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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] ANNUAL REPORT UNDER SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 1999
OR
[_] TRANSITION REPORT UNDER SECTION 13 OR
15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________to________
Commission file number 000-24881
PENNACO ENERGY, INC.
(Name of small business issuer as specified in its charter)
NEVADA 88-0384598
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1050 17th Street, Suite 700, Denver, Colorado 80265
(Address of principal executive offices) (Zip Code)
Issuer's telephone number: (303) 629-6700
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act: Common
Stock, par value $.001
Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past twelve (12) months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past ninety (90) days.
Yes X No___
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Check if disclosure of delinquent filers in response to Item 405 of Regulation
S-B is not contained in this form, and no disclosure will be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in part III of this Form 10-KSB or any
amendment to this Form 10-KSB.
The registrant had operating revenues of $4,550,000 for fiscal year ended
December 31, 1999.
As of March 10, 2000, the aggregate market value of the 15,652,971 shares of
voting stock held by non-affiliates of the registrant was approximately
$176,096,000 based upon the closing price of the Common Stock on March 10, 2000
of $11.25 per share.
As of March 10, 2000 there were 18,877,690 shares of the Company's common stock
outstanding.
The information called for by Part III of this form 10-KSB (Items 9, 10, 11 and
12) is incorporated by reference to the Company's Proxy Statement.
Transitional Small Business Disclosure Format. (Check One): Yes______ No X
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PENNACO ENERGY, INC.
FORM 10-KSB
For the Fiscal Year Ended December 31, 1999
TABLE OF CONTENTS
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PART I
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Page
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Item 1. Description