90 | % | 70 | % | 30 | % | ||||||||||||
_______________
|
(1)
|
LTI
awarded in 2006 pursuant to initial employment agreement. Mr. McCullough
will be eligible for annual award consideration beginning in
2008.
|
|
LTIP
Target Prices (1)
|
||||||||||||||||||
|
Approximate
|
Target
Price
|
Percent
Vested if
|
||||||||||||||||
|
Growth
Target
|
Year
3
|
Year
4
|
Year
5
|
Target
Attained(2)
|
||||||||||||||
| 12 | % | $ |
60.00
|
$ |
67.50
|
$ |
75.00
|
50 | % | |||||||||
| 16 | % |
67.50
|
77.50
|
90.00
|
75 | % | ||||||||||||
| 20 | % |
75.00
|
90.00
|
107.50
|
100 | % | ||||||||||||
_______________
(1)
Growth
target percentages and target prices are based on the average closing price
of
the Company's common stock during the preceding December for each of the years
ended December 31, 2009, 2010 and 2011.
(2)
Performance
shares will vest for a performance period only if the target price is met or
exceeded for such period. Performance shares vested for a performance period
shall not be subject to divestment in the event the share price subsequently
decreases below the threshold in a subsequent performance
period.
Retirement
Plans
As
of
January 1, 2006, the Company maintained a 401(k) plan and a qualified profit
sharing plan for all of the Company’s employees including the executive
officers. On July 1, 2006, the two plans were combined into a single plan.
The
plan provides for discretionary matching contributions. Generally, the Company
matches employee 401(k) contributions dollar for dollar up to 10% of the
employee’s compensation and then matches 20% for contributions above 10% of the
employees' compensation up to the maximum allowable limits under the Internal
Revenue Code ("IRC"). The Company's profit sharing contribution is discretionary
and for 2006 was equal to 1% of the Company's consolidated net income. Total
Company contributions, to both 401(k) and profit sharing, to the plan in 2006
were $3.1 million.
Under
their current employment agreements, each of the executive officers also earns
the right to future payments following their retirement or other departure
from
the Company. For each year worked under his current agreement, the CEO earns
an
annual retirement benefit equal to $500 times the number of his full years
of
service times 10 ($500 per year of service for 10 years). Following the
termination of his service with the Company, the cumulative total of the
calculated annual retirement benefits is disbursed in ten equal annual
installments. For 2006, the retirement benefit was $115,000 ($11,500 per year
for 10 years) and for 2007, the retirement benefit will be $120,000 ($12,000
per
year for 10 years). The CEO's total cumulative retirement benefit, under this
plan, at December 31, 2006, was $330,000 ($33,000 per year for 10 years). Each
of the other executive officers, under their respective employment agreements,
annually earns a retirement benefit equal to $75,000 ($7,500 per year for 10
years). Following their termination of service with the Company, their
cumulative total annual retirement benefit will be disbursed in ten equal annual
installments. As of December 31, 2006, for each of the other executive officers,
excluding Mr. McCullough, the total cumulative benefit, including the 2006
increment, was $225,000 ($22,500 per year for 10 years). As of December 31,
2006, Mr. McCullough had not yet completed sufficient service to qualify for
the
benefit, but will, like the others, be eligible in 2007.
Additionally,
under his previous employment agreement, Mr. Williams earned supplemental
retirement benefits. The prior agreement requires the Company to pay Mr.
Williams an annual sum of $40,000 per year for the ten year period following
his
retirement from the Company (an aggregate of $400,000). This benefit was fully
vested on December 31, 2003. Under provisions of his previous employment
agreement, Mr. Williams may elect to defer payment up to five years following
his retirement. In the event of employment beyond the five year vesting period
or the deferral of payment following retirement the amount of the annual benefit
will be increased by 10.75% compounded annually. As of December 31, 2006, the
amount of this benefit is $543,470 (or $54,347 per year for 10 years). In the
event of change in control the benefits due under this agreement will be
accelerated and due immediately.
Other
Compensation and Benefits
The
Company also provides certain other benefits to its executive officers that
are
not tied to any formal individual or Company performance criteria and are
intended to be part of a competitive overall compensation program. Each of
the
executive officers has 1) a Company vehicle (or vehicle allowance) that they
use
for Company business, and are allowed to use for personal uses as well, 2)
coverage under the Company’s medical plan and reimbursement of medical expenses
not covered by the plan, 3) the right to be reimbursed for one Board-approved
club membership, 4) reimbursement of the cost of a $1 million life insurance
policy, and 5) reimbursement of the cost of disability insurance. Given the
importance of the executives and their good health to the success of the Company
and the achievement of its business goals, the Committee believes that the
medical insurance and reimbursement encourage the executives to seek appropriate
medical assistance. The other benefits are commonly provided to executives
and
are necessary to create a competitive compensation package.
Termination
Benefits including Change in Control Payments
The
Committee believes that severance benefits for senior management should reflect
the fact that it may be difficult for employees to find comparable employment
within a short period of time. They also should disentangle the Company from
the
former employee as soon as practicable. For instance, while it is possible
to
provide salary continuation to an employee during the job search process, which
in some cases may be less expensive than a lump-sum severance payment, a
lump-sum severance payment is preferable in order to most cleanly sever the
relationship as soon as practicable. The Company has entered into employment
agreements with each of the executive officers that include change in control
provisions. These agreements provide for the continued employment of the
executives for a period of two years following a change in control of the
Company. These agreements are intended to retain the executives and provide
continuity of management in the event of an actual or threatened change in
the
control of the Company and ensure that the executive’s compensation and benefits
expectations would be satisfied in such event.
The
compensation provisions in the event of a change in control also serve to lessen
the potential negative impact of a change in control on the executive officers.
The Committee believes this is desirable to encourage the executives to consider
possible change in control situations that might benefit the Company’s
shareholders.
Where
the
termination is without “cause” or the executive officer terminates employment
for “good reason,” the severance plan provides for benefits equal to three times
the sum of: a) the executive officer’s highest base salary during the previous
two years of employment immediately preceding the termination date, plus b)
the
highest bonus paid to the executive officer during the same two year period.
The
executive officer is also entitled to 1) vesting of any unvested equity
compensation, 2) reimbursement for any unpaid expenses, 3) retirement benefits
earned under the current or previous agreements, 4) continued coverage under
the
Company’s medical plan for up to 18 months, and 5) payment of any earned, unpaid
bonus amounts. In addition, a terminated executive officer is entitled to
receive any benefits that he otherwise would have been entitled to receive
under
our 401(k) and profit sharing plan, although those benefits are not increased
or
accelerated. The Committee believes that these termination benefits are
comparable to the general practice among similar companies, although it has
not
conducted a study to confirm this.
Good
reason includes 1) assignment to the executive of duties materially and
adversely inconsistent with his position, duties, responsibilities and status
with the Company, 2) an adverse change in the executive’s position with the
Company, 3) a change in control of the Company, 4) a decrease of the executive
officer’s base salary, 5) a material reduction in the benefits provided by the
Company, 6) the requirement by the Company for the executive officer to be
based
anywhere outside of Bridgeport, West Virginia, 7) the failure by the Company
to
obtain a satisfactory agreement from any successor or assignee of the Company
to
assume and agree to the Company’s obligations under the employment agreement, or
8) any other material breach of the employment agreement by the
Company.
The
Company may terminate any of the executive officers for just cause, which is
defined in the employment agreements to include 1) a failure by the executive
to
perform his duties, 2) conduct by the executive that results in consequences
which are materially adverse to the Company, monetarily or otherwise, 3) a
guilty plea or conviction of a felony, or 4) a material breach of the terms
of
the employment agreement by the executive officer. If an executive officer
is
terminated for just cause, the Company is required to pay the executive officer
his base salary through the termination date plus any bonus (only for periods
completed and accrued, but not paid), incentive, deferred, retirement or other
compensation, and provide any other benefits, which have been earned or become
payable as of the termination date but which have not yet been paid or
provided.
If
an
executive officer voluntarily terminates his employment with the Company for
other than good reason, he is entitled to receive 1) the base salary, bonus
and
incremental retirement payment prorated for the portion of the year that the
executive officer is employed by the Company, 2) any incentive, deferred or
other compensation which has been earned or has become payable, but which has
not yet been paid under the schedule originally contemplated in the agreement
under which they were granted or in full without discount within 60 days of
the
termination date at the discretion of the Company, 3) any unpaid expense
reimbursement upon presentation by the executive officer of an accounting of
such expenses in accordance with normal Company practices, and 4) any other
payments for benefits earned under the employment agreement or Company
plans.
The
table
below provides information regarding the amounts each of the executive officers
would be eligible to receive if a termination event had occurred as of December
31, 2006:
|
Termination
Benefits
|
||||||||||||||||
|
Name
|
Retirement
or
Voluntary
Termination
by
Executive
|
Termination
For
Cause
by
Company
|
Change
in Control or
Termination
Without
Cause or
Good
Reason
by
Executive
|
Death/
Disability(1)
|
||||||||||||
|
Steven
R. Williams(2)
|
$ |
1,669,067
|
$ |
1,513,817
|
$ |
4,198,813
|
$ |
2,286,078
|
||||||||
|
Thomas
E. Riley
|
541,252
|
459,652
|
2,172,522
|
1,069,117
|
||||||||||||
|
Eric
R. Stearns
|
520,252
|
444,952
|
2,315,782
|
1,000,160
|
||||||||||||
|
Richard
W. McCullough(3)
|
-
|
-
|
1,153,767
|
317,267
|
||||||||||||
|
Darwin
L. Stump
|
456,677
|
423,602
|
1,839,846
|
681,171
|
||||||||||||
_______________
| (1) |
In
the event of death or disability, the termination benefits would
consist
of (i) the base salary and bonus for the portion of the year the
executive
officer is employed by the Company; (ii) the base salary that would
have
been earned for six months after termination; (iii) immediate vesting
of
all equity and option awards; (iv) the payment of deferred retirement
compensation based upon the schedule originally contemplated in the
deferred retirement compensation agreement or in a lump-sum no later
than
two and one-half months following the close of the calendar year
in which
the death or disability occurred; (v) reimbursement for any unpaid
expenses; (vi) any benefits earned under the 401(k) and profit sharing
plan; and (vii) continued coverage under the Company's medical plan,
life
time coverage for Mr. Williams and for up to 18 months for all other
named
executive officers.
|
| (2) |
Includes
(i) the estimated lifetime value of medical benefits for Mr. Williams
and/or his spouse; and (ii) the sum of deferred retirement compensation
benefits related to prior employment agreement and current employment
agreement.
|
| (3) |
Includes
a signing bonus of $83,000 (employment effective November 15, 2006).
If
employment terminates within one year after commencement of employment,
Mr. McCullough must refund to the Company a pro-rata portion of the
signing bonus.
|
Executive
and Director Share Retention and Ownership Guidelines
In
order
to promote equity ownership and further align the interests of management with
the Company’s shareholders, the Committee has adopted share retention and
ownership guidelines for senior management and non-employee directors. Under
these guidelines, executive officers and non-employee directors are required
to
achieve and continue to maintain a significant ownership position, expressed
as
a multiple of salary as follows:
|
Chief
Executive Officer
|
3
times salary
|
|
Other
Executive Officers (4 persons)
|
2
times salary
|
|
Non-Employee
Directors
|
1
times retainer
|
The
Committee periodically reviews share ownership levels of the persons subject
to
these guidelines. Shares held by the executive officers and shares held
indirectly through the Company 401(k) plan are included in determining an
executive officer’s share ownership. Shares underlying stock options, including
vested options, as well as unvested restricted stock, are not included. Each
of
the executive officers, excluding Mr. McCullough who was hired in November
2006,
and the non-employee directors have achieved shareholdings in excess of the
applicable multiple set forth above.
The
Company’s insider trading policy expressly prohibits Company officers,
directors, employees and associates from engaging in options, puts, calls or
other transactions that are intended to hedge against the economic risk of
owning the Company shares.
Employment
Agreements
The
Company entered into employment agreements with Messrs. Williams, Riley, Stearns
and Stump effective January 1, 2004, and Mr. McCullough effective November
13,
2006. The initial term of the agreements is for two years and they are
automatically extended for an additional 12 months beginning on the first
anniversary of the effective date and on each successive anniversary unless
either party cancels. The employment agreements provide for the base annual
salary to be reviewed annually (see "Base Salary" discussion above ).
Each
employment agreement provides for an annual performance bonus as determined
by
the Compensation Committee and is based in part upon written objective criteria
and in part upon the discretion of the Compensation Committee. The annual
performance bonus earned is calculated as a percentage, as determined by the
Compensation Committee, of the executive officers' base salary.
Each
employment agreement contains a standard non-disclosure covenant and, also,
provides that the executive officer is prohibited during the term of his
employment and for a period of one year following his termination from engaging
in any business that is competitive with the Company's oil and gas drilling
business. Additionally, the employment agreements state that the executive
officer must devote substantially all of his business time, best efforts and
attention to promote and advance the business of the Company. The executive
officer may not be employed in any other business activity, other than with
the
Company, during the term of the employment agreement, whether or not such
activity is pursued for gain, profit or other pecuniary advantage without
approval by the Compensation Committee of the Board. This restriction will
not
prevent the executive officer from investing his personal assets in a business
which does not compete with the Company or its affiliates, and where such
investment will not require services of any significance on the part of the
executive officer in the operation of the affairs of the business.
Other
Agreements and Arrangements
Executive
officers may invest in a Board-approved executive drilling program at the
Company's cost. During 2006, Messrs. Williams, Riley and Stump invested
approximately $40,000, $20,000 and $17,000, respectively. Other investors
participating in drilling with the Company are generally charged a profit or
markup above the cost of the wells; for example, the markup on Company-sponsored
partnerships is approximately 15% of the cost of the wells. As a result, the
executive officers realize a benefit not generally available to other investors.
The Board believes that having the executive officers invest in wells with
the
Company and other investors helps to create a commonality of interests much
like
share ownership creates a commonality of interests between the shareholders
and
executive officers.
Internal
Revenue Code Section 162(m)
The
Committee is aware of IRC Section 162(m) of the tax code, which generally limits
the deductibility of executive pay in excess of one million dollars, and which
specifies the requirements for the “performance-based” exemption from this
limit. Elements of the executive compensation program are indeed
performance-based, and vehicles such as stock options are believed to qualify
as
performance-based under Section 162(m). Other aspects of the executive
compensation program may not qualify as performance-based, such as time-based
restricted stock and our annual incentive plan because the Committee prefers
the
ability to exercise discretion in evaluating a portion of participants'
performance. The financial implications of a potential lost deduction are not
expected to be material. The Committee will continue to monitor its position
on
the impact of Section 162(m) for the Company's executive compensation programs.
Compensation
Committee Report
The
Compensation Committee has met to review and discuss with the Company’s
management the specific disclosure contained under the heading “Compensation
Discussion and Analysis”. Based on its review and discussions with management
the Compensation Committee has recommended to the Board of Directors that the
Compensation Discussion and Analysis be included in this Annual Report on Form
10-K.
This
report has been provided by the Compensation Committee of the Board of Directors
of the Company.
David
C.
Parke, Chairman
Vincent
F. D'Annunzio
Anthony
J. Crisafio
***
2006
SUMMARY COMPENSATION TABLE
The
following table provides summary compensation information for the Company's
Chief Executive Officer, the Chief Financial Officer, and the three most highly
compensated executive officers, other than the Chief Executive Officer and
Chief
Financial Officer, whose total compensation exceeded $100,000 in 2006 (the
"named executive officers").
|
Name
and Principal Position
|
Salary
|
Bonus(1)
|
Stock
Awards
(2)
|
Option
Awards
(3)
|
Non-Equity
Incentive
Plan
Compensation(4)
|
Nonqualified
Deferred
Compensation
(5)
|
All
Other
Compensation
(6)
|
Total
Compensation
|
||||||||||||||||||||||||
|
Steven
R. Williams
|
$ |
345,000
|
$ |
155,250
|
$ |
163,023
|
$ |
54,546
|
$ |
362,250
|
$ |
88,438
|
$ |
37,778
|
(7) | $ |
1,206,285
|
|||||||||||||||
|
Chairman,
Chief Executive Officer and Director
|
||||||||||||||||||||||||||||||||
|
Thomas
E. Riley
|
272,000
|
81,600
|
107,580
|
35,977
|
190,400
|
30,824
|
9,357
|
(8) |
727,738
|
|||||||||||||||||||||||
|
President
and Director
|
||||||||||||||||||||||||||||||||
|
Eric
R. Stearns
|
251,000
|
175,300
|
(9) |
98,318
|
32,806
|
175,700
|
21,730
|
17,773
|
772,627
|
|||||||||||||||||||||||
|
Executive
Vice President, Exploration and Development
|
||||||||||||||||||||||||||||||||
|
Richard
W. McCullough
|
32,237
|
83,000
|
(10) |
5,928
|
2,289
|
-
|
3,848
|
-
|
127,302
|
|||||||||||||||||||||||
|
Chief
Financial Officer and Treasurer
|
||||||||||||||||||||||||||||||||
|
Darwin
L. Stump
|
220,500
|
33,075
|
85,963
|
28,484
|
154,350
|
25,880
|
17,610
|
(11) |
565,862
|
|||||||||||||||||||||||
|
Chief
Accounting Officer
|
||||||||||||||||||||||||||||||||
_______________
|
(1)
|
The
annual STI bonus plan provides for a discretionary component equal
to 30%
of the total STI award. The amounts for Messrs. Williams, Riley,
and Stump
represent only the discretionary amounts earned pursuant to the STI
plan.
The annual STI bonus plan has established performance criteria that
must
be met before 70% of the annual cash bonus may be paid. See discussion
of
the STI bonus plan above.
|
|
(2)
|
Represents
compensation expense recorded by the Company pursuant to FAS 123(R)
related to outstanding restricted stock awards. See Note 8, Common
Stock,
to the Consolidated Financial
Statements.
|
|
(3)
|
Represents
compensation expense recorded by the Company pursuant to FAS 123(R)
related to outstanding stock options. See Note 8, Common Stock, to
the
Consolidated Financial Statements.
|
|
(4)
|
Represents
performance based cash bonuses earned during the year and paid shortly
after year-end. As noted above in the discussion and analysis, the
STI
bonus plan has established performance criteria that must be met
for the
executive to earn 70% of the targeted annual cash bonus amount.
|
|
(5)
|
Represents
the present value of the current year benefit earned related to the
deferred compensation retirement plan. The amount for Mr. McCullough
was
based upon a prorated annual amount since 2006 was the initial year
of
employment.
|
|
(6)
|
All
Other Compensation includes insurance and medical reimbursements,
social
fringe benefits such as club dues and athletic event tickets, the
value
for the personal use of Company automobiles and discounts related
to
Company-sponsored drilling
programs.
|
|
(7)
|
Includes,
in addition to other compensation items discussed in (6) above, $20,170
for post retirement medical and a discount received of $5,216 related
to
investments in Company-sponsored drilling programs, see discussion
above
in Other Agreements and
Arrangements.
|
|
(8)
|
Includes,
in addition to other compensation items discussed in (6) above, a
discount
received of $2,649 related to investments in Company-sponsored drilling
programs.
|
|
(9)
|
Includes
$75,300 pursuant to discretionary component of the STI plan and an
additional $100,000 bonus for his role in the sale of an undeveloped
leasehold in Grand Valley Field in September.
|
|
(10)
|
Represents
a signing bonus paid at the start of employment with the Company
in
November 2006.
|
|
(11)
|
Includes,
in addition to other compensation items discussed in (6) above, a
discount
received of $2,437 related to an investment in a Company-sponsored
drilling program.
|
2006
GRANTS OF PLAN-BASED AWARDS TABLE
|
Estimated
Future Payouts
|
Number
of
|
Grant
Date
|
|||||||||||||||||||||||||||
|
Under
Non-Equity
|
Securities
|
Exercise
Price
|
Fair
Value of
|
||||||||||||||||||||||||||
|
Incentive
Plan Awards
|
Number
of
|
Underlying
|
Per
Share
|
Stock
and
|
|||||||||||||||||||||||||
|
Shares
|
Option
|
of
Option
|
Option
|
||||||||||||||||||||||||||
|
Name
|
Grant
Date
|
Threshold
|
Target
|
Maximum
|
Awarded
|
Awards(1)
|
Awards(1)
|
Awards
(2)
|
|||||||||||||||||||||
|
Steven
R. Williams
|
3/16/2006
|
$ |
-
|
$ |
-
|
$ |
-
|
9,348
|
7,517
|
$ |
44.95
|
(3) | $ |
571,886
|
|||||||||||||||
|
6/23/2006
|
-
|
258,750
|
517,500
|
- | - | - | - | ||||||||||||||||||||||
|
Thomas
E. Riley
|
3/16/2006
|
- | - | - |
6,141
|
4,939
|
44.95
|
(3) |
375,707
|
||||||||||||||||||||
|
6/23/2006
|
-
|
136,000
|
272,000
|
- | - | - | - | ||||||||||||||||||||||
|
Eric
R. Stearns
|
3/16/2006
|
- | - | - |
5,441
|
4,375
|
44.95
|
(3) |
332,860
|
||||||||||||||||||||
|
6/23/2006
|
-
|
125,500
|
251,000
|
- | - | - | - | ||||||||||||||||||||||
|
Richard
W. McCullough
|
11/14/2006
|
-
|
-
|
-
|
4,256
|
3,333
|
43.60
|
255,688
|
|||||||||||||||||||||
|
Darwin
L. Stump
|
3/16/2006
|
-
|
-
|
-
|
4,381
|
3,523
|
44.95
|
(3) |
268,020
|
||||||||||||||||||||
|
6/23/2006
|
-
|
110,250
|
220,500
|
- | - | - | - | ||||||||||||||||||||||
_______________
|
(1)
|
Represents
awards under the Company's long-term equity compensation plan (see
Note 8,
"Common Stock," to the consolidated financial statements and "Long-Term
Incentives" above in the Compensation Discussion and Analysis for
additional discussion).
|
|
(2)
|
The
Grant Date Fair Value of stock and option awards is computed by
multiplying the restricted stock number of shares awarded by the
closing
price of the Company's stock on the date of the grant, plus the Black
Scholes value per share times the number of securities underlying
the
option shares. The closing price per share of awards on March 16,
2006,
and November 14, 2006, was $44.95 and $43.60, respectively. The Black
Scholes estimated fair value per share of the options awarded on
March 16,
2006, and November 14, 2006, was $20.18 and $21.04,
respectively.
|
|
(3)
|
In
April 2007, the Company corrected an administrative error related
to the
use of the closing price of the Company's common stock on the day
prior to
the award, rather than the closing price on the day of the award
in
accordance to the plan, see Long-Term Incentives discussion above.
The
Exercise Price Per Share correctly reflects the closing price per
share on
the day of the award.
|
Outstanding
Equity Awards at 2006 Fiscal Year-End Table
|
Option
Awards
|
Restricted
Stock Awards
|
||||||||||||||||||
|
Number
of Securities
|
Number
|
Market
Value
|
|||||||||||||||||
|
Underlying
Unexercised
|
of
Shares
|
of
Shares
|
|||||||||||||||||
|
Options
Held at
|
That
Have
|
That
Have
|
|||||||||||||||||
|
December
31, 2006
|
Exercise
|
Expiration
|
Not
|
Not
|
|||||||||||||||
|
Name
|
Exercisable
|
Unexercisable
|
Price
|
Date
|
Vested
|
Vested
(1)
|
|||||||||||||
|
Steven
R. Williams
|
2,935
|
2,935(2
|
)
|
$
|
37.15
|
12/13/2014
|
13,413(3
|
)
|
$
|
577,430
|
|||||||||
|
|
- |
7,517(4
|
)
|
44.95
|
3/16/2016
|
- | - | ||||||||||||
|
Thomas
E. Riley
|
1,945
|
1,945(5
|
)
|
37.15
|
12/13/2014
|
8,836(6
|
)
|
380,390
|
|||||||||||
|
|
-
|
4,939(7
|
)
|
44.95
|
3/16/2016
|
- | - | ||||||||||||
|
Eric
R. Stearns
|
1,835
|
1,835(8
|
)
|
37.15
|
12/13/2014
|
7,981(9
|
)
|
343,582
|
|||||||||||
|
|
-
|
4,375(10
|
)
|
44.95
|
3/16/2016
|
- | - | ||||||||||||
|
Richard
W. McCullough
|
-
|
3,333(11
|
)
|
43.60
|
11/14/2016
|
4,256(12
|
)
|
183,221
|
|||||||||||
|
Darwin
L. Stump
|
1,725
|
1,725(13
|
)
|
37.15
|
12/13/2014
|
6,771(14
|
)
|
291,492
|
|||||||||||
|
|
-
|
3,523(15
|
)
|
44.95
|
3/16/2016
|
- | - | ||||||||||||
_______________
|
(1)
|
Market
value of shares is based on the closing price of the Company's common
stock on December 29, 2006, $43.05 per
share.
|
|
(2)
|
Vesting:
1,467 shares in 2007 and 1,468 shares in
2008.
|
|
(3)
|
Vesting:
4,369 shares in 2007, 4,370 shares in 2008, 2,337 shares in 2009
and 2,337
shares in 2010.
|
|
(4)
|
Vesting:
25% in each of the years 2007 through
2010.
|
|
(5)
|
Vesting:
972 shares in 2007 and 973 shares in
2008.
|
|
(6)
|
Vesting:
2,882 shares in 2007, 2,883 shares in 2008, 1,535 shares in 2009
and 1,536
shares in 2010.
|
|
(7)
|
Vesting:
25% in each of the years 2007 through
2010.
|
|
(8)
|
Vesting:
917 shares in 2007 and 918 shares in
2008.
|
|
(9)
|
Vesting:
2,630 shares in 2007, 2,630 shares in 2008, 1,360 shares in 2009
and 1,361
shares in 2010.
|
|
(10)
|
Vesting:
25% in each of the years 2007 through
2010.
|
|
(11)
|
Vesting:
25% in each of the years 2007 through
2010.
|
|
(12)
|
Vesting:
25% in each of the years 2007 through
2010.
|
|
(13)
|
Vesting:
862 shares in 2007 and 863 shares in
2008.
|
|
(14)
|
Vesting:
2,290 shares in 2007, 2,290 shares in 2008, 1,095 shares in 2009
and 1,096
shares in 2010.
|
|
(15)
|
Vesting:
25% in each of the years 2007 through
2010.
|
2006
Options Exercises and Stock Vested Table
|
Option
Awards
|
Stock
Awards
|
|||||||||||||||
|
Name
|
Number
of
Shares
Acquired
on
Exercise
|
Value
Realized
on
Exercise
|
Number
of
Shares
Acquired
on
Vesting
|
Value
Realized
on
Vesting(1)
|
||||||||||||
|
Steven
R. Williams
|
-
|
$ |
-
|
2,032
|
$ |
90,932
|
||||||||||
|
Thomas
E. Riley
|
-
|
-
|
1,347
|
60,278
|
||||||||||||
|
Eric
R. Stearns
|
-
|
-
|
1,270
|
56,833
|
||||||||||||
|
Richard
W. McCullough
|
-
|
-
|
-
|
-
|
||||||||||||
|
Darwin
L. Stump
|
-
|
-
|
1,195
|
53,476
|
||||||||||||
_______________
| (1) |
Based
on the closing price of the Company's common stock on the date of
vesting,
December 13, 2006, $44.75 per
share.
|
2006
Nonqualified Deferred Compensation Table
|
Name
|
Executive
Contributions
in
2006
|
Company
Contributions
in
2006(1)
|
Aggregate
Earnings
in
2006(2)
|
Aggregate
Withdrawals/
Distributions
|
Aggregate
Balance
at
December
31, 2006
|
|||||||||||||||
|
Steven
R. Williams
|
$ |
-
|
$ | 88,438 | (3) | $ | 35,699 | (4) | $ |
-
|
$ |
754,821
|
||||||||
|
Thomas
E. Riley
|
-
|
30,824
|
3,489
|
-
|
92,471
|
|||||||||||||||
|
Eric
R. Stearns
|
-
|
21,730
|
2,460
|
-
|
65,189
|
|||||||||||||||
|
Richard
W. McCullough
|
-
|
3,848
|
-
|
-
|
3,848
|
|||||||||||||||
|
Darwin
L. Stump
|
-
|
25,880
|
2,930
|
-
|
77,641
|
|||||||||||||||
_______________
|
(1)
|
Company
contributions include the present value cost of providing the defined
compensation payout over a ten year period. Since this is a self
funded
deferred compensation plan, the Company’s additional annual deferred
compensation expense, less the interest component noted as aggregate
earnings above, equals the increase in the accrued Company contributions
that are required to fund the plan. These annual amounts are a component
of the executive officers' 2006 compensation and are included in
the 2006
Summary Compensation Table.
|
|
(2)
|
Aggregate
earnings consist of interest income earned on the beginning of the
year
compensation balance at a 6% interest rate. These earnings are not
included in the 2006 Summary Compensation Table as they are not above
market rate.
|
|
(3)
|
Mr.
Williams received deferred compensation benefits from both the current
deferred compensation plan for all named executive officers, as well
as a
prior retirement plan. The amount for Mr. Williams includes a reduction
of
$8,990 in the current funding amount due to the fact that the deferral
option has been elected by Mr. Williams for the start of benefits
under
the prior retirement plan. The deferred payment start date has been
deferred for five years after retirement. In addition, current year
required Company contributions were also reduced by $35,699 due to
a
change in Mr. Williams’ projected retirement date.
|
|
(4)
|
Aggregate
earnings for Mr. Williams include additional earnings of $4,590 on
the
Company’s previous retirement plan due to that plan’s “five year deferral
option”.
|
DIRECTOR
COMPENSATION
Each
non-employee director received an annual retainer of $40,000 during 2006.
Additionally, non-employee directors receive a fee for being a member of certain
committees. During the third quarter of 2006, the audit committee chairperson
began receiving an annual fee of $13,000, payable quarterly, and the other
audit
committee members began receiving an annual fee of $8,000, each, also payable
quarterly. The compensation committee chairperson received an annual fee of
$2,500 and the nominating committee chairperson received an annual fee of
$2,500. Non-employee directors also receive restricted stock compensation.
Pursuant to the shareholder approved, Non-Employee Director Restricted Stock
Plan (the “Restricted Stock Plan”), as of the date of each annual stockholders
meeting of the Company each non-employee director will be awarded a specified
number of shares of Restricted Stock as determined by the Board. The amount
of
the award for the upcoming plan year will be disclosed in the Company’s proxy
statement. Directors receiving Restricted Stock under the Restricted Stock
Plan
will have all of the rights of a stockholder including the right to vote the
shares and receive cash dividends and other cash distributions. Restricted
Stock
will be subject to the restrictions of the Restricted Period commencing on
the
date the stock is awarded. Each non-employee director can choose to defer a
portion or all of their annual cash compensation by participating in the
Non-Employee Director Deferred Compensation Plan. The plan's trustee will invest
all cash deposits received exclusively in the common stock of the Company.
2006
Director Compensation Table
|
Name
|
Fees
Earned/
Paid
in Cash
|
Stock
Awards
(1)
|
Option
Awards
|
All
Other
Compensation
|
Total
|
|||||||||||
|
Kimberly
Luff Wakim
|
$
|
46,500(2)
|
|
$
|
26,310
|
$
|
-
|
$
|
-
|
$
|
72,810
|
|||||
|
Vincent
F. D'Annunzio
|
42,500(3)
|
|
41,464
|
-
|
-
|
83,964
|
||||||||||
|
David
C. Parke
|
44,500
|
|
23,088
|
-
|
-
|
67,588
|
||||||||||
|
Jeffrey
C. Swoveland
|
45,250
|
23,088
|
-
|
-
|
68,338
|
|||||||||||
|
Donald
B. Nestor
|
35,750(4)
|
|
19,996
|
-
|
-
|
55,746
|
||||||||||
|
Anthony
J. Crisafio
|
12,000
|
2,882
|
-
|
-
|
14,882
|
|||||||||||
_______________
|
(1)
|
Represents
compensation expense recorded by the Company pursuant to FAS 123(R).
See
Note 8, Common Stock, to the Consolidated Financial
Statements.
|
|
(2)
|
Includes
amounts deferred (20%) pursuant to stock purchase
election.
|
|
(3)
|
Includes
amounts deferred (100%) pursuant to stock purchase
election.
|
|
(4)
|
Retired
from directorship on September 1, 2006. He received a prorated annual
retainer and fees for three quarters of the year based on his time
of
service.
|
Compensation
Committee Interlocks and Insider Participation
There
are
no Compensation Committee interlocks.
ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The
following table sets forth certain information regarding ownership of the
Company's common stock as of April 30, 2007, by (a) each person known by the
Company to own beneficially more than 5% of the outstanding shares of common
stock; (b) each director of the Company; (c) each executive officer; and (d)
all
directors and executive officers as a group. As of April 30, 2007, 14,887,530
common shares of the Company were issued and outstanding.
|
Name
and Address of Beneficial Owner
|
Number
Of
Shares
Beneficially
Owned
|
Percent
Of
Shares
Beneficially
Owned
|
||||||
|
FMR
Corporation
|
||||||||
|
82
Devonshire Street
Boston,
MA 02109
|
2,420,360 | (1) | 16.3 | % | ||||
|
Steinberg
Asset Management, LLC
|
||||||||
|
12
East 49th Street
New
York, NY 10017
|
2,085,868 | (2) | 14.0 | % | ||||
|
Kayne
Anderson Rudnick
|
||||||||
|
Investment
Management, LLC
|
||||||||
|
1800
Avenue of the Stars, 2nd Floor
Los
Angeles, CA 90067
|
1,078,093 | (3) | 7.2 | % | ||||
|
Barclays
Global Investors, NA
|
||||||||
|
45
Fremont Street
San
Francisco, CA 94105
|
1,029,403 | (4) | 6.9 | % | ||||
|
Steven
R. Williams
|
310,931 | (5) | 2.1 | % | ||||
|
Thomas
E. Riley
|
104,605 | (6) |
*
|
|||||
|
Eric
R. Stearns
|
56,828 | (7) |
*
|
|||||
|
Richard
W. McCullough
|
- | (8) |
*
|
|||||
|
Darwin
L. Stump
|
26,540 | (9) |
*
|
|||||
|
Vincent
F. D'Annunzio
|
21,042
|
*
|
||||||
|
Jeffrey
C. Swoveland
|
12,916
|
|||||||
|
Kimberly
Luff Wakim
|
4,479
|
*
|
||||||
|
David
C. Parke
|
4,129
|
*
|
||||||
|
Anthony
J. Crisafio
|
1,035
|
*
|
||||||
|
All
directors and executive officers as a group (10 persons)(10)
|
542,505 | (11) | 3.6 | % | ||||
_______________
*
Less
than 1%
|
(1)
|
According
to the Schedule 13G filed by FMR Management with the SEC on February
14,
2007.
|
|
(2)
|
According
to the Schedule 13G filed by Steinberg Asset Management with the
SEC on
February 9, 2007.
|
|
(3)
|
According
to the Schedule 13G filed by Anderson Rudnick Investment Management
with
the SEC on February 5, 2007.
|
|
(4)
|
According
to the Schedule 13G filed by Barclays Global Investors, NA Management
with
the SEC on January 23, 2007.
|
|
(5)
|
Includes
4,814 shares subject to options exercisable within 60 days of April
30,
2007; excludes 19,561 restricted shares subject to
vesting.
|
|
(6)
|
Includes
3,179 shares subject to options exercisable within 60 days of April
30,
2007; excludes 13,971 restricted shares subject to
vesting.
|
|
(7)
|
Includes
2,928 shares subject to options exercisable within 60 days of April
30,
2007; excludes 12,597 restricted shares subject to
vesting.
|
|
(8)
|
Excludes
4,256 restricted shares subject to
vesting.
|
|
(9)
|
Includes
2,605 shares subject to options exercisable within 60 days of April
30,
2007; excludes 9,316 restricted shares subject to
vesting.
|
|
(10)
|
Address:
120 Genesis Boulevard, Bridgeport, WV
26330.
|
|
(11)
|
Includes
13,526 shares subject to options exercisable within 60 days of April
30,
2007; excludes 59,701 restricted shares subject to
vesting.
|
Equity
Compensation Plan Information
The
following table summarizes information related to the Company's equity
compensation plans under which its equity securities are authorized for issuance
as of April 30, 2007.
|
Plan
category
|
Number
of securities to be
issued
upon exercise of
outstanding
options
|
Weighted-average
exercise
price
of outstanding options
|
Number
of securities
remaining
available for
future
issuance under equity
compensation
plans(1)
|
|||||||||
|
Equity
compensation plans approved by security holders(2)
|
59,567 | (3) | $ |
29.56
|
530,267
|
|||||||
|
Equity
compensation plans not approved by security holders
|
-
|
-
|
-
|
|||||||||
|
Total
|
59,567
|
$ |
29.56
|
530,267
|
||||||||
_______________
|
(1)
|
Excludes
the number of securities to be issued upon exercise of outstanding
options
and performance shares subject to certain performance goals over
a
specified period of time.
|
|
(2)
|
These
plans consist of the 1999 Incentive Stock Option and Non-Qualified
Stock
Option Plan, the 2004 Long-Term Equity Compensation Plan and the
2005
Non-Employee Director Restricted Stock
Plan.
|
|
(3)
|
Excludes
31,972 shares of common stock issuable upon the obtainment of specified
performance goals over a specified period of
time.
|
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
Policies
and Procedures with Respect to Transactions with Related
Persons
The
Board
has adopted a policy for the review, approval and ratification of transactions
that involve related parties and potential conflicts of interest.
The
related party transaction policy applies to each director and executive officer
of the Company, any nominee for election as a director, any security holder
who
is known to own more than five percent of the Company's voting securities,
any
immediate family member of any of the foregoing persons and any corporation,
firm or association in which one or more of the Company's directors are
directors or officers, or have a substantial financial interest.
Under
the
related party transaction policy a related person transaction is a transaction
or arrangement involving a related person in which the Company is a participant
or that would require disclosure in the Company's filings with the SEC as a
transaction with a related person.
The
related persons must disclose to the Audit Committee any potential related
person transactions and must disclose all material facts with respect to such
interest. All related person transactions will be reviewed by the Audit
Committee. In determining whether to approve or ratify a transaction, the Audit
Committee will consider the relevant facts and circumstances of the transaction
which may include factors such as the relationship of the related person with
the Company, the materiality or significance of the transaction to the Company
and the business purpose and reasonableness of the transaction, whether the
transaction is comparable to a transaction that could be available to the
Company on an arms-length basis, and the impact of the transaction on the
Company's business and operations.
During
the year ended December 31, 2006, there was no transaction or series of
transactions, or any currently proposed transaction, in which the amount
involved exceeds $120,000 and in which any director, executive officer, holder
of more than 5% of our common stock or any member of the immediate family of
any
of the foregoing persons had or will have a direct or indirect material
interest.
ITEM
14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
KPMG
Fees
The
following table presents the aggregate fees billed to the Company by KPMG LLP
("KPMG") for services in 2006 and 2005 as of March 31, 2007.
|
2006
|
2005
|
|||||||
|
Audit
fees
|
$ |
2,038,701
|
$ |
2,457,423
|
||||
|
Audit
related fees
|
983,701
|
394,543
|
||||||
|
Total
audit and audit related fees(1)
|
$ |
3,022,402
|
$ |
2,851,966
|
||||
| _______________ | ||||||||
|
(1)There
were no tax or other fees for services rendered to us during either
of the
years.
|
||||||||
Audit
Fees
Audit
fees include amounts billed for professional services rendered by KPMG for
the
audit of the Company's annual consolidated financial statements and the report
on management's assessment of internal control over financial reporting and
the
effectiveness of the Company's internal control over financial reporting for
the
years ended December 31, 2006 and 2005, including reviews of the condensed
consolidated financial statements included in the Company's quarterly reports
on
Form 10-Q for the years ended December 31, 2006 and 2005. The 2005 audit fees
also include fees billed for professional services rendered by KPMG for the
audit of the consolidated financial statements included in the Company's Form
10-K/A for the year ended December 31, 2004.
Audit
Related Fees
Audit
related fees include amounts billed for professional services rendered by KPMG
for the audits of the annual financial statements of the Company-sponsored
drilling partnerships for which the Company acts as managing general partner.
The aggregate billings for those professional services rendered during 2006
primarily represent audits for years ended December 31, 2005 and prior. Total
audit related fees for the year ended December 31, 2005, includes $140,977
related to due diligence services provided for a contemplated
transaction.
Audit
Committee Pre-Approval Policies and Procedures
The
Sarbanes-Oxley Act of 2002 requires that all services provided to the Company
by
its Independent Registered Public Accounting Firm be subject to pre-approval
by
the Audit Committee or authorized members of the Committee. The Audit Committee
has adopted policies and procedures for pre-approval of all audit services
and
non-audit services to be provided by the Company's Independent Registered Public
Accounting Firm. Services necessary to conduct the annual audit must be
pre-approved by the Audit Committee annually at a meeting. Permissible non-audit
services to be performed by the independent accountant may also be approved
on
an annual basis by the Audit Committee if they are of a recurring nature.
Permissible non-audit services to be conducted by the independent accountant,
which are not eligible for annual pre-approval, must be pre-approved
individually by the full Audit Committee or by an authorized Audit Committee
member. Actual fees incurred for all services performed by the independent
accountant will be reported to the Audit Committee after the services are fully
performed. The duties of the Committee are described in the Audit Committee
Charter, which is available at the Company's website under Corporate
Governance.
PART
IV
ITEM
15. EXHIBITS,
FINANCIAL STATEMENT SCHEDULES
|
(a)
|
(1)
|
Financial
Statements:
|
See
Index
to Financial Statements and Schedules on page F-1.
|
(2)
|
Financial
Statement Schedules:
|
See
Index
to Financial Statements and Schedules on page F-1.
Schedules
and Financial Statements Omitted
All
other
financial statement schedules are omitted because they are not required,
inapplicable, or the information is included in the Financial Statements or
Notes thereto.
|
(3)
|
Exhibits:
|
See
Exhibits Index on page E-1.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf
by
the undersigned, thereunto duly authorized.
|
PETROLEUM
DEVELOPMENT CORPORATION
|
|||
|
By
|
/s/
Steven R. Williams
|
||
|
Steven
R. Williams, Chairman
|
|||
|
May
22, 2007
|
|||
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following
persons
on behalf of the Registrant and in the capacities and on the dates
indicated:
|
Signature
|
Title
|
Date
|
|
|
/s/
Steven R. Williams
Steven
R. Williams
|
Chairman,
Chief Executive Officer and Director
(principal
executive officer)
|
May
22, 2007
|
|
|
/s/
Richard W. McCullough
Richard
W. McCullough
|
Chief
Financial Officer and Treasurer
(principal
financial officer)
|
May
22, 2007
|
|
|
/s/
Darwin L. Stump
Darwin
L. Stump
|
Chief
Accounting Officer
(principal
accounting officer)
|
May
22, 2007
|
|
|
/s/
Thomas E. Riley
Thomas
E. Riley
|
President
and Director
|
May
22, 2007
|
|
|
/s/
Jeffrey C. Swoveland
Jeffrey
C. Swoveland
|
Director
|
May
22, 2007
|
|
|
/s/
Vincent F. D'Annunzio
Vincent
F. D'Annunzio
|
Director
|
May
22, 2007
|
|
|
/s/
Kimberly Luff Wakim
Kimberly
Luff Wakim
|
Director
|
May
22, 2007
|
|
|
/s/
David C. Parke
David
C. Parke
|
Director
|
May
22, 2007
|
|
|
/s/
Anthony J. Crisafio
Anthony
J. Crisafio
|
Director
|
May
22, 2007
|
Exhibits
Index
|
Exhibit
Number
|
Exhibit
Name
|
Location
|
||
|
3.1
|
Amended
and Restated Certificate of Incorporation of the Company
|
Incorporated
by reference to Exhibit 3.1 to Form S-2, SEC File No. 333-36369,
filed on
September 25, 1997.
|
||
|
3.2
|
Amended
and Restated By Laws of the Company
|
Incorporated
by reference to Exhibit 3.1 to Form 8-K filed on April 2,
2007.
|
||
|
10.1
|
Amended
and restated Credit Agreement, dated as of November 4, 2005, Petroleum
Development Corporation, as borrower, and JPMorgan Chase Bank, N.A.
and
BNP Paribas, as lenders.
|
Incorporated
by reference to Exhibit 10.2 to Form 8-K dated November 4,
2005.
|
||
|
10.2
|
Employment
Agreement with Steven R. Williams, Chief Executive Officer and Chairman,
dated as of March 7, 2003, and amended December 29, 2005
|
Incorporated
by reference in Exhibit 10.2 to Form 10-K filed on March 7, 2003,
and
Exhibit 99.1 to Form 8-K filed January 4, 2006.
|
||
|
10.3
|
Employment
Agreement with Darwin L. Stump, Chief Accounting Officer, dated as
of
January 5, 2004, and amended December 29, 2005
|
Incorporated
by reference to Exhibit 99.4 Form 8-K dated January 5, 2004 and Exhibit
99.4 to Form 8-K dated January 4, 2006.
|
||
|
10.4
|
Employment
Agreement with Thomas E. Riley, President, dated as of January 5,
2004,
and amended December 29, 2005
|
Incorporated
by reference to Exhibit 99.6 Form 8-K dated January 5, 2004, and
Exhibit
99.2 to Form 8-K dated January 4, 2006.
|
||
|
10.5
|
Employment
Agreement with Eric R. Stearns, Executive Vice President, dated as
of
January 5, 2004, and amended December 29, 2005
|
Incorporated
by reference to Exhibit 99.5 Form 8-K dated January 5, 2004, and
Exhibit
99.3 to Form 8-K dated January 4, 2006.
|
||
|
Employment
Agreement with Richard W. McCullough, Chief Financial Officer, dated
as of
November 13, 2006.
|
Filed
herewith.
|
|||
|
10.7
|
2007
Compensation Arrangements with Executive Officers
|
Incorporated
by reference to Exhibit 99.1 to Form 8-K dated February 20,
2007.
|
||
|
10.8
|
2007
Long-Term Incentive Program
|
Incorporated
by reference to Exhibit 99.1 to Form 8-K dated February 20,
2007.
|
||
|
10.9
|
2007
Short-Term Incentive Program
|
Incorporated
by reference to Form 8-K dated April 2, 2007.
|
||
|
10.10
|
2005
Non-Employee Director Restricted Stock Plan
|
Incorporated
by reference to Exhibit 99.1 to Form S-8, SEC file No. 333-126444
filed on
July 7, 2005.
|
||
|
10.11
|
2004
Long-Term Equity Compensation Plan
|
Incorporated
by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-118215,
filed
on August 13, 2004.
|
|
Exhibit
Number
|
Exhibit
Name
|
Location
|
||
|
10.12
|
Non-Employee
Director Deferred Compensation Plan
|
Incorporated
by reference Exhibit 99.1 to Form S-8, SEC File No. 333-118222, filed
on
August 13, 2004.
|
||
|
10.13
|
1999
Incentive Stock Option and Non-Qualified Stock
|
Incorporated
by reference to Exhibit 99.1 to form S-8, SEC File No. 333-111825,
filed
on January 9, 2004.
|
||
|
10.14
|
1997
Employee Incentive Stock Option Plan
|
Incorporated
by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111824,
filed
on January 9, 2004.
|
||
|
10.15
|
Tom
Carpenter Employment Agreement Stock Option Plan
|
Incorporated
by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111823,
filed
on January 9, 2004.
|
||
|
14
|
Code
of Business Conduct and Ethics
|
Incorporated
by reference to Exhibit 3.1 to Form 10-K for the year ended December
31,
2002, SEC File No. 0-07246
filed on March 7, 2003.
|
||
|
Subsidiaries
|
Filed
herewith.
|
|||
|
Consent
of Independent Registered Public Accounting Firm
|
Filed
herewith.
|
|||
|
Consent
of Independent Petroleum Engineers
|
Filed
herewith.
|
|||
|
Consent
of Independent Petroleum Engineers
|
Filed
herewith
|
|||
|
Rule
13a-14(a)/15d-14(a) Certification by Chief Executive
Officer
|
Filed
herewith.
|
|||
|
Rule
13a-14(a)/15d-14(a) Certification by Chief Financial
Officer
|
Filed
herewith.
|
|||
|
Title
18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
Certifications by Chief Executive Officer and Chief Financial
Officer
|
Filed
herewith.
|
PETROLEUM
DEVELOPMENT CORPORATION
Index
to Consolidated Financial Statements and Financial Statement
Schedule
|
1.
|
Financial
Statements:
|
|
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
|
|
Balance
Sheets - December 31, 2006 and 2005
|
F-3
|
|
|
Statements
of Income - Years Ended December 31, 2006, 2005 and 2004
|
F-4
|
|
|
Statements
of Shareholders' Equity - Years Ended December 31, 2006, 2005 and
2004
|
F-5
|
|
|
Statements
of Cash Flows - Years Ended December 31, 2006, 2005 and
2004
|
F-6
|
|
|
Notes
to Consolidated Financial Statements
|
F-7
|
|
|
2.
|
Financial
Statement Schedule:
|
|
|
Valuation
and Qualifying Accounts and Reserves
|
F-38
|
PETROLEUM
DEVELOPMENT CORPORATION
Report
of Independent Registered Public Accounting Firm
The
Board
of Directors and Shareholders
Petroleum
Development Corporation:
We
have
audited the accompanying consolidated balance sheets of Petroleum Development
Corporation and subsidiaries as of December 31, 2006 and 2005, and the related
consolidated statements of income, shareholders' equity, and cash flows for
each
of the years in the three-year period ended December 31, 2006. In connection
with our audits of the consolidated financial statements, we also have audited
the related financial statement schedule. These consolidated financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements and financial statement schedule based on
our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Petroleum Development
Corporation and subsidiaries as of December 31, 2006 and 2005, and the results
of their operations and their cash flows for each of the years in the three-year
period ended December 31, 2006, in conformity with U. S. generally accepted
accounting principles. Also in our opinion, the related financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the
information set forth therein.
As
discussed in Note 1 to the consolidated financial statements, the Company
adopted the provisions of Statement of Financial Accounting Standards No.
123(R), (“Share-Based Payment”), in 2006.
As
discussed in Note 1 to the consolidated financial statements, the Company
changed its method of quantifying errors based on SEC Staff Accounting Bulletin
No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements”) in 2006.
We
also
have audited, in accordance with the standards of Public Company Accounting
Oversight Board (United States), the effectiveness of Petroleum Development
Corporation's internal control over financial reporting as of December 31,
2006,
based on criteria established in Internal Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)
and our report dated May 22, 2007, expressed an unqualified opinion on
management’s assessment of, and an adverse opinion on the effective operation
of, internal control over financial reporting as of December 31,
2006.
KPMG
LLP
Pittsburgh,
Pennsylvania
May
22,
2007
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Balance Sheets
(in
thousands, except share and per share data)
|
December
31,
|
2006
|
2005
|
||||||
|
Assets
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ |
194,326
|
$ |
90,110
|
||||
|
Restricted
cash
|
519
|
1,501
|
||||||
|
Accounts
receivable, net
|
42,600
|
43,248
|
||||||
|
Accounts
receivable - affiliates
|
9,235
|
9,041
|
||||||
|
Inventories
|
3,345
|
5,055
|
||||||
|
Fair
value of derivatives
|
15,012
|
10,382
|
||||||
|
Other
current assets
|
5,977
|
4,640
|
||||||
|
Total
current assets
|
271,014
|
163,977
|
||||||
|
Properties
and equipment, net
|
394,217
|
265,926
|
||||||
|
Restricted/designated
cash
|
192,451
|
-
|
||||||
|
Goodwill
|
6,783
|
-
|
||||||
|
Other
assets
|
19,822
|
14,458
|
||||||
|
Total
Assets
|
$ |
884,287
|
$ |
444,361
|
||||
|
Liabilities
and Shareholders' Equity
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$ |
67,675
|
$ |
55,049
|
||||
|
Short
term debt
|
20,000
|
-
|
||||||
|
Production
tax liability
|
11,497
|
11,758
|
||||||
|
Other
accrued expenses
|
9,685
|
4,141
|
||||||
|
Accounts
payable - affiliates
|
7,595
|
1,479
|
||||||
|
Deferred
gain on sale of leaseholds
|
8,000
|
-
|
||||||
|
Federal
and state income taxes payable
|
28,698
|
8,473
|
||||||
|
Fair
value of derivatives
|
2,545
|
18,424
|
||||||
|
Advances
for future drilling contracts
|
54,772
|
49,999
|
||||||
|
Funds
held for distribution
|
31,367
|
31,417
|
||||||
|
Total
current liabilities
|
241,834
|
180,740
|
||||||
|
Long-term
debt
|
117,000
|
24,000
|
||||||
|
Deferred
gain on sale of leaseholds
|
17,600
|
-
|
||||||
|
Other
liabilities
|
19,400
|
16,184
|
||||||
|
Deferred
income taxes
|
116,393
|
26,889
|
||||||
|
Asset
retirement obligation
|
11,916
|
8,283
|
||||||
|
Total
liabilities
|
524,143
|
256,096
|
||||||
|
Commitments
and contingent liabilities
|
||||||||
|
Shareholders'
equity:
|
||||||||
|
Common
stock, par value $.01 per share;authorized 50,000,000 shares;issued
14,834,871 shares and issued and outstanding 16,281,923
shares
|
148
|
163
|
||||||
|
Additional
paid-in capital
|
64
|
30,423
|
||||||
|
Retained
earnings
|
360,102
|
158,504
|
||||||
|
Unamortized
stock award
|
-
|
(825 | ) | |||||
|
Treasury
shares at cost, 4,706 shares
|
(170 | ) |
-
|
|||||
|
Total
shareholders' equity
|
360,144
|
188,265
|
||||||
|
Total
Liabilities and Shareholders' Equity
|
$ |
884,287
|
$ |
444,361
|
||||
See
accompanying Notes to Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Income
(in
thousands, except per share data)
|
Year
Ended December 31,
|
2006
|
2005
|
2004
|
|||||||||
|
Revenues:
|
||||||||||||
|
Oil
and gas well drilling operations
|
$ |
17,917
|
$ |
99,963
|
$ |
94,076
|
||||||
|
Gas
sales from marketing activities
|
131,325
|
121,104
|
94,627
|
|||||||||
|
Oil
and gas sales
|
115,189
|
102,559
|
69,492
|
|||||||||
|
Well
operations and pipeline income
|
10,704
|
8,760
|
7,677
|
|||||||||
|
Oil
and gas price risk management gains (losses), net
|
9,147
|
(9,368 | ) | (3,085 | ) | |||||||
|
Other
|
2,221
|
2,180
|
1,696
|
|||||||||
|
Total
revenues
|
286,503
|
325,198
|
264,483
|
|||||||||
|
Costs
and expenses:
|
||||||||||||
|
Cost
of oil and gas well drilling operations
|
12,617
|
88,185
|
77,696
|
|||||||||
|
Cost
of gas marketing activities
|
130,150
|
119,644
|
92,881
|
|||||||||
|
Oil
and gas production and well operations cost
|
29,021
|
20,400
|
17,713
|
|||||||||
|
Exploration
cost
|
8,131
|
11,115
|
-
|
|||||||||
|
General
and administrative expense
|
19,047
|
6,960
|
4,506
|
|||||||||
|
Depreciation,
depletion, and amortization
|
33,735
|
21,116
|
18,156
|
|||||||||
|
Total
costs and expenses
|
232,701
|
267,420
|
210,952
|
|||||||||
|
Gain
on sale of leaseholds
|
328,000
|
7,669
|
-
|
|||||||||
|
Income
from operations
|
381,802
|
65,447
|
53,531
|
|||||||||
|
Interest
income
|
8,050
|
898
|
185
|
|||||||||
|
Interest
expense
|
(2,443 | ) | (217 | ) | (238 | ) | ||||||
|
Income
before income taxes
|
387,409
|
66,128
|
53,478
|
|||||||||
|
Income
taxes
|
149,637
|
24,676
|
20,250
|
|||||||||
|
Net
income
|
$ |
237,772
|
$ |
41,452
|
$ |
33,228
|
||||||
|
Basic
earnings per common share
|
$ |
15.18
|
$ |
2.53
|
$ |
2.05
|
||||||
|
Diluted
earnings per common share
|
$ |
15.11
|
$ |
2.52
|
$ |
2.00
|
||||||
See
accompanying Notes to Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Shareholders' Equity
(in
thousands, except share and per share data)
|
Year
Ended December 31,
|
2006
|
2005
|
2004
|
|||||||||
|
Common
stock - shares issued:
|
||||||||||||
|
Shares
at beginning of year
|
16,281,923
|
16,589,824
|
15,628,433
|
|||||||||
|
Adjust
prior conversion of predecessor shares
|
59,546
|
-
|
-
|
|||||||||
|
Exercise
of stock options
|
8,000
|
3,000
|
1,100,000
|
|||||||||
|
Issuance
of stock awards, net of forfeitures
|
112,902
|
20,895
|
23,380
|
|||||||||
|
Retirement
of treasury shares
|
(1,627,500 | ) | (331,796 | ) | (161,989 | ) | ||||||
|
Shares
at end of year
|
14,834,871
|
16,281,923
|
16,589,824
|
|||||||||
|
Treasury
stock:
|
||||||||||||
|
Shares
at beginning of year
|
-
|
-
|
-
|
|||||||||
|
Purchase
of treasury shares
|
(1,627,500 | ) | (331,796 | ) | (161,989 | ) | ||||||
|
Retirement
of treasury shares
|
1,627,500
|
331,796
|
161,989
|
|||||||||
|
Non-employee
directors' deferred compensation plan
|
(4,706 | ) |
-
|
-
|
||||||||
|
Shares
at end of year
|
(4,706 | ) |
-
|
-
|
||||||||
|
Common
shares outstanding
|
14,830,165
|
16,281,923
|
16,589,824
|
|||||||||
|
Common
stock, $.01 par:
|
||||||||||||
|
Balance
at beginning of year
|
$ |
163
|
$ |
166
|
$ |
156
|
||||||
|
Exercise
of stock options
|
-
|
-
|
11
|
|||||||||
|
Issuance
of stock awards, net of forfeitures
|
1
|
-
|
-
|
|||||||||
|
Retirement
of treasury shares
|
(16 | ) | (3 | ) | (1 | ) | ||||||
|
Balance
at end of year
|
148
|
163
|
166
|
|||||||||
|
Additional
paid-in capital:
|
||||||||||||
|
Balance
at beginning of year
|
30,423
|
37,684
|
28,593
|
|||||||||
|
Reclassification
of unearned compensation pursuant to the adoption of SFAS No. 123(R)
|
(825 | ) |
-
|
-
|
||||||||
|
Exercise
of stock options
|
31
|
12
|
4,981
|
|||||||||
|
Issuance
of stock awards, net of forfeitures
|
(1 | ) |
-
|
-
|
||||||||
|
Stock
based compensation expense
|
1,516
|
603
|
871
|
|||||||||
|
Retirement
of treasury shares
|
(31,150 | ) | (7,876 | ) | (4,156 | ) | ||||||
|
Excess
tax benefit of stock based compensation
|
70
|
-
|
7,395
|
|||||||||
|
Balance
at end of year
|
64
|
30,423
|
37,684
|
|||||||||
|
Retained
earnings:
|
||||||||||||
|
Balance
at beginning of year
|
158,504
|
117,052
|
83,824
|
|||||||||
|
Cumulative
effect adjustment for the adoption of SAB 108, net of tax
|
(1,021 | ) |
-
|
-
|
||||||||
|
Retirement
of treasury shares
|
(35,153 | ) |
-
|
-
|
||||||||
|
Net
income
|
237,772
|
41,452
|
33,228
|
|||||||||
|
Balance
at end of year
|
360,102
|
158,504
|
117,052
|
|||||||||
|
Unamortized
stock award
|
||||||||||||
|
Balance
at beginning of year
|
(825 | ) | (882 | ) | (15 | ) | ||||||
|
Issuance
of stock awards
|
-
|
(603 | ) | (871 | ) | |||||||
|
Amortization
of stock awards
|
-
|
660
|
4
|
|||||||||
|
Reclassification
of unearned compensation pursuant to the adoption of SFAS No. 123(R)
|
825
|
-
|
-
|
|||||||||
|
Balance
at end of year
|
-
|
(825 | ) | (882 | ) | |||||||
|
Treasury
stock, at cost:
|
||||||||||||
|
Balance
at beginning of year
|
-
|
-
|
-
|
|||||||||
|
Purchase
of treasury shares
|
(66,319 | ) | (7,879 | ) | (4,157 | ) | ||||||
|
Retirement
of treasury shares
|
66,319
|
7,879
|
4,157
|
|||||||||
|
Non-employee
directors' deferred compensation plan
|
(170 | ) |
-
|
-
|
||||||||
|
Balance
at end of year
|
(170 | ) |
-
|
-
|
||||||||
|
Total
shareholders' equity
|
$ |
360,144
|
$ |
188,265
|
$ |
154,020
|
||||||
See
accompanying Notes to Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
Consolidated
Statements of Cash Flows
(in
thousands)
|
Year
Ended December 31,
|
2006
|
2005
|
2004
|
|||||||||
|
Cash
flows from operating activities:
|
||||||||||||
|
Net
income
|
$ |
237,772
|
$ |
41,452
|
$ |
33,228
|
||||||
|
Adjustments
to net income to reconcile to net cash provided by (used in) operating
activities:
|
||||||||||||
|
Deferred
income taxes
|
86,431
|
3,351
|
9,887
|
|||||||||
|
Depreciation,
depletion and amortization
|
33,735
|
21,116
|
18,156
|
|||||||||
|
Impairment
of oil and gas properties
|
1,519
|
-
|
-
|
|||||||||
|
Accretion
of asset retirement obligation
|
515
|
465
|
436
|
|||||||||
|
Dry
hole costs
|
1,790
|
11,115
|
-
|
|||||||||
|
Gain
from sale of leaseholds
|
(328,000 | ) | (7,669 | ) |
-
|
|||||||
|
Loss
(gain) from sale of assets
|
9
|
(207 | ) | (32 | ) | |||||||
|
Expired
and abandoned leases
|
2,169
|
48
|
301
|
|||||||||
|
Amortization
of stock award
|
1,516
|
660
|
4
|
|||||||||
|
Unrealized
(gains) losses on derivative transactions
|
(7,620 | ) |
3,226
|
535
|
||||||||
|
Changes
in current assets and liabilities:
|
||||||||||||
|
Decrease
(increase) in restricted cash
|
982
|
(836 | ) |
1,201
|
||||||||
|
Increase
in accounts receivable
|
(9,935 | ) | (11,811 | ) | (11,391 | ) | ||||||
|
Increase
in accounts receivable - affiliates
|
(194 | ) | (5,319 | ) | (1,482 | ) | ||||||
|
Decrease
(increase) in inventories
|
1,987
|
(3,398 | ) |
357
|
||||||||
|
(Increase)
decrease in other current assets
|
(2,106 | ) |
3,482
|
4,776
|
||||||||
|
(Decrease)
increase in production tax liability
|
(261 | ) |
3,317
|
8,441
|
||||||||
|
Increase
in accounts payable and accrued expenses
|
13,010
|
19,440
|
11,648
|
|||||||||
|
Increase
in accounts payable - affiliates
|
6,116
|
112
|
745
|
|||||||||
|
Increase
(decrease) in advances for future drilling contracts
|
4,773
|
7,502
|
(7,961 | ) | ||||||||
|
Increase
in federal and state income taxes payable
|
19,880
|
8,473
|
-
|
|||||||||
|
(Decrease)
increase in funds held for future distribution
|
(575 | ) |
18,505
|
4,501
|
||||||||
|
Other
|
3,877
|
(652 | ) | (49 | ) | |||||||
|
Net
cash provided by operating activities
|
67,390
|
112,372
|
73,301
|
|||||||||
|
Cash
flows from investing activities:
|
||||||||||||
|
Capital
expenditures
|
(146,180 | ) | (97,390 | ) | (44,762 | ) | ||||||
|
Acquisition
of Unioil, net of cash acquired
|
(18,512 | ) |
-
|
-
|
||||||||
|
Investment
in drilling partnerships
|
(7,151 | ) | (7,160 | ) |
3,540
|
|||||||
|
Exploration
costs
|
(765 | ) | (1,918 | ) | (4,170 | ) | ||||||
|
(Increase)
decrease in restricted/designated cash
|
(192,416 | ) |
-
|
-
|
||||||||
|
Proceeds
from sale of leases to partnerships
|
1,798
|
2,829
|
1,951
|
|||||||||
|
Proceeds
from sale of leaseholds/assets
|
353,600
|
9,597
|
95
|
|||||||||
|
Net
cash provided by (used in) investing activities
|
(9,626 | ) | (94,042 | ) | (43,346 | ) | ||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Proceeds
from debt
|
302,000
|
91,000
|
84,000
|
|||||||||
|
Proceeds
from short-term debt
|
20,000
|
-
|
-
|
|||||||||
|
Retirement
of debt
|
(209,000 | ) | (88,000 | ) | (116,000 | ) | ||||||
|
Payment
of debt issuance costs
|
(160 | ) | (423 | ) | (233 | ) | ||||||
|
Proceeds
from issuance of stock
|
31
|
12
|
3,584
|
|||||||||
|
Excess
tax benefits from stock-based compensation
|
70
|
-
|
-
|
|||||||||
|
Purchase
of treasury stock
|
(66,489 | ) | (7,879 | ) | (2,749 | ) | ||||||
|
Net
cash provided by (used in) financing activities
|
46,452
|
(5,290 | ) | (31,398 | ) | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
104,216
|
13,040
|
(1,443 | ) | ||||||||
|
Cash
and cash equivalents, beginning of period
|
90,110
|
77,070
|
78,513
|
|||||||||
|
Cash
and cash equivalents, end of period
|
$ |
194,326
|
$ |
90,110
|
$ |
77,070
|
||||||
|
Supplemental
disclosures of cash flow information:
|
||||||||||||
|
Cash
paid during the period for:
|
||||||||||||
|
Income
taxes
|
$ |
46,735
|
$ |
10,675
|
$ |
5,028
|
||||||
|
Interest
|
$ |
3,011
|
$ |
101
|
$ |
1,049
|
||||||
See
accompanying Notes to Consolidated Financial Statements.
PETROLEUM
DEVELOPMENT CORPORATION
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Petroleum
Development Corporation (“PDC” or “the Company”) is an independent energy
company engaged primarily in the drilling and 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 operates
approximately 3,100 wells located in the Appalachian Basin, Michigan, and the
Rocky Mountain Region. All of the Company's oil and gas wells are located in
West Virginia, Tennessee, Pennsylvania, Michigan, North Dakota, Colorado, Kansas
and Wyoming. The Company's operations are divided into four business segments:
drilling and development, natural gas marketing, oil and gas sales and well
operations and pipeline income. See Note 17.
Principles
of Consolidation
The
accompanying consolidated financial statements include the accounts of
PDC
and its
wholly owned subsidiaries, Riley Natural Gas (“RNG”), Unioil and PDC
Securities Incorporated. All material intercompany accounts and transactions
have been eliminated in consolidation. The Company accounts for its investment
in interests in oil and gas limited partnerships under the proportionate
consolidation method. Under this method, the Company’s consolidated financial
statements include its pro rata share of assets, liabilities and revenues and
expenses respectively of the limited partnerships in which it participates.
The
Company’s proportionate share of all significant transactions between the
Company and the limited partnerships is eliminated.
Cash
Equivalents
For
purposes of the statement of cash flows, the Company considers all highly liquid
debt instruments with original maturities of three months or less to be cash
equivalents.
Restricted
and Designated Cash
In
July
2006, the Company established a trust in the amount of $300 million with a
qualified intermediary in conjunction with its sale of undeveloped leaseholds
and corresponding “like-kind exchange” agreement. As of December 31, 2006, $300
million remains in the trust, with $109 million reflected in cash and cash
equivalents as a current asset in the consolidated balance sheet and the
remaining $191.5 million reflected as designated cash - property acquisitions,
a
non-current asset. The $191.5 million represents the amounts paid in January
2007 for the acquisition of oil and gas properties qualifying for "like-kind
exchange" treatment. Interest earned on the trust account of $5.5 million is
reflected in cash and cash equivalents as a current asset, along with the $109
million not utilized for "like-kind exchange" (“LKE”) purchases, will be
available to the Company for operating purposes in January 2007 and is no longer
subject to a LKE. See Note 15 and Note 16.
In
December 2006, the Company had paid a deposit of $0.5 million, reflected in
the
consolidated balance sheet as designated cash, a non-current asset, for the
acquisition of oil and gas properties subsequently closed in January
2007.
The
Company is required to maintain margin deposits with brokers for outstanding
derivative contracts. As of December 31, 2006 and 2005, cash in the amount
of
$0.5 million and $1.5 million, respectively, was on deposit and reflected in
the
consolidated balance sheets as restricted cash, a current asset.
The
Company is required by various government agencies or joint venture agreements
to maintain a bond or cash account for the plugging and abandonment of wells.
As
of December 31, 2006, the Company had bonds and cash accounts restricted for
plugging and abandonment of wells totaling $1.0 million, which are reflected
in
restricted/designated cash, a non-current asset.
Inventories
Materials,
supplies and commodity inventories are stated at the lower of average cost
or
market and removed at carrying value.
Oil
and Gas Properties
The
Company accounts for its oil and gas properties under the successful efforts
method of accounting. Costs of proved developed producing properties, successful
exploratory wells and development dry hole costs are depreciated or depleted
by
the unit-of-production method based on estimated proved developed producing
oil
and gas reserves. Property acquisition costs are depreciated or depleted on
the
unit-of-production method based on estimated proved oil and gas reserves. The
Company obtains new reserve reports from independent petroleum engineers
annually as of December 31 of each year. The Company adjusts oil and gas
reserves for any major acquisitions, new drilling and divestitures during the
year as needed.
PETROLEUM
DEVELOPMENT CORPORATION
Exploration
costs, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory well drilling costs, including
the
cost of stratigraphic test wells, are initially capitalized but charged to
expense if the well is determined to be nonproductive. The status of each
in-progress well is reviewed quarterly to determine the proper accounting
treatment under the successful efforts method of accounting. Exploratory well
costs continue to be capitalized as long as the well has found a sufficient
quantity of reserves to justify its completion as a producing well and the
Company is making sufficient progress assessing its reserves and economic and
operating viability. If an in-progress exploratory well is found to be
unsuccessful (referred to as a dry hole) prior to the issuance of the Company’s
financial statements, the costs are expensed to exploration costs. If management
is unable to make a final determination about the productive status of a well
prior to issuance of the Company’s financial statements, the cost of the well is
classified as part of “Suspended Well Costs” until management has had sufficient
time to conduct additional completion or testing operations to evaluate the
pertinent geological and engineering data obtained. At the time when management
is able to make a final determination of a well’s productive status, the well is
removed from the suspended well status and the proper accounting treatment
is
recorded based on that determination. The determination of an exploratory well's
ability to produce is generally made within one year from the completion of
drilling activities. See Note 18.
The
acquisition costs of unproved properties are capitalized when incurred, until
such properties are transferred to proved properties or charged to expense
when
expired, impaired or amortized. Unproved oil and gas properties with
individually significant acquisition costs are periodically assessed, and any
impairment in value is charged to expense. The amount of impairment recognized
on unproved properties which are not individually significant is determined
by
amortizing the costs of such properties within appropriate fields based on
the
Company's historical experience, acquisition dates and average lease terms.
Amortization of remaining lease costs for all other insignificant properties
is
recorded over the average remaining lives of the leases. The valuation of
unproved properties is subjective and requires management of the Company to
make
estimates and assumptions which, with the passage of time, may prove to be
materially different from actual realizable values.
Upon
sale
or retirement of significant portions of or complete fields of depreciable
or
depletable property, the net book value thereof, less proceeds or salvage value,
is credited or charged to income. Upon sale of individual wells, the proceeds
are credited to property costs.
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 production to be sold.
These estimates of future production prices may differ from current market
prices of oil and gas. Any downward revisions to management's estimates of
future production or prices could result in an impairment of the Company's
oil
and gas properties in subsequent periods. If net capitalized costs exceed
undiscounted future net cash flows, the measurement of impairment is based
on
estimated fair value which would consider future discounted cash flows. In
2006,
the Company recognized an impairment loss on oil and gas properties of $1.5
million, which is included in the statement of income as a component of
exploration cost.
Transportation
Equipment, Pipelines and Other Equipment
Transportation
equipment, pipelines and other equipment are carried at cost. Depreciation
is
provided principally on the straight-line method over useful lives of 3 to
17
years. In accordance with Statement of Financial Accounting Standards (“SFAS”)
No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets,
long-lived assets, such as property, plant and equipment, are reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Recoverability of assets
to
be held and used is measured by a comparison of the carrying amount of an asset
to estimated undiscounted future cash flows expected to be generated by the
asset. If the carrying amount of an asset exceeds its estimated future cash
flows, an impairment charge is recognized in the amount by which the carrying
amount of the asset exceeds the fair value of the asset.
Maintenance
and repairs are charged to expense as incurred. Major renewals and improvements
are capitalized. Upon the sale or other disposition of assets, the cost and
related accumulated depreciation, depletion and amortization are removed from
the accounts, the proceeds are applied thereto and any resulting gain or loss
is
reflected in income.
Capitalized
Interest
Interest
costs are capitalized as part of the historical cost of acquiring assets. Oil
and gas investments in unproved properties and major development projects,
on
which depreciation, depletion and amortization expense is not currently recorded
and on which exploration or development activities are in progress, qualify
for
capitalization of interest. Major construction projects also qualify for
interest capitalization until the asset is ready for service. Capitalized
interest is calculated by multiplying the Company's weighted-average interest
rate on its debt by the qualifying costs. Interest capitalized may not exceed
gross interest expense for the period. As the qualifying asset is moved to
the
depreciation, depletion and amortization pool, the related capitalized interest
is also transferred and is amortized over the useful life of the asset. Interest
costs of $1.6 million were capitalized during 2006. No interest costs were
capitalized during 2005 or 2004.
PETROLEUM
DEVELOPMENT CORPORATION
Goodwill
Goodwill
represents the excess of the aggregate purchase price over the fair value of
the
net assets acquired in a purchase business combination. The acquisition of
Unioil in December 2006 resulted in the recognition of goodwill in the amount
of
$6.8 million. The goodwill has been allocated to the oil and gas sales segment.
In accordance with SFAS No. 142, Goodwill
and Other Intangible Assets,
goodwill will be tested at least annually for impairment. See Note
2.
Buildings
Buildings
are carried at cost and depreciated on the straight-line method over estimated
useful lives of 30 years.
Asset
Retirement Obligations
The
Company accounts for asset retirement obligations by recording the fair value
of
its plugging and abandonment obligations when incurred, which is at the time
the
well is completely drilled. Upon initial recognition of an asset retirement
obligation, the Company increases the carrying amount of the long-lived asset
by
the same amount as the liability. Over time, the liabilities are accreted for
the change in their present value, through charges to oil and gas production
and
well operations costs. The initial capitalized costs are depleted over the
useful lives of the related assets, through charges to depreciation, depletion
and amortization. If the fair value of the estimated asset retirement obligation
changes, an adjustment is recorded to both the asset retirement obligation
and
the asset retirement cost. Revisions in estimated liabilities can result from
revisions of estimated inflation rates, escalating retirement costs and changes
in the estimated timing of settling asset retirement obligations. See Note
7 for
a reconciliation of asset retirement obligation activity.
Production
Tax Liability
Production
tax liability represents estimated taxes, primarily severance and property,
to
be paid to the states and counties in which the Company produces oil and gas.
The Company's share of these taxes is expensed to oil and gas production and
well operations cost.
Advances
for Future Drilling Contracts
Advances
for future drilling contracts represent deferred revenues arising from funds
being received from partnerships and other joint ventures for drilling
activities which have not been completed and accordingly have not yet been
recognized as revenue in accordance with the Company's revenue recognition
policies.
Retirement
of Treasury Shares
The
Company has historically retired all treasury share purchases, with the
exception of shares purchased in accordance with its non-employee deferred
compensation plan for non-employee directors, see Note 9. As treasury shares
are
retired, the Company charges any excess of cost over the par value entirely
to
additional paid-in-capital, to the extent the Company has amounts in
paid-in-capital, with any remaining excess cost being charged to retained
earnings.
Revenue
Recognition
The
Company's drilling segment recognizes revenue from drilling contracts with
sponsored drilling programs using the percentage of completion method based
upon
the percentage of contract costs incurred to date to the estimated total
contract costs for each contract. The Company utilizes this method since
reasonably dependable estimates of the total estimated costs can be made and
recognized revenues are subject to revisions as a contract progresses, the
term
of which can range from three to twelve months. In addition, the Company offers
its drilling services under two types of contractual arrangements, cost-plus
or
footage-based service contracts, which result in differing risk and reward
relationships, and hence, different revenue reporting policies pursuant to
Emerging Issues Task Force (“EITF”) No. 99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent.
PETROLEUM
DEVELOPMENT CORPORATION
The
first
cost-plus drilling service arrangement was initially entered into in late 2005
with drilling activity commencing in the first quarter of 2006. Although the
Company acts as a principal in the transaction and takes title to products
and
services acquired necessary for drilling, the Company acts as an agent, with
little risk of loss during the performance of the drilling activities.
Consistent with the provisions of EITF 99-19, the Company’s services provided
under the cost-plus drilling agreements are reported net of recovered costs.
The
Company entered into its second cost-plus drilling arrangement in September
2006
and commenced drilling immediately. It is the Company’s intent that all future
drilling arrangements will be on a cost-plus basis.
Footage-based
contracts provide for the drilling, completion and equipping of wells at footage
rates and are generally completed within nine to twelve months after the
commencement of drilling. The Company provides geological, engineering, and
drilling supervision on the drilling and completion process and uses
subcontractors to perform drilling and completion services and accordingly
has
risk of loss in performing services under these arrangements. Accordingly,
the
Company reports revenue under these agreements gross of related expenses.
Anticipated losses, if any, on uncompleted contracts are recorded at the time
that the estimated total costs exceed the estimated total contract revenue.
At
December 31, 2006 and 2005, the loss contract reserve was $0.3 million and
$0.8
million, respectively.
Natural
gas marketing is reported on the gross accounting method, based on the nature
of
the agreements between RNG, its suppliers and its customers. RNG, the Company’s
marketing subsidiary, purchases gas from many small producers and bundles the
gas together to sell in larger amounts to purchasers of natural gas for a price
advantage. RNG has latitude in establishing price and discretion in supplier
and
purchaser selection. Natural gas marketing revenues and expenses reflect the
full cost and revenue of those transactions because RNG takes title to the
gas
it purchases from the various producers and bears the risks and rewards of
that
ownership. Both the realized and unrealized gains or losses of the RNG commodity
based derivative transactions for natural gas marketing activities are included
in gas sales from marketing activities or cost of gas marketing activities,
as
applicable.
Sales
of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection
of revenue from the sale is reasonably assured and the sales price is fixed
or
determinable. Natural gas is sold by the Company under contracts with terms
ranging from one month to three years. Virtually all of the Company’s contract
pricing provisions are tied to a market index, 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 believes that the pricing provisions of its natural gas
contracts are customary in the industry.
The
Company currently uses the “net-back” method of accounting for transportation
arrangements of its natural gas sales. The Company sells gas at the wellhead
and
collects a price and recognizes revenues based on the wellhead sales price
since
transportation costs downstream of the wellhead are incurred by the customers
and reflected in the wellhead price.
Sales
of
oil are recognized when persuasive evidence of a sales arrangement exists,
the
oil is verified as produced and is delivered to a purchaser, collection of
revenue from the sale is reasonably assured and the sales price is determinable.
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
at prices and in accordance with arrangements that are customary in the oil
industry.
Well
operations and pipeline income are recognized when persuasive evidence of an
arrangement exists, services have been rendered, collection of revenues is
reasonably assured and the sales price is fixed or determinable. The Company
is
paid a monthly operating fee for each well it operates for outside owners
including the limited partnerships sponsored by the Company. The fee covers
monthly operating and accounting costs, insurance and other recurring costs.
The
Company may also receive additional compensation for special non-recurring
activities, such as reworks and recompletions.
Income
Taxes
Income
taxes are accounted for under the asset and liability method.
Deferred
tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts
of
existing assets and liabilities and their respective tax bases. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply
to
taxable income in the years in which those temporary differences are expected
to
be recovered or settled. The effect on deferred tax assets and liabilities
of a
change in tax rates is recognized in income in the period that includes the
enactment date.
PETROLEUM
DEVELOPMENT CORPORATION
Derivative
Financial Instruments
The
Company accounts for derivative financial instruments in accordance with SFAS
No. 133, Accounting
for Derivative Instruments and Certain Hedging Activities,
as
amended.
During
2006, 2005 and 2004, none of the Company's derivative instruments qualified
for
use of hedge accounting under the terms of SFAS No. 133. Accordingly, the
Company recognizes all derivative instruments as either assets or liabilities
on
the consolidated balance sheets at fair value and changes in the derivatives'
fair values are recorded in the consolidated statements of income in oil and
gas
price risk management, net for the Company’s oil and gas commodities
(derivatives related to the Company's production only), in gas sales from
marketing activities for RNG’s gas sales, in cost of gas marketing activities
for RNG’s gas purchases and in interest expense for the Company’s interest rate
swap (2004 only), as applicable. See Note 14.
In
the
accompanying consolidated balance sheets, the Company records the fair value
of
derivatives entered into on behalf of the affiliated partnerships and records
an
offsetting receivable from or payable to the partnerships. See Note
11.
Stock-Based
Compensation
Effective
January 1, 2006, the Company adopted Statement SFAS No. 123(R), Share-Based
Payment (revised 2004).
The
Company elected the modified prospective method of adoption, and accordingly,
prior period financial statements have not been restated. Pursuant to SFAS
No.
123(R) the Company is required to recognize in its financial statements, based
on fair value, compensation expense for all unvested stock options and other
equity-based awards as of January 1, 2006. For all unvested options outstanding
as of January 1, 2006 the previously measured but unrecognized compensation
expense, based on the fair value at the original grant date, will be recognized
in the financial statements over the remaining requisite service period for
each
separately vesting portion. For equity-based compensation awards granted or
modified subsequent to January 1, 2006, compensation expense, based on the
fair
value on the date of grant or modification, will be recognized in the financial
statements on a straight-line basis over the vesting period for the entire
award. To the extent compensation cost relates to employees directly involved
in
oil and natural gas acquisition, exploration and development activities, such
amounts are capitalized to properties and equipment. Amounts not capitalized
to
properties and equipment are recognized in the appropriate cost and expense
line
item in the statement of income. For the year ended December 31, 2006, the
Company recognized stock-based compensation expense of $0.1 million and $1.4
million related to stock option and restricted stock awards, respectively.
Compensation capitalized as part of properties and equipment was immaterial
in
2006.
For
periods prior to the adoption of SFAS No. 123(R), the Company accounted for
its
share-based compensation awards using the intrinsic value based method as
prescribed by Accounting Principles Board Opinion ("APB") No. 25, Accounting
for Stock Issued to Employees,
and
related interpretations. Under the intrinsic value based method, compensation
expense for option awards was recorded on the date of grant only if the
then-current market price of the underlying stock exceeded the exercise price.
The following table illustrates the effect on net income and earnings per share
had the Company applied the fair value recognition provisions of SFAS No.
123(R), as amended, to stock-based employee compensation during 2005 and 2004
(in thousands, except per share data):
|
Year
ended
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Net
income, as reported:
|
$
|
41,452
|
$
|
33,228
|
|||
|
Stock-based
compensation expense included in reported net income, net of
tax
|
414
|
2
|
|||||
|
Total
stock-based compensation expense determined under fair value
method
|
(509
|
)
|
(21
|
)
|
|||
|
Pro
forma net income
|
$
|
41,357
|
$
|
33,209
|
|||
|
Earnings
per share:
|
|||||||
|
Basic
earnings per share, as reported and pro forma
|
$
|
2.53
|
$
|
2.05
|
|||
|
Diluted
earnings per share, as reported and pro forma
|
$
|
2.52
|
$
|
2.00
|
|||
Earnings
Per Share
The
Company's basic earnings per share ("EPS") amounts have been computed based
on
the average number of shares of common stock outstanding for the period. Diluted
EPS amounts include the effect of the Company's outstanding stock options,
unamortized portion of restricted stock and shares held pursuant to the
Company's non-employee director deferred compensation plan using the treasury
stock method if including such potential shares of common stock is dilutive.
See
Note 10.
PETROLEUM
DEVELOPMENT CORPORATION
Use
of Estimates
The
preparation of the consolidated financial statements in accordance with
generally accepted accounting principles in the United States of America
requires management of the Company to make estimates and assumptions that affect
the amounts reported in the consolidated financial statements and accompanying
notes. Actual results could differ from those estimates. Estimates which are
particularly significant to the consolidated financial statements include
estimates of oil and gas reserves, future cash flows from oil and gas properties
valuation of derivative instruments and valuation of deferred income tax
assets.
Fair
Value of Financial Instruments
The
carrying values of the Company's receivables, payables and debt obligations
approximate fair value as of December 31, 2006 and 2005, due to the short-term
maturity of these instruments.
Reclassifications
Reclassifications
to conform to current year presentation
Certain
prior year amounts were reclassified to conform to the current year
presentation. The reclassifications had no impact on reported net earnings,
earnings per share, shareholders’ equity or cash flows from operating
activities.
|
·
|
Oil
and gas price risk management losses of $9.4 million and $3.1 million
for
2005 and 2004, respectively, have been reclassified from non-operating
losses to a component of (and an offset to)
revenues.
|
|
·
|
As
of December 31, 2005, investment in drilling partnerships, a long-term
asset, in the amount of $11.2 million has been reclassified from
properties and equipment, net, also a long-term asset, to other long-term
assets.
|
Reclassifications
to correct prior year amounts
Certain
prior year amounts were reclassified to correct prior year amounts. These
correcting reclassifications were immaterial and had no impact on reported
net
earnings, earnings per share, shareholders' equity or cash flows from operating
activities.
|
·
|
Accretion
expense related to the Company’s asset retirement obligation in the amount
of $0.5 million and $0.4 million, respectively for the years 2005
and
2004, has been reclassified from interest expense, a non-operating
expense, to oil and gas production and well operations cost, a component
of income from operations.
|
|
·
|
Interest
income in the amount of $0.9 million, and $0.2 million, respectively
for
the years 2005 and 2004, has been reclassified from other income,
a
component of revenues, to interest income, a non-operating income
item.
|
|
·
|
Gain
on sale of leaseholds in the amount of $7.7 million for the year
2005 has
been reclassified from other income to gain on sale of leaseholds,
with no
impact on income from operations.
|
|
·
|
As
of December 31, 2005, production taxes relating to accrued oil and
gas
revenues in the amount of $3.8 million previously reported as a reduction
of accounts receivable have been reclassified to production tax liability.
|
|
·
|
As
of December 31, 2005, production receivables in the amount of $1.8
million
were reclassified from accounts receivable to accounts receivable
-
affiliates.
|
|
·
|
As
of December 31, 2005, the Company did not appropriately eliminate
a
portion of its intercompany accounts receivable and accounts payable;
accordingly, the Company reduced it accounts receivable and accounts
payable balances by $8.5 million, resulting in the elimination of
all
material intercompany transactions.
|
|
·
|
In
connection with the production tax withheld adjustment discussed
below
under the caption Recently Adopted Accounting Standards, $22.1 million
has
been reclassified from production tax liability to other liability
line
items as of December 31, 2005. Of this amount, $9.1 million has been
reclassified to other long-term liability to reflect production tax
obligations as of December 31, 2005, that are not payable until 2007
and
$13 million, representing amounts due to drilling partnership limited
partners as a result of over withholding of estimated production
taxes by
the Company, has been reclassified to funds held for
distribution.
|
Recent
Accounting Standards
Recently
Adopted Accounting Standards
In
December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No.
123(R), Share-Based
Payment.
In
March 2005, the Securities and Exchange Commission (“SEC”) issued Staff
Accounting Bulletin (“SAB”) No. 107, Share-Based
Payment,
regarding the interaction between SFAS No. 123(R) and certain SEC rules and
regulations. Effective January 1, 2006, the Company adopted SFAS No. 123(R).
The
Company elected to use the modified prospective method for adoption, which
requires compensation expense to be recognized in the statement of income for
all unvested stock options and other equity-based compensation beginning in
the
first quarter of adoption. Prior to the adoption of SFAS No. 123(R), the Company
followed the intrinsic value method in accordance with APB No. 25 (as amended)
to account for employee stock-based compensation. The adoption of SFAS No.
123(R) required the unamortized stock award recorded under APB No. 25 related
to
stock-based compensation awards as of January 1, 2006, in the amount of $0.8
million to be eliminated against additional paid-in-capital. See Stock-Based
Compensation
policy
above and Note 8 for further discussion of the Company's accounting for
share-based compensation awards.
PETROLEUM
DEVELOPMENT CORPORATION
In
June
2005, the FASB issued SFAS No. 154, Accounting
Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB
Statement No. 3,
which
replaces APB No. 20, Accounting
Changes,
and
SFAS No. 3, Reporting
Accounting Changes in Interim Financial Statements,
and
changes the requirements for the accounting for and reporting of a change in
accounting principle. SFAS No. 154 requires retrospective application for
voluntary changes in accounting principle unless it is impracticable to do
so,
and it applies to all voluntary changes in accounting principle in addition
to
changes required by an accounting pronouncement in the unusual instance that
the
pronouncement does not include specific transition provisions. SFAS No. 154
became effective for accounting changes and corrections of errors made in fiscal
years beginning after December 15, 2005. The January 1, 2006, adoption of SFAS
No. 154 did not have a material impact on the Company's consolidated financial
statements.
In
September 2006, the SEC issued SAB No. 108, Considering
the Effects of Prior Year Misstatements when Quantifying Misstatements in
Current Year Financial Statements.
SAB No.
108 provides guidance on how the effects of prior year misstatements should
be
considered in quantifying misstatements in the current year financial
statements. SAB No. 108 requires registrants to quantify misstatements using
both the income statement (“rollover”) and balance sheet (“iron curtain”)
approach and evaluate whether either approach results in a misstatement that,
when all relevant quantitative and qualitative factors are considered, is
material. Historically, the Company evaluated uncorrected misstatements using
the “rollover” method which resulted in an accumulation of quantitatively and
qualitatively immaterial misstatements to the Company’s consolidated financial
statements. SAB No. 108 provides for a one time transitional adjustment to
retained earnings for errors which were not deemed material to prior year
financial statements, but which are material under guidance of SAB No. 108.
The
Company adopted SAB No. 108 during the fourth quarter of 2006 and recorded
the
effect of the following identified items as a cumulative effect adjustment
to
retained earnings effective January 1, 2006 for periods through December 31,
2005 (in thousands):
|
Increase/
(Decrease)
|
||||
|
Pre-tax
adjustments:
|
||||
|
Employee
benefits payable (1)
|
$
|
(470
|
)
|
|
|
Accrued
performance supplement (2)
|
(464
|
)
|
||
|
Deferred
compensation retirement liability (3)
|
(961
|
)
|
||
|
Accounting
for oil inventory (4)
|
(1,172
|
)
|
||
|
Fair
value of derivatives (5)
|
(487
|
)
|
||
|
Oil
and gas properties, net (6)
|
(1,402 | ) | ||
|
Funds
held for distribution (7)
|
(778
|
)
|
||
|
Funds
held pending a division order (8)
|
377
|
|||
|
Interest
income recognition (9)
|
136
|
|||
|
Accrued
gas marketing (10)
|
(15
|
)
|
||
|
Accrued
oil and gas production costs (11)
|
878
|
|||
|
Unclaimed
property liabilities (12)
|
(124
|
)
|
||
|
Production
taxes withheld (13)
|
5,003
|
|||
|
Accrued
franchise tax (14)
|
(52
|
)
|
||
|
Prepaid
well costs (15)
|
(274
|
)
|
||
|
Accrued
production taxes (16)
|
(1,445
|
)
|
||
|
(1,250
|
) | |||
|
Tax
effect (17)
|
229
|
|
||
|
Decrease
to shareholders' equity as of January 1, 2006
|
$
|
(1,021
|
)
|
|
____________________
|
(1)
|
Employee
benefits payable - The Company understated employee benefits payable
as a
result of errors in its calculation of certain 401k plan provisions.
These
errors originated in 1997 and continued through December 31, 2005.
|
|
(2)
|
Oil
and gas partnership performance liability - The Company understated
oil
and gas partnership performance liability as a result of recognizing
its
cost on a cash basis instead of accruing the cost in the period in
which
the cost was incurred. This misstatement originated in 1996 and continued
through June 30, 2006.
|
PETROLEUM
DEVELOPMENT CORPORATION
|
(3)
|
Deferred
compensation retirement liabilities - The Company understated its
deferred
compensation and medical benefits liability as a result of errors
in the
calculation of the escalation provision in the deferred compensation
plan
and understated its post retirement medical benefits liability as
a result
of recognizing its cost on a cash basis for certain employment contracts.
This misstatement originated in 2000 and continued through September
30,
2006.
|
|
(4)
|
Accounting
for oil inventory - The Company overstated accounts receivable and
understated its inventory as a result of recognizing oil revenues
when
production was delivered to Company owned storage tanks. This misstatement
originated in 1999 and continued through September 30,
2006.
|
|
(5)
|
Fair
value of derivatives - The Company overstated the fair value of its
purchase of certain put option contracts as a result of errors in
its
premium amortization calculation. This misstatement originated in
2005 and
continued through September 30,
2006.
|
|
(6)
|
Oil
and gas properties, net – The Company capitalized certain overhead cost
which, under the successful efforts method of accounting for oil
and gas
properties, should have been expensed in the period
incurred. This misstatement originated in 2001 and continued
through September 30,
2006.
|
|
(7)
|
Funds
held for distribution liability - The Company understated its funds
held
for distribution liability as a result of errors in the processing
of
certain transactions and un-reconciled differences between certain
control
and subsidiary accounts. This misstatement originated in years prior
to
2002 and continued through September 30,
2006.
|
|
(8)
|
Funds
held pending a division order - The Company overstated its funds
held for
distribution liability and understated its portion of oil and gas
revenue
and corresponding production taxes as a result of not accruing oil
and gas
production proceeds that had been received but held for distribution
due
to a lack of a division order. This misstatement originated in years
prior
to 2002 and continued through September 30,
2006.
|
|
(9)
|
Accrued
interest income - The Company understated accounts receivable affiliates
as a result of recognizing the Company’s portion of affiliate interest
income on a cash basis. This misstatement originated in 2005 and
continued
through September 30, 2006.
|
|
(10)
|
Gas
marketing liabilities - The Company understated gas marketing liabilities
as a result of errors in its calculation of the timing of services
provided. This misstatement originated in 2004 and continued through
September 30, 2006.
|
|
(11)
|
Accrued
oil and gas production costs - The Company overstated production
tax
liability, a current liability, by over accruing fuel usage costs.
This
misstatement originated in 2003 and continued through September 30,
2006.
|
|
(12)
|
Unclaimed
property liability - The Company understated accrued expenses as
a result
of errors in its calculation of unclaimed property liability. This
misstatement originated in 1995 and continued through September 30,
2006.
|
|
(13)
|
Production
taxes withheld - The Company over-withheld production tax obligations
related to oil and gas production proceeds distributed by the Company
in
years prior to 2002 to September 30, 2006. As a result, the Company
overstated its oil and gas production and well operations cost and,
in its
capacity as well operator, the Company over-withheld from the revenue
distributions made to drilling partnership limited partners (see
reclassification above). The Company has accrued and will distribute
foregone interest to the limited partners and has also accrued estimated
penalties and interest that are likely to result from this item.
This
misstatement originated in 2001 and continued through September 30,
2006.
|
|
(14)
|
Franchise
tax liabilities - The Company understated franchise tax liabilities
as a
result of recognizing certain of its liabilities on a cash basis.
This
misstatement originated in 2005 and continued through September 30,
2006.
|
|
(15)
|
Prepaid
well costs - The Company overstated prepaid well costs as a result
of
errors in accounting for the expiration and abandonment of well drill
sites. This misstatement originated in 2004 and continued through
September 30, 2006.
|
|
(16)
|
Accrued
production taxes - The Company understated production tax liabilities
as a
result of not accruing penalty and interest associated with the untimely
payment of production taxes in certain jurisdictions and not correcting
other unreconciled amounts included in production tax liabilities.
This
misstatement originated in 2001 and continued through September 30,
2006.
|
|
(17)
|
Tax
effect - As a result of the errors discussed in items 13 and 16 above,
and
the fact that certain property and severance taxes were remitted
late, the
Company expects that it will incur non-deductible
penalties. These penalties are not deductible for tax purposes
and consist of $0.3 million for the late payment and/or late filing
of
severance taxes, as well as, income tax penalties of $0.4 for the
late
payment of the limited partners’ income taxes that resulted from the
overstatement of production costs. After adjusting for the
impact of these non-deductible items, the Company recorded a tax
provision
for the net effect of items 1 through 16 at the rate of
38.8%.
|
See
Note
19, where the effect of the above entries on 2006 quarterly financial
statements, which was not material, is reflected in revised financial data
for
those periods.
PETROLEUM
DEVELOPMENT CORPORATION
Recently
Issued Accounting Standards
In
June
2006, the FASB issued EITF No. 06-3, How
Taxes Collected from Customers and Remitted to Governmental Authorities Should
be Presented in the Income Statement (That Is, Gross versus Net
Presentation).
EITF
06-3 addresses the income statement presentation of any tax collected from
customers and remitted to a government authority and concludes that the
presentation of taxes on either a gross basis or a net basis is an accounting
policy decision that should be disclosed pursuant to APB No. 22, Disclosures
of Accounting Policies.
For
taxes that are reported on a gross basis (included in revenues and costs),
EITF
06-3 requires disclosure of the amounts of those taxes in interim and annual
financial statements, if those amounts are significant. EITF 06-3 is effective
for interim and annual reporting periods beginning after December 15, 2006.
The
adoption of the standard, effective January 1, 2007, is not expected to have
a
significant impact on the consolidated financial statements.
In
July
2006, the FASB issued FASB Interpretation (“FIN”) No. 48, Accounting
for Uncertainty in Income Taxes - an Interpretation of FASB Statement
109,
which
prescribes a comprehensive model for accounting for uncertainty in tax
positions. FIN No. 48 provides that the tax effects from an uncertain tax
position can be recognized in the financial statements, only if the position
is
more likely than not of being sustained on audit by the Internal Revenue
Service, based on the technical merits of the position. The provisions of FIN
48
will become effective for the Company as of January 1, 2007. The cumulative
effect, if any, of applying the provisions of FIN 48 will be accounted for
as an
adjustment to retained earnings in the first quarter of 2007. The Company is
currently evaluating the impact of adopting FIN 48 on its consolidated financial
statements.
In
September 2006, the FASB issued SFAS No. 157, Accounting
for Fair Value Measurements.
SFAS
No. 157 defines fair value, establishes a framework for measuring fair value
within generally accepted accounting principles and expands required disclosure
about fair value measurements. SFAS No. 157 does not expand the use of fair
value in any new circumstances. The provisions of SFAS No. 157 are effective
for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years. The Company does not expect
the
new standard to have any material impact on its consolidated financial
statements.
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities.
SFAS
No. 159 permits entities to choose to measure many financial instruments and
certain other items at fair value that are not currently required to be measured
at fair value. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply
complex hedge accounting provisions. SFAS No. 159 establishes presentation
and
disclosure requirements designed to facilitate comparisons between entities
that
choose different measurement attributes for similar types of assets and
liabilities. The statement will be effective as of the beginning of an entity's
first fiscal year beginning after November 15, 2007. The Company is evaluating
the impact of the adoption of SFAS No. 159 on the financial
statements.
NOTE
2 - ACQUISITION OF UNIOIL
On
December 6, 2006, the Company completed its cash tender offer and purchased
approximately 95.5% or 9,112,750 shares of the outstanding common stock of
Unioil, an independent energy company with properties in northern Colorado
and
southern Wyoming. The acquisition of more than 90% of the outstanding shares
of
common stock allowed the Company to effect a short-form merger of Unioil and
a
wholly owned subsidiary of the Company, resulting in the acquisition of the
remaining 428,719 shares of Unioil. Each share of Unioil common stock not
tendered through the offer was converted into the right to receive $1.91 in
cash, the same consideration paid for shares in the tender offer. The total
price paid for 100% of Unioil’s outstanding common stock was $18.6 million,
including $0.4 million in direct costs of the acquisition. The acquisition
was
accounted for in accordance with SFAS No. 141, Business
Combinations.
PETROLEUM
DEVELOPMENT CORPORATION
The
total
acquisition cost has been initially allocated to the assets purchased and the
liabilities assumed based upon the fair values on the date of acquisition as
follows (in thousands):
|
Cash
consideration paid
|
$
|
18,224
|
||
|
Plus:
Direct costs of acquisition
|
382
|
|||
|
Total
acquisition cost
|
$
|
18,606
|
||
|
Current
assets acquired
|
$
|
660
|
||
|
Properties
and equipment acquired
|
19,056
|
|||
|
Goodwill
|
6,783
|
|||
|
Deferred
tax liability
|
(6,783
|
)
|
||
|
Other
liabilities assumed
|
(1,110
|
)
|
||
|
Total
acquisition cost
|
$
|
18,606
|
The
assessment of the fair values of oil and gas properties acquired was based
primarily on projections of expected future net cash flows, discounted to
present value. The preliminary acquisition cost allocation includes $6.8 million
in goodwill. The goodwill is neither deductible for tax purposes, nor
amortizable for book purposes pursuant to SFAS No. 141. Goodwill will be tested
for impairment at least annually. The purchase price allocation is preliminary
subject to finalizing fair value appraisals and completing evaluations of proved
and unproved oil and gas properties. These amounts are subject to change as
additional information becomes available and is assessed by the Company.
The
results of Unioil's operations have been included in the consolidated financial
statements from the date of acquisition, December 6, 2006. The pro forma effect
of the inclusion of the results of Unioil's operations in the Company's
consolidated statements of income was not material.
NOTE
3 - ACCOUNTS RECEIVABLE
Accounts
receivable are reviewed to determine which are doubtful of collection. In making
the determination of the appropriated allowance for doubtful accounts,
management considers the Company's historical write-offs, relationships and
overall credit worthiness of its customers, additional consideration is given
to
well production data for receivables related to well operations. The allowance
as reflected in the accompanying balance sheets is the Company's best estimate
of the amount of probable credit losses in the Company's existing accounts
receivable.
The
allowance for doubtful accounts receivable, net as of December 31, 2006 and
2005, was $0.2 million and $0.2 million, respectively. In addition, included
in
other assets, a non-current asset, based on their terms, are accounts receivable
as of December 31, 2006 and 2005, in the amounts of $0.2 million and $0.4
million, net of an allowance for doubtful accounts of $0.2 million and $0.2
million, respectively.
The
nature of the independent oil and gas industry involves a dependence on outside
investor drilling capital and involves a concentration of oil and gas sales
to a
few customers. The Company sells oil and natural gas to various public
utilities, gas marketers and industrial customers. The following table
identifies significant customers as a percent of total oil and gas sales and
total revenues for each of the years presented.
|
Oil
and Gas Sales
|
Total
Revenue
|
||||||||||||||||||
|
Year
Ended December 31,
|
Year
Ended December 31,
|
||||||||||||||||||
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
||||||||||||||
|
Customer
|
|||||||||||||||||||
|
A
|
14.9
|
%
|
10.5
|
%
|
7.6
|
%
|
12.9
|
%
|
6.9
|
%
|
4.3
|
%
|
|||||||
|
B
|
10.6
|
%
|
10.6
|
%
|
9.6
|
%
|
9.1
|
%
|
6.9
|
%
|
5.4
|
%
|
|||||||
|
C
|
10.3
|
%
|
15.2
|
%
|
11.1
|
%
|
8.9
|
%
|
9.9
|
%
|
6.3
|
%
|
|||||||
|
D
|
9.4
|
%
|
12.9
|
%
|
13.8
|
%
|
8.1
|
%
|
8.4
|
%
|
7.8
|
%
|
|||||||
PETROLEUM
DEVELOPMENT CORPORATION
NOTE
4 - PROPERTIES AND EQUIPMENT (in thousands)
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
Properties
and Equipment:
|
|||||||
|
Oil
and gas properties (successful efforts method of
accounting)
|
$
|
500,506
|
$
|
354,147
|
|||
|
Pipelines
|
12,673
|
11,512
|
|||||
|
Transportation
and other equipment
|
7,870
|
6,383
|
|||||
|
Land
and buildings
|
11,620
|
3,981
|
|||||
|
Construction
in progress
|
4,801
|
1,509
|
|||||
|
537,470
|
377,532
|
||||||
|
Less
accumulated depreciation, depletion and amortization
|
143,253
|
111,606
|
|||||
|
Properties
and equipment, net of accumulated depreciation,depletion and
amortization
|
$
|
394,217
|
$
|
265,926
|
|||
NOTE
5 - LONG-TERM DEBT
The
Company has a credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and
BNP Paribas of $200 million subject to and secured by required levels of oil
and
gas reserves. The current borrowing base, based upon current oil and gas
reserves, is $135 million. Effective September 18, 2006, the Company elected
to
increase the amount it had activated by $55 million, from $80 million to $135
million. The Company is required to pay a commitment fee of 0.25% to 0.375%
per
annum on the unused portion of the activated credit facility. Interest accrues
at an Alternative Base Rate ("ABR") or adjusted LIBOR at the discretion of
the
Company. The ABR is the greater of JPMorgan's prime rate, an adjusted secondary
market rate for a three-month certificate of deposit plus 1% or the federal
funds effective rate plus 0.5%. ABR borrowings are assessed an additional margin
spread of 0% to 0.375% and adjusted LIBOR borrowings are assessed an additional
margin spread of 1.125% to 1.875%. The margin spread charges are based upon
the
outstanding balance under the facility. No principal payments are required
until
the credit agreement expires on November 4, 2010.
On
December 19, 2006, the Company executed pursuant to its credit facility an
overline note in the amount of $20 million to be repaid on January 31, 2007.
Interest on the overline note accrued at a per annum rate equal to the alternate
base rate plus 0.80% until December 22, 2006, at which time the rate converted
to a Eurodollar borrowing for a one month period and at a per annum rate equal
to an adjusted LIBOR rate plus 2.30%. The overline note was paid in full in
accordance with its terms in January, 2007.
As
of
December 31, 2006 and 2005, the outstanding balance under the facility,
including the overline note, was $137 million and $24 million, respectively.
Any
amounts outstanding under the credit facility are secured by substantially
all
properties of the Company. At December 31, 2006, an outstanding balance of
$67
million was subject to a prime interest rate of 8.375%; the overline note in
the
amount of $20 million was subject to an interest rate of 9.05% and the remaining
outstanding balance of $50 million was subject to a LIBOR rate of 7.0%. The
credit agreement requires, among other things, the existence of satisfactory
levels of natural gas reserves and the maintenance of certain working capital
and tangible net worth ratios. As of the filing of this annual report on Form
10-K, the Company was in compliance with all covenants in the credit agreement
except for timely filing of this December 31, 2006, Form 10-K. During March
2007, due to various reporting and processing delays, the Company requested
a
waiver related to the Security assignment provisions of its credit facility.
During March 2007, a waiver was granted and the corresponding Borrowing Base
was
reduced to $100 million from $135 million. Along with the previously discussed
waiver, the Company requested and was granted a waiver related to the delay
in
the delivery of its consolidated financial statement for the year ended December
31, 2006, and three months ended March 31, 2007, until May 31, 2007, and June
30, 2007, respectively.
NOTE
6 - INCOME TAXES
The
Company had a substantial taxable gain from the sale of undeveloped oil and
gas
properties (see Note 15). The Company has chosen to use the favorable deferral
aspects of the Internal Revenue Code ("IRC") Section 1031, LKE to defer the
tax
liability on a portion of the gain utilized by purchasing replacement properties
(see Note 16). Accordingly, the Company’s current and deferred provision for
income taxes increased substantially in 2006 and consisted of the following
(in
thousands):
PETROLEUM
DEVELOPMENT CORPORATION
|
2006
|
2005
|
2004
|
||||||||
|
Current:
|
||||||||||
|
Federal
|
$
|
54,467
|
$
|
17,894
|
$
|
8,650
|
||||
|
State
|
8,739
|
3,431
|
1,713
|
|||||||
|
Total
current income taxes
|
63,206
|
21,325
|
10,363
|
|||||||
|
Deferred:
|
||||||||||
|
Federal
|
74,003
|
2,834
|
8,430
|
|||||||
|
State
|
12,428
|
517
|
1,457
|
|||||||
|
Total
deferred income taxes
|
86,431
|
3,351
|
9,887
|
|||||||
|
Total
income taxes
|
$
|
149,637
|
$
|
24,676
|
$
|
20,250
|
||||
Income
tax expense differed from the amounts computed by applying the U.S. federal
income tax rate of 35% (in thousands).
|
2006
|
2005
|
2004
|
||||||||
|
Computed
"expected" tax
|
$
|
135,594
|
$
|
23,145
|
$
|
18,717
|
||||
|
State
income tax
|
13,744
|
2,566
|
2,061
|
|||||||
|
Percentage
depletion
|
(545
|
)
|
(771
|
)
|
(649
|
)
|
||||
|
Domestic
production activities deduction
|
-
|
(399
|
)
|
-
|
||||||
|
Other
|
844
|
135
|
121
|
|||||||
|
$
|
149,637
|
$
|
24,676
|
$
|
20,250
|
|||||
The
Company did not have any net income from Qualified Production Activities
("QPAI"), due to its tax filing election to expense the majority of its
intangible drilling costs incurred in 2006. Accordingly, the domestic production
activities deduction, which is statutorily equal to three percent of QPAI,
was
zero for 2006.
The
Internal Revenue Service (“IRS”) has proposed certain adjustments to the
Company’s federal tax returns for 2003 and 2004. The Company has entered into an
agreement with the IRS concerning some of the proposed adjustments and has
reached an informal understanding with the IRS regarding the others. The
additional federal and state tax expense, including interest, totals
approximately $0.6 million, which was accrued for primarily in prior periods.
In
addition, the proposed adjustments also result in the current taxation in 2003
and 2004 of items previously deferred. Accordingly, as of December 31, 2006,
the
Company has accrued a current federal and state tax liability of $4.6 million,
including applicable interest, which will be due upon completion of the IRS
audit.
PETROLEUM
DEVELOPMENT CORPORATION
The
tax
effects of temporary differences that give rise to significant portions of
the
deferred tax assets and deferred tax liabilities at December 31, 2006 and 2005,
are presented below (in thousands).
|
2006
|
2005
|
||||||
|
Deferred
tax assets:
|
|||||||
|
Allowance
for doubtful accounts
|
$
|
161
|
$
|
159
|
|||
|
Drilling
notes
|
46
|
71
|
|||||
|
Deferred
revenue related to cash withheld for future plugging cost
|
929
|
824
|
|||||
|
Deferred
compensation
|
2,105
|
904
|
|||||
|
Asset
retirement obligations
|
4,428
|
3,242
|
|||||
|
Derivatives
|
-
|
1,562
|
|||||
|
Employee
benefits
|
798
|
-
|
|||||
|
Other
|
-
|
8
|
|||||
|
Total
gross deferred tax assets
|
8,467
|
6,770
|
|||||
|
Less
valuation allowance
|
-
|
-
|
|||||
|
Deferred
tax assets
|
8,467
|
6,770
|
|||||
|
Deferred
tax liabilities:
|
|||||||
|
Properties
and equipment, principally due to differences in depreciation and
amortization
|
(58,790
|
)
|
(31,811
|
)
|
|||
|
Like
kind exchange - deferred gain
|
(63,783
|
)
|
-
|
||||
|
Unrealized
gains - derivatives
|
(1,203
|
)
|
-
|
||||
|
Total
gross deferred tax liabilities
|
(123,776
|
)
|
(31,811
|
)
|
|||
|
Net
deferred tax liability
|
$
|
(115,309
|
)
|
$
|
(25,041
|
)
|
|
|
Classification
in the Consolidated Balance Sheets:
|
|||||||
|
Net
current deferred tax assets*
|
$
|
1,084
|
$
|
1,848
|
|||
|
Net
non-current deferred tax liability
|
(116,393
|
)
|
(26,889
|
)
|
|||
|
Net
deferred tax liability
|
$
|
(115,309
|
)
|
$
|
(25,041
|
)
|
|
| *included in other current assets | |||||||
As
noted
above, deferred tax liabilities increased substantially in 2006 due to the
Company’s utilization of the like-kind exchange tax deferral for a portion of
the taxable gain on the undeveloped land sale (Note 15). The deferred tax
liability on property and equipment increased primarily as a result of the
election to expense, for current tax purposes, approximately $55 million of
intangible drilling costs. In addition, approximately $6.8 million of the
increase in the deferred liability is due to the Unioil acquisition.
In
assessing whether a valuation allowance for the deferred tax assets should
be
recorded, management considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate
realization of deferred tax assets is dependent upon the generation of future
taxable income during the periods in which those temporary differences become
deductible. Based upon the level of historical taxable income and projections
for future taxable income over the periods in which the deferred tax assets
are
deductible, management believes it is more likely than not that the Company
will
realize the benefits of these deductible differences. The amount of the deferred
tax asset considered realizable, however, could be reduced in the near term
if
estimates of future taxable income during the carryforward period are
reduced.
PETROLEUM
DEVELOPMENT CORPORATION
NOTE
7 - ASSET RETIREMENT OBLIGATIONS
Changes
in carrying amounts of the asset retirement obligations associated with the
Company’s working interest in oil and gas properties are as follows (in
thousands):
|
2006
|
2005
|
||||||
|
Balance
at beginning of year
|
$
|
8,333
|
$
|
7,998
|
|||
|
Obligations
assumed with development activities and acquisitions
|
1,264
|
302
|
|||||
|
Obligations
discharged with disposed properties and asset retirements
|
(115
|
)
|
(446
|
)
|
|||
|
Accretion
expense
|
515
|
465
|
|||||
|
Revisions
to estimated cash flows
|
1,969
|
14
|
|||||
|
Balance
at end of year
|
$
|
11,966
|
$
|
8,333
|
|||
If
the
fair value of the estimated asset retirement obligation changes, an adjustment
is recorded to both the asset retirement obligation and the asset retirement
cost. Approximately $50,000 of the asset retirement obligations were classified
as short-term and included in other accrued expenses as of December 31, 2006
and
2005.
NOTE
8 - COMMON STOCK
Stock-Based
Compensation Plans
Approved
by the shareholders in June 2004, the Company maintains a long-term equity
compensation plan for officers and certain key employees of the Company (the
"2004 Plan"). In accordance with the plan, awards may be issued in the form
of
stock options, stock appreciation rights, restricted stock or performance
shares. A total of 750,000 new shares of common stock have been reserved for
issuance. Awards pursuant to the plan vest over periods set at the discretion
of
the Compensation Committee of the Company’s Board of Directors (“Board”) and
have a maximum exercisable period of ten years. As of December 31, 2006, 565,702
common shares remain available for future awards.
Approved
by the shareholders in June 2005, the Company also maintains a restricted stock
plan for non-employee directors. A total of 40,000 new shares of common stock
have been reserved for issuance under the plan. Awards pursuant to the plan
are
subject to restrictions ending on the earliest of various retirement or
termination dates, including certain provisions for change in control. During
2006 and 2005, 6,551 and 6,895 common shares, respectively, were awarded in
accordance with the plan. Compensation expense for each of the years ended
December 31, 2006 and 2005, related to these restricted shares was $0.1 million.
As of December 31, 2006, 26,554 common shares remain available for future
awards.
In
August
1999, the shareholders approved the 1999 Incentive Stock Option and
Non-Qualified Stock Option Plan. A total of 500,000 shares of the Company’s
common stock were reserved for issuance upon the exercise of stock options.
All
shares authorized to be awarded pursuant to this plan were awarded in years
prior to 2002. At December 31, 2006, options for 49,000 common shares remain
outstanding and exercisable through 2011, at which time the options will
expire.
Stock
Option Awards.
The
Company granted stock options in previous years under several stock compensation
plans. Outstanding options expire ten years from the date of grant and become
exercisable ratably over a four year period. The Company did not grant any
stock
option awards in 2005. The fair values of stock options granted during the
years
ended December 31, 2006 and 2004, were estimated at the date of grant using
a
Black-Scholes option-pricing model assuming no dividends and the following
weighted average assumptions:
|
For
the year ended December 31,
|
|||||||
|
2006
|
2004
|
||||||
|
Expected
Volatility
|
40.4
|
%
|
39.7
|
%
|
|||
|
Expected
term (in years)
|
6
|
7
|
|||||
|
Risk-free
interest rate
|
4.2
|
%
|
4.1
|
%
|
|||
|
Weighted-average
grant date fair value per share
|
$
|
20.30
|
$
|
16.75
|
|||
PETROLEUM
DEVELOPMENT CORPORATION
Expected
volatilities are based on the Company's historical volatility. The expected
life
of an award is estimated using historical exercise behavior data. The risk-free
interest rate is based on the U.S. Treasury yields in effect at the time of
grant and extrapolated to approximate the expected life of the award. The
Company does not expect to pay dividends, nor does it expect to declare
dividends in the foreseeable future.
The
following table provides a summary of the Company's stock option award activity
for the year ended December 31, 2006:
|
Number
of
Shares
Underlying
Options
|
Weighted
Average
Exercise
Price
Per
Share
|
Weighted
Average
Remaining
Contractual
Term
(years)
|
||||||||
|
Outstanding
at December 31, 2005
|
73,880
|
$
|
11.96
|
|||||||
|
Granted
|
23,687
|
44.76
|
||||||||
|
Exercised
|
(8,000
|
)
|
3.88
|
|||||||
|
Outstanding
at December 31, 2006
|
89,567
|
21.36
|
5.6
|
|||||||
|
Vested
and expected to vest at December 31, 2006
|
85,808
|
20.32
|
5.4
|
|||||||
|
Exercisable
at December 31, 2006
|
57,440
|
9.38
|
3.7
|
|||||||
|
Year
Ended December 31,
|
||||||||||
|
(in
millions)
|
2006
|
2005
|
2004
|
|||||||
|
Total
intrinsic value of options exercised
|
$
|
0.3
|
$
|
0.1
|
$
|
27.6
|
||||
|
Total
intrinsic value of options outstanding
|
2.0
|
1.6
|
2.1
|
|||||||
|
Total
intrinsic value of options exercisable
|
1.9
|
1.6
|
2.0
|
|||||||
The
intrinsic value of options exercised represents the amount by which the market
value of the Company’s stock at date of exercise exceeds the exercise price of
the option. The intrinsic values of the options outstanding and exercisable
represent the amount by which the closing market price of the Company’s common
stock at the last trading day of the year exceeds the exercise price of the
options.
Total
unrecognized compensation cost related to stock options granted under the 2004
Plan was $0.5 million as of December 31, 2006. This cost is expected to be
recognized over a weighted average period of 2.7 years.
During
2004, 337,360 stock option shares were exercised by employees exchanging 62,999
mature shares of stock with a fair value of $1.4 million. All of the mature
shares exchanged were subsequently cancelled.
Restricted
Stock Awards.
The
Company began issuing shares of restricted common stock to employees in 2004.
The fair value of the awards issued is determined based on the fair market
value
of the shares on the date of grant. The grant date fair value is amortized
over
the vesting period, ratably over four years from the date of grant for employees
and the lesser of three years or remaining elected term at date of issuance
for
directors.
The
following table provides a summary of the Company's restricted stock award
activity for the year ended December 31, 2006:
|
Restricted
Shares
|
Weighted
Average
Grant-Date
Fair
Value
|
||||||
|
Non-vested
restricted stock at December 31, 2005
|
38,430
|
$
|
32.68
|
||||
|
Granted
|
118,498
|
40.65
|
|||||
|
Vested
|
(19,602
|
)
|
30.47
|
||||
|
Forfeited
|
(5,596
|
)
|
40.05
|
||||
|
|
|||||||
|
Non-vested
restricted stock at December 31, 2006
|
131,730
|
$
|
39.87
|
||||
PETROLEUM
DEVELOPMENT CORPORATION
|
Year
Ended December 31,
|
||||||||||
|
(in
millions)
|
2006
|
2005
|
2004
|
|||||||
|
Total
intrinsic value of restricted stock awards vested
|
$
|
0.8
|
$
|
0.2
|
$
|
-
|
||||
|
Total
intrinsic value of restricted stock awards outstanding
|
5.7
|
1.3
|
0.9
|
|||||||
The
intrinsic value above is based upon the closing market price of the Company's
common stock on the last trading date of the year, $43.05.
The
total
compensation cost related to non-vested awards not yet recognized as of December
31, 2006, is $3.9 million. The cost is expected to be recognized over a
weighted-average period of 3.2 years.
Conversion
of Predecessor Shares
The
Company has historically understated the number of shares issued and outstanding
primarily as a result of improper conversion of predecessor company shares
dating back to 1969. The impact of this adjustment on the balance sheet was
less
than $1 thousand, and the impact of the exclusion of these shares as outstanding
was not material to the Company's reported earnings per share. The Company
has
adjusted the amount of shares and the balance in common stock in the
accompanying consolidated statement of shareholders’ equity as of January 1,
2006.
Treasury
Share Purchases
In
March
2004, the Compensation Committee of the Company's Board of Directors ("Board")
approved the purchase of 48,650 shares of common stock from one of the Company’s
officers. The purchase price of the common stock was the closing price on the
date of the purchase of $26.61 per share and totaled $1.3 million, which
approximated the tax savings to be realized by the Company as a result of the
exercise of said officer’s non-qualified stock options in 2004. The Company also
purchased 1,703 shares from an employee upon retirement from the Company in
June
2004. All shares purchased were subsequently retired.
In
March
2005, the Company publicly announced the authorization by its Board to purchase
up to 2% of the Company's outstanding common stock (331,796 shares) at fair
market value at the date of purchase. In June 2005, the Board approved an
amendment of the size of the stock purchase from 2% to 10% (1,658,980 shares)
of
the Company’s then outstanding common stock. Under the program, the Board had
discretion as to the dates of purchase and amounts of stock to be purchased
and
whether or not to make purchases. The Company purchased pursuant to the plan
331,796 common shares at a cost of $7.9 million ($23.75 average price paid
per
share). This program expired on December 31, 2005. All shares purchased in
accordance with the program have subsequently been retired.
In
January 2006, the Company announced that
its
Board authorized the purchase of up to 10% (1,627,500 shares) of the Company's
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. In October 2006, the Company completed its January 2006
program. Total shares purchased 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 have subsequently been retired.
On
October 16, 2006, the Board of Directors of the Company approved a second 2006
purchase program authorizing the Company to purchase up to 10% (1,477,109
shares) of the Company’s then outstanding common stock 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.
Stock
Repurchase Agreement
In
May
2004, the Company repurchased 50,487 shares of common stock from the estate
of
one of the Company’s former officer in accordance with the terms of a stock
repurchase agreement. The repurchase totaled $1.4 million of which $1 million
was funded by life insurance proceeds. Similar agreements with all other
executive officers were terminated in December 2005.
NOTE
9 - EMPLOYEE BENEFIT PLANS
The
Company sponsors a qualified deferred compensation plan covering substantially
all of its employees. The plan consists of a 401(k) retirement plan with a
profit sharing component. The plan enables eligible employees to contribute
a
portion of their compensation through payroll deductions in accordance with
specific guidelines. The Company provides a discretionary matching contribution
based on a percentage of the employees' contributions up to certain limits.
The
Company's contribution to the profit sharing component is discretionary. Total
Company contributions, to both 401(k) and profit sharing, in 2006, 2005 and
2004, were $3.1 million, $0.9 million and $0.7 million,
respectively.
PETROLEUM
DEVELOPMENT CORPORATION
The
Company provides a supplemental retirement benefit of deferred compensation
under terms of the various employment agreements with certain executive
officers. During 2006, 2005 and 2004, the Company charged $0.3 million, $0.2
million and $0.2 million related to this plan to general and administrative
expenses, respectively, and has recorded a related liability in the amount
$1.9
million and $1.1 million as of December 31, 2006 and 2005, respectively.
In
addition to the supplemental retirement benefit of deferred compensation, the
Company offers a supplemental healthcare benefit covering certain executive
officers and their spouses in accordance with each officer's employment
agreement. During 2006, the Company charged $0.1 million related to this plan
to
general and administrative expenses and has a related liability in the amount
of
$0.6 million as of December 31, 2006.
The
Company maintains a non-qualified deferred compensation plan for non-employee
directors of the Company. The amount of compensation deferred by each
participant is based on participant elections. The amounts deferred pursuant
to
the plan are invested in the Company's common stock, maintained in a rabbi
trust
and are classified in the accompanying balance sheet as treasury shares as
a
component of shareholders' equity. The plan may be settled in either cash or
shares as requested by the participant. As of December 31, 2006, the Company
had
recorded a long-term liability of $0.2 million, which is included in other
liabilities in the accompanying consolidated balance sheet.
NOTE
10 - EARNINGS PER SHARE
The
following is a reconciliation of the numerators and denominators used in the
calculation of basic and diluted earnings per share for the years ended December
31, (in thousands, except per share amounts):
|
2006
|
2005
|
2004
|
||||||||
|
Weighted
average common shares outstanding
|
15,660
|
16,362
|
16,239
|
|||||||
|
Dilutive
effect of share-based compensation:
|
||||||||||
|
Unamortized
portion of restricted stock
|
22
|
13
|
1
|
|||||||
|
Stock
options
|
55
|
52
|
366
|
|||||||
|
Non
employee director deferred compensation
|
4
|
-
|
-
|
|||||||
|
Weighted
average common and common equivalent shares
outstanding
|
15,741
|
16,427
|
16,606
|
|||||||
|
Net
income
|
$
|
237,772
|
$
|
41,452
|
$
|
33,228
|
||||
|
Basic
earnings per common share
|
$
|
15.18
|
$
|
2.53
|
$
|
2.05
|
||||
|
Diluted
earnings per common share
|
$
|
15.11
|
$
|
2.52
|
$
|
2.00
|
||||
Options
with an exercise price exceeding the average price of the underlying securities
are not considered to be dilutive, or anti-dilutive, and are included in the
calculation of the denominator for diluted earnings per share. Common share
equivalents attributable to anti-dilutive options, and therefore not included
in
the computation of earnings per share, for the years ended December 31, 2006,
2005 and 2004, were 23,687, 16,880 and 16,880, respectively.
NOTE
11 - TRANSACTIONS WITH AFFILIATES
Funds
held for future distribution on the consolidated balance sheets was relatively
unchanged at $31.4 million for each of the years ended December 31, 2006 and
2005. These funds primarily represent amounts owed to affiliated partnerships
for undistributed production proceeds as of December 31, 2006 and 2005,
respectively.
The
Company provided oil and gas well drilling services and well operations and
pipeline services to affiliated partnerships. Substantially all of the Company's
revenue and expenses related to oil and gas well drilling operations and
revenues from well operations and pipeline income are associated with services
provided to the investing partners. Amounts due from/to the affiliated
partnership are principally amounts related to derivative
positions.
PETROLEUM
DEVELOPMENT CORPORATION
Management
fees collected from the affiliated partnerships amounted to $1.3 million, $1.7
million and $1.5 million for the years ended December 31, 2006, 2005 and 2004,
respectively, and are included in other income on the accompanying consolidated
statements of income.
Revenues
from oil and gas well drilling operations and costs of oil and gas well drilling
operations each include $0.1 million, $0.2 million and $0.1 million during
2006,
2005 and 2004, respectively, related to investments made by officers of the
Company for working interests in wells drilled during the respective years.
The
Company through its wholly-owned subsidiary, PDC
Securities Incorporated, acts as Dealer-Manager of the drilling partnerships.
PDC
Securities receives the applicable commissions and marketing allowances from
the
Escrow Agent of the drilling program and distributes them to the soliciting
broker/dealers who sell the programs. The commissions and marketing allowances
received by
PDC
Securities are included in other income net of the commissions distributed
to
the soliciting broker/dealer. The commissions and marketing allowances received
by PDC Securities and distributed to the Soliciting Broker/Dealers amounted
to
$8.8 million, $11.4 million and $9.7 million for the years ended December 31,
2006, 2005 and 2004, respectively.
During
2006, 2005 and 2004, the Company paid $18,000, $25,900 and $22,500,
respectively, to the Corporate Secretary's law firm for various legal
services.
NOTE
12 - COMMITMENTS AND CONTINGENCIES
The
Company would be exposed to oil and natural gas price fluctuations on underlying
purchase and sale contracts should the counterparties to the Company's
derivative instruments or the counterparties to the Company's gas marketing
contracts not perform. Nonperformance is not anticipated. There were no
counterparty default losses in 2006, 2005 or 2004.
The
Company is a party to an exploration agreement with an unaffiliated party.
The
agreement requires the Company to drill a minimum of 25 wells through June
30,
2007. For each well the Company fails to drill prior to June 30, 2007, the
Company will be required to pay liquidated damages equal to $125,000 per
un-drilled well, for a maximum contingency of $3.1 million. Drilling pursuant
to
the agreement commenced in February 2007.
In
connection with the Company’s sale of undeveloped leaseholds in July 2006, the
Company is obligated to either drill 16 wells on specifically identified acreage
over the next three years (five by December 31, 2007, another five by December
31, 2008, and another six by December 31, 2009) or pay liquidated damages of
$1.6 million per un-drilled well for a total contingent obligation of $25.6
million, of which $8 million is reflected in current liabilities, and $17.6
million is reflected as a deferred gain on sale of leaseholds, a long-term
liability, in the consolidated balance sheets. See Note 15 for additional
disclosure related to the sale.
Substantially
all of the Company's drilling programs contain a repurchase provision where
investing partners may request that the Company purchase their partnership
units
at any time beginning with the third anniversary of the first cash distribution.
The provision provides that the Company is obligated to purchase an aggregate
of
10% of the initial subscriptions per calendar year (at a minimum price of four
times the most recent 12 months' cash distributions), if repurchase is requested
by investors, and subject to the Company's financial ability to do so. The
maximum annual repurchase obligation as of December 31, 2006, was approximately
$12.3 million. The Company has adequate liquidity to meet this obligation.
During 2006 and 2005, the Company paid $0.8 million and $0.4 million,
respectively, under this provision for the repurchase of partnership units.
As
of December 31, 2006, outstanding repurchase offers to investing partners
totaled $0.2 million, which $0.1 million of the outstanding offers was
consummated in 2007 prior to expiration.
The
Company's drilling programs formed from 1996 through the second quarter of
2005
contain a performance supplement that provides for changes in the distribution
of partnership profits if certain levels of performance are not met. The terms
of this provision in the partnership agreements are not a guarantee of a rate
of
return on an investment in the partnership. Under those specific conditions,
such changes can result in the Company’s share of an affected partnership’s
profits being reduced by up to one half of the amount to which it otherwise
would be entitled in the affected period. In no event would the Company be
obligated to assume a disproportionate share of losses in such partnerships;
should the partnerships which contain this provision in the partnership
agreements incur a loss, the Company’s share of such losses would be unaffected
by the terms of this provision. In accordance with these provisions, the
Company’s share of partnership profits was reduced by an aggregate of $1
million, $0.7 million and $0.6 million during 2006, 2005 and 2004, respectively.
As of December 31, 2006 and 2005, based on production through December 31 of
the
corresponding year, the Company had accrued $0.4 million and zero,
respectively.
As
Managing General Partner of 76 partnerships the Company has liability for any
potential casualty losses in excess of the partnership assets and insurance.
In
January 2007, the Company purchased the remaining working interests in 44 of
the
76 partnerships, which were sponsored by the Company in the late 1980s and
1990s
(see Note 16). The
Company's management believes the casualty insurance coverage carried by the
Company and its subcontractors is adequate to meet this potential
liability.
PETROLEUM
DEVELOPMENT CORPORATION
In
order
to secure the services for drilling rigs, the Company made commitments to the
drilling contractors, which call for a minimum commitment of $9,000 daily for
a
specified amount of time if the Company ceases to use the drilling rigs, an
event that is not anticipated to occur, and a maximum commitment of $34,400
daily for a specified amount of time for daily use of the drilling rigs. As
of
December 31, 2006, commitments for these two separate contracts expire in July
2009 and May 2010. As of December 31, 2006, the Company has an outstanding
minimum commitment for $9.4 million and an outstanding maximum commitment for
$36.1 million.
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.
NOTE
13 - LEASE OBLIGATIONS
The
Company has entered into operating leases on behalf of itself and its affiliated
partnerships principally for the leasing of natural gas compressors on its
Michigan operating facilities. Additionally, the Company has operating leases
for general office equipment. The future minimum lease payments under these
non-cancelable operating leases as of December 31, 2006, are as follows: (in
thousands)
|
Year
|
Lease
Amount
|
|||
|
2007
|
$
|
502
|
||
|
2008
|
493
|
|||
|
2009
|
495
|
|||
|
2010
|
347
|
|||
|
2011
|
208
|
|||
|
Thereafter
|
4
|
|||
|
$
|
2,049
|
|||
The
Company's share of this lease expense for operating leases for the years ended
December 31, 2006, 2005 and 2004 was $0.4 million, $0.3 million and $0.3
million, respectively.
NOTE
14 - DERIVATIVE FINANCIAL INSTRUMENTS
The
Company utilizes commodity based derivative instruments to manage a portion
of
its exposure to price risk from its oil and natural gas sales and marketing
activities. Company policy prohibits the use of oil and natural gas future
and
option contracts for speculative purposes. These instruments consist of
NYMEX-traded natural gas futures contracts and option contracts for Appalachian
and Michigan production, Panhandle-based contracts and NYMEX-traded contracts
for NECO production and CIG-based contracts for other Colorado production.
These
derivative instruments have the effect of locking in for specified periods
(at
predetermined prices or ranges of prices) the prices the Company will receive
for the volume to which the derivative relates and, in the case of RNG, the
cost
of gas supplies purchased for marketing activities. As a result, while these
derivatives are structured to reduce the Company's exposure to changes in price
associated with the derivative commodity, they also limit the benefit the
Company might otherwise have received from price changes associated with the
derivative commodity. RNG also enters into fixed-price physical purchase and
sale agreements that are derivative contracts.
The
net
fair value of the commodity based derivatives was $13.6 million of which $1.1
million is included in other long term assets at December 31, 2006. At December
31, 2005, the net fair value of commodity based derivatives was $(9.4) million
of which $(1.4) million is included in other long term liabilities. The Company
recognized in the statement of income an unrealized gain on commodity based
derivatives of $7.6 million for the year ended December 31, 2006, and unrealized
losses of $3.2 million and $1.1 million for the years ended December 31, 2005,
and 2004, respectively.
PETROLEUM
DEVELOPMENT CORPORATION
The
following tables summarize the open derivative option and purchase and sales
contracts for Riley Natural Gas and the Company as of December 31, 2006 and
2005.
Riley
Natural Gas
Open
Derivative Positions
(dollars
in thousands, except average price data)
|
Commodity
|
Type
|
Quantity
Gas-MMbtu
|
Weighted
Average
Price
|
Total
Contract
Amount
|
Fair
Value
|
|||||||||||
|
Total
Positions as of December 31, 2006
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Purchases |
246,900
|
$
|
7.34
|
$
|
1,811
|
$
|
(304
|
)
|
|||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Sales |
1,952,150
|
8.42
|
16,444
|
2,815
|
|||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Purchases |
90,000
|
0.42
|
38
|
(12
|
)
|
||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Sales |
20,000
|
0.50
|
10
|
4
|
|||||||||||
|
Natural
Gas
|
Cash Settled Option Purchases |
220,000
|
5.50
|
1,210
|
64
|
|||||||||||
|
Natural
Gas
|
Cash Settled Option Sales |
110,000
|
10.10
|
1,111
|
(39
|
)
|
||||||||||
|
Natural
Gas
|
Physical Purchases |
1,964,150
|
8.27
|
16,244
|
(1,974
|
)
|
||||||||||
|
Natural
Gas
|
Physical Sales |
114,974
|
9.62
|
1,106
|
310
|
|||||||||||
|
Natural
Gas
|
Physical Basis Purchases |
20,000
|
0.45
|
9
|
(3
|
)
|
||||||||||
|
Natural
Gas
|
Physical Basis Sales |
90,000
|
0.44
|
39
|
14
|
|||||||||||
|
|
||||||||||||||||
|
Positions
maturing in 12 months following December 31, 2006
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Purchases |
246,900
|
$
|
7.34
|
$
|
1,811
|
$
|
(304
|
)
|
|||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Sales |
1,637,150
|
8.37
|
13,697
|
2,637
|
|||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Purchases |
90,000
|
0.42
|
38
|
(12
|
)
|
||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Sales |
20,000
|
0.50
|
10
|
4
|
|||||||||||
|
Natural
Gas
|
Cash Settled Option Purchases |
220,000
|
5.50
|
1,210
|
64
|
|||||||||||
|
Natural
Gas
|
Cash Settled Option Sales |
110,000
|
10.10
|
1,111
|
(39
|
)
|
||||||||||
|
Natural
Gas
|
Physical Purchases |
1,649,150
|
8.27
|
13,641
|
(2,027
|
)
|
||||||||||
|
Natural
Gas
|
Physical Sales |
114,974
|
9.62
|
1,105
|
310
|
|||||||||||
|
Natural
Gas
|
Physical Basis Purchases |
20,000
|
0.45
|
9
|
(3
|
)
|
||||||||||
|
Natural
Gas
|
Physical Basis Sales |
90,000
|
0.44
|
39
|
14
|
|||||||||||
|
Prior
Year Total Positions as of December 31, 2005
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Purchases |
1,025,500
|
$
|
9.05
|
$
|
9,283
|
$
|
1,983
|
||||||||
|
Natural
Gas
|
Cash Settled Futures/Swaps Sales |
3,149,000
|
7.95
|
25,018
|
(8,689
|
)
|
||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Purchases |
450,000
|
0.91
|
409
|
(158
|
)
|
||||||||||
|
Natural
Gas
|
Cash Settled Basis Swap Sales |
240,000
|
0.50
|
120
|
4
|
|||||||||||
|
Natural
Gas
|
Physical Purchases |
2,819,000
|
8.32
|
23,456
|
7,858
|
|||||||||||
|
Natural
Gas
|
Physical Sales |
585,222
|
10.72
|
6,272
|
(670
|
)
|
||||||||||
|
Natural
Gas
|
Physical Basis Purchases |
240,000
|
0.45
|
108
|
8
|
|||||||||||
|
Natural
Gas
|
Physical Basis Sales |
450,000
|
0.94
|
420
|
169
|
|||||||||||
The
maximum term for the derivative contracts listed above is 25
months.
PETROLEUM
DEVELOPMENT CORPORATION
Petroleum
Development Corporation
Open
Derivative Positions
(dollars
in thousands, except average price data)
|
Commodity
|
Type
|
Quantity
Gas-MMbtu
Oil-Barrels
|
Weighted
Average
Price
|
Total
Contract
Amount
|
Fair
Value
|
|||||||||||
|
Total
Positions as of December 31, 2006
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Option Sales |
17,390,000
|
$
|
5.56
|
$
|
96,613
|
$
|
12,597
|
||||||||
|
Natural
Gas
|
Cash Settled Option Purchases |
2,155,000
|
10.34
|
22,287
|
(14
|
)
|
||||||||||
|
Oil
|
Cash Settled Option Purchases |
300,000
|
50.00
|
15,000
|
155
|
|||||||||||
|
Positions
maturing in 12 months following December 31, 2006
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Option Sales |
15,530,000
|
$
|
5.53
|
$
|
85,850
|
$
|
11,682
|
||||||||
|
Natural
Gas
|
Cash Settled Option Purchases |
2,155,000
|
10.34
|
22,287
|
(14
|
)
|
||||||||||
|
Oil
|
Cash Settled Option Purchases |
300,000
|
50.00
|
15,000
|
155
|
|||||||||||
|
Prior
Year Total Positions as of December 31, 2005
|
||||||||||||||||
|
Natural
Gas
|
Cash Settled Option Sales |
5,665,000
|
$
|
8.17
|
$
|
46,273
|
$
|
(12,531
|
)
|
|||||||
|
Natural
Gas
|
Cash Settled Option Purchases |
14,030,000
|
6.36
|
89,210
|
2,660
|
|||||||||||
The
maximum term for the derivative contracts listed above is 15
months.
In
addition to including the gross assets and liabilities related to the Company's
share of oil and gas production, the above tables and the accompanying
consolidated balance sheets include the gross assets and liabilities related
to
derivative contracts entered into by the Company on behalf of the affiliate
partnerships as the Managing General Partner. The accompanying consolidated
balance sheets include the fair value of derivatives and a corresponding net
payable to the partnerships of $7.5 million as of December 31, 2006 and a net
receivable from the partnerships of $5.4 million as of December 31, 2005. In
addition to the short-term fair value of derivatives shown in the accompanying
consolidated balance sheet there are long-term assets and long-term liabilities
which total to a net long-term asset of approximately $0.9 million and $1.3
million as of December 31, 2006 and 2005, respectively, related to the fair
value of derivatives included in the accompanying consolidated balance
sheets.
The
Company is required to maintain margin deposits with brokers for outstanding
futures contracts. As of December 31, 2006 and 2005, restricted cash in the
amount of $0.5 million and $1.5 million was on deposit.
An
interest rate swap agreement was used to reduce the potential impact of
increases in interest rates on variable rate long-term debt. The swap agreement
expired in October 2004. The agreement required the Company, on a quarterly
basis, to make a fixed-rate interest payment of 6.89% plus its current LIBOR
rate margin (+1.50% at December 31, 2003) on a $10 million amount related to
its
outstanding line of credit. The change in the fair value of the swap was
included as a component of interest expense; the related gain was $0.6 million
for the year ended December 31, 2004.
By
using
derivative financial instruments to manage exposures to changes in interest
rates and commodity prices, the Company exposes itself to credit risk and market
risk. Credit risk is the failure of the counterparty to perform under the terms
of the derivative contract. When the fair value of a derivative contract is
positive, the counterparty owes the Company, which creates repayment risk.
The
Company minimizes the credit or repayment risk in derivative instruments by
entering into transactions with high-quality counterparties. There were no
counterparty defaults during the years ended December 31, 2006, 2005 and
2004.
PETROLEUM
DEVELOPMENT CORPORATION
The
following changes in the fair value of commodity based derivatives are reflected
in the consolidated statements of income (in millions):
|
Realized
gains/(losses)
|
Unrealized
gains/(losses)
|
||||||||||||||||||
|
Statement
of Income Line Item
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|||||||||||||
|
Oil
and gas price risk management gain (loss), net
|
$
|
1.9
|
$
|
(6.4
|
)
|
$
|
(1.6
|
)
|
$
|
7.2
|
$
|
(3.0
|
)
|
$
|
(1.5
|
)
|
|||
|
Gas
sales from marketing activities
|
2.6
|
(5.6
|
)
|
0.8
|
12.3
|
(8.5
|
)
|
1.2
|
|||||||||||
|
Cost
of gas marketing activities
|
(1.9
|
)
|
(1.3
|
)
|
(3.3
|
)
|
(11.9
|
)
|
8.3
|
(0.8
|
)
|
||||||||
Oil
and
gas price risk management gain (loss), net includes realized and unrealized
gains and losses on commodity based derivatives related to the Company’s oil and
gas sales. Gas sales from marketing activities and cost of gas marketing
activities includes realized and unrealized gains and losses on commodity based
derivatives related to the RNG gas sales and gas purchases, respectively.
NOTE
15 - SALE OF OIL AND GAS PROPERTIES
Grand
Valley Field Acreage
In
July
2006, the Company sold to an unaffiliated company a portion of its undeveloped
leasehold located in Grand Valley Field, Garfield County, Colorado. The sale
encompassed 100% of the working interest in approximately 8,700 acres, including
approximately 6,400 acres of the Company's Chevron leasehold and 2,300 acres
of
the Company's Puckett Land Company leasehold. The Company retained approximately
475 undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold
in addition to all of its producing properties in the field. The proceeds from
the sale were $353.6 million.
The
Company recorded a gain on sale of leaseholds of $328 million and a deferred
gain on sale of leaseholds of $25.6 million. The Company is obligated to either
drill 16 wells on specifically identified acreage over the next three years
(five by December 31, 2007, another five by December 31, 2008, and another
six
by December 31, 2009) or pay liquidated damages of $1.6 million per un-drilled
well. The Company expects to drill the wells for its own benefit and, as such,
will record the costs of the wells drilled in accordance with its oil and gas
properties accounting policy. For each well the Company drills, the Company
will
recognize $1.6 million of the deferred gain when drilling is complete.
Alternatively, should the Company not first drill the wells, the unaffiliated
company has the option to drill the wells for its benefit and, should it decide
to exercise its option, with each well drilled, the Company would recognize
both
$1.6 million of the amount deferred and $0.4 million to be paid to the Company
by the unaffiliated company. At December 31, 2006, $8 million of the deferred
gain on sale of leaseholds is classified as short-term and included in other
current liabilities in the accompanying consolidated balance sheet.
In
conjunction with the sale, the Company entered into a LKE agreement, in
accordance with IRC Section 1031, with a “qualified intermediary.” Proceeds in
the amount of $300 million were transferred directly to the qualified
intermediary to be held in trust pursuant to the terms of the LKE agreement.
The
Company had until mid-January 2007 to close any acquisition of suitable
like-kind property, allowing the Company to take advantage of the income tax
deferral benefits of a LKE transaction. See Note 16 for a further discussion
of
the acquisition of suitable like-kind properties.
During
2005, the Company sold a portion of one of its undeveloped Grand Valley Field,
Garfield County, Colorado leases to an unaffiliated entity. The proceeds of
the
sale were $6.2 million and the Company’s carrying value of the property was
zero. The Company was required to remit $1 million to the original lessor,
unless it commenced construction of certain facilities adjacent to this
undeveloped property subject to certain timing conditions. The Company commenced
construction of the facilities in 2005. The gain of $6.2 million was recognized
in 2005 and is included in gain on sale of leaseholds in the accompanying
consolidated statement of income.
Others
Additionally,
in 2005, the Company completed the sale to an unaffiliated entity of 111
Pennsylvania wells it purchased in 1998. The Company received proceeds of $3.4
million and recorded a gain of $1.5 million, which is included in gain on sale
of leaseholds in the accompanying consolidated statement of income.
PETROLEUM
DEVELOPMENT CORPORATION
NOTE
16 - SUBSEQUENT EVENTS
Acquisition
of IRC Section 1031 - Like-Kind Exchange Properties
In
January 2007, the Company completed its acquisitions of suitable like-kind
properties in accordance with the LKE agreement it entered into in connection
with its sale of undeveloped leaseholds located in Grand Valley Field, Garfield
Country, Colorado in July 2006. The Company acquired for cash qualifying oil
and
gas properties totaling $191.5 million as described below.
EXCO
Resources Inc.
On
January 5, 2007, the Company completed its purchase of EXCO Resources Inc.’s
producing properties and remaining undeveloped drilling locations and acreage
in
the Wattenberg Field area of the DJ Basin, Colorado. The cash consideration
paid
for the EXCO properties was $130.9 million. The acquisition included
substantially all of EXCO’s assets in the area and encompassed 144 oil and gas
wells (approximating 25.5 Bcfe, net of royalty interests, proved developed
reserves as of December 31, 2005) and 8,160 acres of leasehold. The wells and
leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties,
Colorado. The Company will operate the assets and holds a majority working
interest in the properties.
Company-Sponsored
Partnerships.
On
January 10, 2007, the Company completed the purchase of the remaining working
interests in 44 Company-sponsored partnerships for $58.8 million. The
transaction resulted in an increase in the Company’s net interest in 718 wells
that are currently operated by the Company. The wells are located primarily
in
the Appalachian Basin and Michigan.
Other.
The
Company acquired from unaffiliated parties undeveloped leaseholds in Erath
County, Texas for $1.8 million.
Other
Acquisitions
On
February 22, 2007, the Company acquired, from an unaffiliated party 28 producing
wells and associated undeveloped acreage located in Colorado (Wattenberg Field)
for a purchase price of $11.8 million. The acquisition encompasses current
daily
production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil
per
day), net to the interests acquired, 100 or more undeveloped drilling locations,
19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable
reserves.
NOTE
17 - BUSINESS SEGMENTS
The
Company's
operating activities can be divided into four major segments: drilling and
development, natural gas marketing, oil and gas sales, and well operations
and
pipeline income. The Company drills natural gas wells for Company-sponsored
drilling partnerships and retains an interest in each well. A wholly-owned
subsidiary, Riley Natural Gas, engages in the marketing of natural gas to
commercial and industrial end-users. The Company owns an interest in
approximately 3,100 wells from which it sells its oil and gas production from
its working interests in the wells. The Company charges Company-sponsored
partnerships and other third parties competitive industry rates for well
operations and gas gathering. All material inter-company accounts and
transactions between segments have been eliminated. Segment information for
the
years ended December 31, 2006, 2005 and 2004 is presented below (in
thousands).
PETROLEUM
DEVELOPMENT CORPORATION
|
Year
Ended December 31,
|
2006
|
2005
|
2004
|
|||||||
|
REVENUES
|
||||||||||
|
Drilling
and development
|
$
|
17,917
|
$
|
99,963
|
$
|
94,076
|
||||
|
Natural
gas marketing
|
131,326
|
121,114
|
94,628
|
|||||||
|
Oil
and gas sales (1)
|
124,336
|
93,191
|
66,407
|
|||||||
|
Well
operations and pipeline income
|
10,704
|
8,760
|
7,677
|
|||||||
|
Unallocated
amounts
|
2,220
|
2,170
|
1,695
|
|||||||
|
Total
|
$
|
286,503
|
$
|
325,198
|
$
|
264,483
|
||||
|
SEGMENT
INCOME BEFORE INCOME TAXES
|
||||||||||
|
Drilling
and development
|
$
|
5,300
|
$
|
11,778
|
$
|
16,380
|
||||
|
Natural
gas marketing
|
1,816
|
1,737
|
1,784
|
|||||||
|
Oil
and gas sales (2)
|
61,868
|
46,095
|
35,090
|
|||||||
|
Well
operations and pipeline income (3)
|
2,823
|
3,539
|
3,695
|
|||||||
|
Unallocated
amounts
|
||||||||||
|
General
and administrative expense
|
(19,047
|
)
|
(6,960
|
)
|
(4,506
|
)
|
||||
|
Gain
on sale of leaseholds
|
328,000
|
7,669
|
-
|
|||||||
|
Interest
income (4)
|
7,407
|
625
|
138
|
|||||||
|
Interest
expense
|
(2,443
|
)
|
(217
|
)
|
(238
|
)
|
||||
|
Other
(5)
|
1,685
|
1,862
|
1,135
|
|||||||
|
Total
|
$
|
387,409
|
$
|
66,128
|
$
|
53,478
|
||||
|
As
of December 31,
|
|
|
|
|||||||
|
SEGMENT
ASSETS
|
|
|||||||||
|
Drilling
and development
|
$
|
87,746
|
$
|
89,030
|
$
|
64,348
|
||||
|
Natural
gas marketing
|
39,899
|
56,518
|
31,234
|
|||||||
|
Oil
& gas sales
|
394,952
|
251,897
|
205,680
|
|||||||
|
Well
operations and pipeline income
|
28,895
|
31,407
|
16,518
|
|||||||
|
Unallocated
amounts
|
||||||||||
|
Cash
|
109,467
|
3,383
|
112
|
|||||||
|
Designated
cash - property acquisitions (6)
|
191,512
|
-
|
-
|
|||||||
|
Other
|
31,816
|
12,126
|
11,561
|
|||||||
|
Total
|
$
|
884,287
|
$
|
444,361
|
$
|
329,453
|
||||
|
EXPENDITURES
FOR SEGMENT LONG-LIVED ASSETS
|
||||||||||
|
Drilling
and development
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
|
Natural
gas marketing
|
-
|
1
|
6
|
|||||||
|
Oil
& gas sales
|
133,401
|
92,907
|
45,713
|
|||||||
|
Well
operations and pipeline income
|
1,419
|
3,949
|
1,911
|
|||||||
|
Unallocated
amounts
|
12,125
|
2,452
|
1,302
|
|||||||
|
Total
|
$
|
146,945
|
$
|
99,309
|
$
|
48,932
|
||||
|
(1)
|
Includes
oil and gas price risk management gains (losses),
net.
|
|
(2)
|
Includes
$8.1 million and $11.1 million in exploration costs and $31.3 million
and
$19.3 million in DD&A for the years ended December 31, 2006 and 2005,
respectively.
|
|
(3)
|
Includes
$1.9 million and $1.5 million in DD&A for the years ended December 31,
2006 and 2005, respectively.
|
|
(4)
|
Includes
interest income for PDC operations, $0.6 and $0.3 million in interest
income allocated to Natural gas marketing for the years ended December
31,
2006 and 2005, respectively, in addition to partnership management
fees.
|
|
(5)
|
Includes
$0.5 million and $0.3 million in DD&A for the years ended December 31,
2006 and 2005, respectively.
|
|
(6)
|
Amount
was expended in early 2007 in LKE transactions; the assets and liabilities
of which will be included in the oil and gas sales
segment.
|
PETROLEUM
DEVELOPMENT CORPORATION
NOTE
18 - SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities (Unaudited)
Costs
incurred by the Company in oil and gas property acquisition, exploration and
development are presented below (in thousands).
|
Year
ended December 31,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
Acquisition
of properties:
|
||||||||||
|
Unproved
properties
|
$
|
11,926
|
$
|
16,910
|
$
|
4,583
|
||||
|
Proved
properties
|
802
|
1,608
|
720
|
|||||||
|
Development
costs
|
114,487
|
68,605
|
32,700
|
|||||||
|
Exploration
costs
|
20,894
|
12,943
|
4,170
|
|||||||
|
Total
costs incurred
|
$
|
148,109
|
$
|
100,066
|
$
|
42,173
|
||||
The
proved reserves attributable to the development costs in the above table were
70,499 MMcf and 3,148 MBbls for 2006, 85,624 MMcf and 1,576 MBbls for 2005,
40,716 MMcf and 358 MBbls for 2004. Of the above development costs incurred
for
the years ended December 31, 2006, 2005 and 2004, the amounts of $1 million,
$6.9 million and $1.8 million, respectively, were incurred to develop proved
undeveloped properties from the prior year end.
Property
acquisition costs include costs incurred to purchase, lease or otherwise acquire
a property. Development costs include costs incurred to gain access to and
prepare development well locations for drilling, to drill and equip development
wells, recompletions and to provide facilities to extract, treat, gather and
store oil and gas. Exploration costs include costs incurred in identifying
areas
that may warrant examination and in examining specific areas that are considered
to have prospects of containing oil and gas reserves.
Capitalized
Oil and Gas Costs (Unaudited)
Aggregate
capitalized costs for the Company related to oil and gas exploration and
production activities with applicable accumulated depreciation, depletion and
amortization are presented below (in thousands):
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
Proved
oil and gas properties
|
$
|
473,451
|
$
|
334,301
|
|||
|
Unproved
oil and gas properties
|
27,055
|
19,846
|
|||||
|
500,506
|
354,147
|
||||||
|
Less
accumulated depreciation, depletion and amortization
|
133,172
|
102,513
|
|||||
|
$
|
367,334
|
$
|
251,634
|
||||
PETROLEUM
DEVELOPMENT CORPORATION
Suspended
Well Costs (Unaudited)
The
following table lists the capitalized exploratory well costs which are pending
the determination of proved reserves (dollars
in thousands).
|
2006
|
2005
|
2004
|
||||||||
|
Beginning
balance at January 1
|
$
|
1,918
|
$
|
4,170
|
$
|
-
|
||||
|
Additions
to capitalized exploratory well costs pending the determination of
proved
reserves
|
12,016
|
6,441
|
4,170
|
|||||||
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved
reserves
|
(13,169
|
)
|
(4,523
|
)
|
-
|
|||||
|
Capitalized
exploratory well costs charged to expense
|
-
|
(4,170
|
)
|
-
|
||||||
|
Ending
balance at December 31
|
$
|
765
|
$
|
1,918
|
$
|
4,170
|
||||
As
of
December 31, 2006, the one well awaiting the determination of proved reserves
has not been capitalized for a period greater than one year.
Results
of Operations for Oil and Gas Producing Activities
(Unaudited)
The
results of operations for oil and gas producing activities (excluding marketing)
are presented below (in thousands).
|
Years
Ended December 31,
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
|
||||||||||
|
Revenue:
|
||||||||||
|
Oil
and gas sales
|
$
|
115,189
|
$
|
102,559
|
$
|
69,492
|
||||
|
Oil
and gas price risk management gain (loss), net
|
9,147
|
(9,368
|
)
|
(3,085
|
)
|
|||||
|
124,336
|
93,191
|
66,407
|
||||||||
|
Expenses:
|
||||||||||
|
Production
costs
|
20,855
|
16,194
|
14,201
|
|||||||
|
Depreciation,
depletion and amortization
|
30,988
|
19,322
|
16,680
|
|||||||
|
Exploration
costs
|
8,131
|
11,115
|
-
|
|||||||
|
59,974
|
46,631
|
30,881
|
||||||||
|
Results
of operations for oil and gas producing activities before provision
for
income taxes
|
64,362
|
46,560
|
35,526
|
|||||||
|
Provision
for income taxes
|
24,818
|
18,112
|
13,820
|
|||||||
|
Results
of operations for oil and gas producing activities (excluding corporate
overhead and interest costs)
|
$
|
39,544
|
$
|
28,448
|
$
|
21,706
|
||||
PETROLEUM
DEVELOPMENT CORPORATION
Production
costs include those costs incurred to operate and maintain productive wells
and
related equipment, including costs such as labor, repairs, maintenance,
materials, supplies, fuel consumed, insurance and production and severance
taxes. In addition, production costs include administrative expenses and
depreciation applicable to support equipment associated with these activities.
Depreciation, depletion and amortization expense includes those costs associated
with capitalized acquisition, exploration and development costs, but does not
include the depreciation applicable to support equipment. The provision for
income taxes is computed using statutory tax rates.
Net
Proved Oil and Gas Reserves (Unaudited)
The
proved reserves of oil and gas of the Company have been estimated by independent
petroleum engineers at December 31, 2006, 2005 and 2004. These reserves have
been prepared in compliance with the SEC and FASB rules which require that
reserve reports be prepared under economic and operating conditions existing
at
the Company’s year-end with no provision for price and cost escalation except by
contractual arrangements. An analysis of the change in estimated quantities
of
oil and gas reserves, all of which are located within the United States, is
shown below:
|
Oil
(MBbls)
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
Proved
developed and undeveloped reserves:
|
||||||||||
|
Beginning
of year
|
4,538
|
3,316
|
3,029
|
|||||||
|
Revisions
of previous estimates
|
35
|
80
|
305
|
|||||||
|
Beginning
of year as revised
|
4,573
|
3,396
|
3,334
|
|||||||
|
New
discoveries and extensions
|
||||||||||
|
Rocky
Mountain region
|
3,148
|
1,576
|
358
|
|||||||
|
Dispositions
to partnerships
|
(92
|
)
|
-
|
(12
|
)
|
|||||
|
Purchases
of reserves:
|
||||||||||
|
Michigan
|
-
|
-
|
-
|
|||||||
|
Rocky
Mountain region
|
274
|
5
|
17
|
|||||||
|
Appalachian
|
-
|
-
|
-
|
|||||||
|
Production
|
(631
|
)
|
(439
|
)
|
(381
|
)
|
||||
|
End
of year
|
7,272
|
4,538
|
3,316
|
|||||||
|
Proved
developed reserves:
|
||||||||||
|
Beginning
of year
|
3,860
|
3,190
|
2,889
|
|||||||
|
End
of year
|
4,629
|
3,860
|
3,190
|
|||||||
|
Natural
Gas (MMcf)
|
||||||||||
|
2006
|
2005
|
2004
|
||||||||
|
Proved
developed and undeveloped reserves:
|
||||||||||
|
Beginning
of year
|
247,288
|
197,549
|
180,998
|
|||||||
|
Revisions
of previous estimates
|
(28,067
|
)
|
(15,850
|
)
|
(10,635
|
)
|
||||
|
Beginning
of year as revised
|
219,221
|
181,699
|
170,363
|
|||||||
|
New
discoveries and extensions
|
||||||||||
|
Rocky
Mountain region
|
70,499
|
85,624
|
40,716
|
|||||||
|
Dispositions
to partnerships
|
(1,215
|
)
|
(9,556
|
)
|
(4,240
|
)
|
||||
|
Purchases
of reserves:
|
||||||||||
|
Michigan
Basin
|
35
|
47
|
96
|
|||||||
|
Rocky
Mountain region
|
3,477
|
71
|
242
|
|||||||
|
Appalachian
basin
|
222
|
434
|
744
|
|||||||
|
Production
|
(13,161
|
)
|
(11,031
|
)
|
(10,372
|
)
|
||||
|
End
of year
|
279,078
|
247,288
|
197,549
|
|||||||
|
Proved
developed reserves:
|
||||||||||
|
Beginning
of year
|
155,354
|
146,152
|
134,936
|
|||||||
|
End
of year
|
158,978
|
155,354
|
146,152
|
|||||||
PETROLEUM
DEVELOPMENT CORPORATION
Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Oil and Gas Reserves (Unaudited)
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
oil
and gas reserves. Future cash inflows are computed by applying year-end prices
of oil and gas relating to the Company's proved reserves to the 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 the end of each year 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).
|
2006
|
2005
|
2004
|
||||||||
|
Future
estimated cash flows
|
$
|
1,804,796
|
$
|
2,381,238
|
$
|
1,298,394
|
||||
|
Future
estimated production costs
|
(571,346
|
)
|
(545,683
|
)
|
(319,065
|
)
|
||||
|
Future
estimated development costs
|
(373,460
|
)
|
(207,164
|
)
|
(95,498
|
)
|
||||
|
Future
estimated income tax expense
|
(334,536
|
)
|
(633,444
|
)
|
(343,810
|
)
|
||||
|
Future
net cash flows
|
525,454
|
994,947
|
540,021
|
|||||||
|
10%
annual discount for estimated timing of cash flows
|
(309,792
|
)
|
(589,517
|
)
|
(310,593
|
)
|
||||
|
Standardized
measure of discounted future estimated net cash
flows
|
$
|
215,662
|
$
|
405,430
|
$
|
229,428
|
||||
The
following table summarizes the principal sources of change in the standardized
measure of discounted future estimated net cash flows (in
thousands).
|
2006
|
2005
|
2004
|
||||||||
|
Sales
of oil and gas production net of production costs
|
$
|
(94,337
|
)
|
$
|
(86,366
|
)
|
$
|
(55,291
|
)
|
|
|
Net
changes in prices and production costs
|
(299,721
|
)
|
208,353
|
26,768
|
||||||
|
Extensions,
discoveries, and improved recovery, less related costs
|
46,109
|
150,654
|
51,413
|
|||||||
|
Sales
of reserves
|
(3,356
|
)
|
(14,456
|
)
|
(7,565
|
)
|
||||
|
Purchase
of reserves
|
11,003
|
1,266
|
1,953
|
|||||||
|
Development
costs incurred during the period
|
20,051
|
24,035
|
8,495
|
|||||||
|
Revisions
of previous quantity estimates
|
(23,146
|
)
|
(24,130
|
)
|
6,312
|
|||||
|
Changes
in estimated income taxes
|
120,818
|
(112,054
|
)
|
(16,160
|
)
|
|||||
|
Accretion
of discount
|
62,838
|
38,241
|
33,500
|
|||||||
|
Timing
and other
|
(30,027
|
)
|
(9,541
|
)
|
(22,380
|
)
|
||||
|
Total
|
$
|
(189,768
|
)
|
$
|
176,002
|
$
|
27,045
|
|||
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 since the computations are based on a large number of estimates and
arbitrary 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 utilized
and the limitations inherent therein.
PETROLEUM
DEVELOPMENT CORPORATION
The
estimated present value of future cash flows relating to proved reserves is
extremely sensitive to prices used at any measurement period. The average prices
used for each commodity for the years ended December 31, 2006, 2005 and 2004
are
presented below.
|
Average
Price
|
|||||||
|
As
of December 31:
|
Oil
|
Gas
|
|||||
|
2006
|
$
|
57.70
|
$
|
4.96
|
|||
|
2005
|
$
|
58.25
|
$
|
8.56
|
|||
|
2004
|
$
|
41.63
|
$
|
5.87
|
|||
PETROLEUM
DEVELOPMENT CORPORATION
NOTE
19 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly
financial data for the years ended December 31, 2006 and 2005, are presented
below The sum of the quarters may not equal the total of the year's net income
per share due to changes in the weighted average shares outstanding throughout
the year (in thousands, except per share data).
|
2006
|
|||||||||||||||||||||||||
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
||||||||||||||||||||
|
|
As
Reported
(1)
|
As
Revised
(2)
|
As
Reported
(1)
|
As
Revised
(2)
|
As
Reported
(1)
|
As
Revised
(2)
|
|
||||||||||||||||||
|
Revenues:
|
|||||||||||||||||||||||||
|
Oil
and gas well drilling operations
|
$
|
5,278
|
$
|
5,278
|
$
|
3,745
|
$
|
3,745
|
$
|
2,659
|
$
|
2,659
|
$
|
6,235
|
$
|
17,917
|
|||||||||
|
Gas
sales from marketing activities
|
41,942
|
41,942
|
29,129
|
29,129
|
30,374
|
30,374
|
29,880
|
131,325
|
|||||||||||||||||
|
Oil
and gas sales
|
29,208
|
28,332
|
27,267
|
27,992
|
29,663
|
30,577
|
28,288
|
115,189
|
|||||||||||||||||
|
Well
operations and pipeline income
|
2,290
|
2,290
|
2,486
|
2,486
|
2,530
|
2,536
|
3,392
|
10,704
|
|||||||||||||||||
|
Oil
and gas price risk management gains, net
|
4,435
|
4,925
|
1,367
|
1,370
|
2,912
|
2,707
|
145
|
9,147
|
|||||||||||||||||
|
Other
income
|
3
|
3
|
21
|
21
|
1,964
|
1,964
|
233
|
2,221
|
|||||||||||||||||
|
Total
revenues
|
83,156
|
82,770
|
64,015
|
64,743
|
70,102
|
70,817
|
68,173
|
286,503
|
|||||||||||||||||
|
Costs
and expenses:
|
|||||||||||||||||||||||||
|
Cost
of oil and gas well drilling operations
|
4,081
|
4,212
|
3,159
|
3,278
|
4,311
|
3,838
|
1,289
|
12,617
|
|||||||||||||||||
|
Cost
of gas marketing activities
|
41,775
|
41,780
|
28,462
|
28,471
|
29,883
|
29,988
|
29,911
|
130,150
|
|||||||||||||||||
|
Oil
and gas production and well operations costs
|
7,261
|
6,949
|
6,770
|
6,830
|
8,762
|
8,584
|
6,658
|
29,021
|
|||||||||||||||||
|
Exploration
costs
|
1,163
|
1,208
|
1,657
|
1,898
|
1,749
|
2,180
|
2,845
|
8,131
|
|||||||||||||||||
|
General
and administrative expense
|
3,981
|
3,719
|
4,667
|
5,102
|
4,759
|
5,357
|
4,869
|
19,047
|
|||||||||||||||||
|
Depreciation,
depletion and amortization
|
6,616
|
6,587
|
7,617
|
7,605
|
8,322
|
8,300
|
11,243
|
33,735
|
|||||||||||||||||
|
Total
costs and expenses
|
64,877
|
64,455
|
52,332
|
53,184
|
57,786
|
58,247
|
56,815
|
232,701
|
|||||||||||||||||
|
Gain
on sale of leaseholds
|
-
|
-
|
-
|
-
|
328,000
|
328,000
|
-
|
328,000
|
|||||||||||||||||
|
Income
from operations
|
18,279
|
18,315
|
11,683
|
11,559
|
340,316
|
340,570
|
11,358
|
381,802
|
|||||||||||||||||
|
Interest
income
|
388
|
392
|
343
|
349
|
3,427
|
3,475
|
3,834
|
8,050
|
|||||||||||||||||
|
Interest
expense
|
(73
|
)
|
(352
|
)
|
(125
|
)
|
(436
|
)
|
(34
|
)
|
(366
|
)
|
(1,289
|
)
|
(2,443
|
)
|
|||||||||
|
Income
before income taxes
|
18,594
|
18,355
|
11,901
|
11,472
|
343,709
|
343,679
|
13,903
|
387,409
|
|||||||||||||||||
|
Income
taxes
|
6,797
|
6,710
|
4,351
|
4,192
|
132,795
|
132,795
|
5,940
|
149,637
|
|||||||||||||||||
|
Net
income
|
$
|
11,797
|
$
|
11,645
|
$
|
7,550
|
$
|
7,280
|
$
|
210,914
|
$
|
210,884
|
$
|
7,963
|
$
|
237,772
|
|||||||||
|
Basic
earnings per common share
|
$
|
0.73
|
$
|
0.72
|
$
|
0.47
|
$
|
0.45
|
$
|
13.39
|
$
|
13.39
|
$
|
0.54
|
$
|
15.18
|
|||||||||
|
Diluted
earnings per common share
|
$
|
0.73
|
$
|
0.72
|
$
|
0.47
|
$
|
0.45
|
$
|
13.33
|
$
|
13.33
|
$
|
0.54
|
$
|
15.11
|
|||||||||
|
(1)
|
As
previously reported in the corresponding Form 10-Q reclassified to
conform
to current year presentation. See Note 1 for detailed discussion
of
reclassifications which impact current year presentation. In addition,
$0.3 million was reclassified from cost of oil and gas well drilling
operations to general and administrative expense and $0.8 million
was
reclassified from oil and gas production and well operations cost
to
exploration costs in the third quarter of
2006.
|
|
(2)
|
The
revised quarterly data in the above table reflects the impact on
the
quarterly results previously reported in 2006 of the adjustments
recorded
pursuant to SEC SAB No. 108 as described in Note
1.
|
PETROLEUM
DEVELOPMENT CORPORATION
|
2005
|
||||||||||||||||
|
Quarter
|
||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
Year
|
||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil
and gas well drilling operations
|
$
|
25,366
|
$
|
28,111
|
$
|
32,267
|
$
|
14,219
|
$
|
99,963
|
||||||
|
Gas
sales from marketing activities
|
17,522
|
25,917
|
14,970
|
62,695
|
121,104
|
|||||||||||
|
Oil
and gas sales
|
18,664
|
21,543
|
28,414
|
33,938
|
102,559
|
|||||||||||
|
Well
operations and pipeline income
|
1,927
|
2,068
|
2,291
|
2,474
|
8,760
|
|||||||||||
|
Oil
and gas price risk management (losses) gains, net
|
(3,659
|
)
|
858
|
(9,922
|
)
|
3,355
|
(9,368
|
)
|
||||||||
|
Other
income
|
(243
|
)
|
1,860
|
7
|
556
|
2,180
|
||||||||||
|
Total
revenues
|
59,577
|
80,357
|
68,027
|
117,237
|
325,198
|
|||||||||||
|
Costs
and expenses:
|
||||||||||||||||
|
Cost
of oil and gas well drilling operations
|
20,644
|
23,743
|
28,734
|
15,064
|
88,185
|
|||||||||||
|
Cost
of gas marketing activities
|
17,902
|
26,177
|
14,269
|
61,296
|
119,644
|
|||||||||||
|
Oil
and gas production costs and well operations costs
|
4,093
|
4,595
|
6,379
|
5,333
|
20,400
|
|||||||||||
|
Exploration
costs
|
-
|
4,864
|
136
|
6,115
|
11,115
|
|||||||||||
|
General
and administrative expense
|
1,617
|
1,266
|
1,646
|
2,431
|
6,960
|
|||||||||||
|
Depreciation,
depletion and amortization
|
4,857
|
4,845
|
5,120
|
6,294
|
21,116
|
|||||||||||
|
Total
costs and expenses
|
49,113
|
65,490
|
56,284
|
96,533
|
267,420
|
|||||||||||
|
Gain
on sale of leaseholds
|
6,216
|
1,453
|
-
|
-
|
7,669
|
|||||||||||
|
Income
from operations
|
16,680
|
16,320
|
11,743
|
20,704
|
65,447
|
|||||||||||
|
Interest
income
|
241
|
179
|
202
|
276
|
898
|
|||||||||||
|
Interest
expense
|
(33
|
)
|
(29
|
)
|
(26
|
)
|
(129
|
)
|
(217
|
)
|
||||||
|
Income
before income taxes
|
16,888
|
16,470
|
11,919
|
20,851
|
66,128
|
|||||||||||
|
Income
taxes
|
6,248
|
6,091
|
4,413
|
7,924
|
24,676
|
|||||||||||
|
Net
income
|
$
|
10,640
|
$
|
10,379
|
$
|
7,506
|
$
|
12,927
|
$
|
41,452
|
||||||
|
Basic
earnings per common share
|
$
|
0.64
|
$
|
0.63
|
$
|
0.46
|
$
|
0.80
|
$
|
2.53
|
||||||
|
Diluted
earnings per common share
|
$
|
0.64
|
$
|
0.63
|
$
|
0.46
|
$
|
0.79
|
$
|
2.52
|
||||||
PETROLEUM
DEVELOPMENT CORPORATION
VALUATION
AND QUALIFYING ACCOUNTS AND RESERVES
(in
thousands)
|
Description
|
Beginning
balance
|
Additions
charged
to
cost
and
expenses
|
Deductions
|
Ending
balance
|
|||||||||
|
Allowance
for doubtful accounts deducted from accounts receivable in the balance
sheet
|
|||||||||||||
|
2006
|
$
|
409
|
$
|
7
|
$
|
1
|
$
|
415
|
|||||
|
2005
|
$
|
409
|
$
|
-
|
$
|
-
|
$
|
409
|
|||||
|
2004
|
$
|
487
|
$
|
-
|
$
|
78
|
(a)
|
$
|
409
|
||||
(a) Deduction
relates to the write-off of accounts receivable deemed
uncollectible.
F-38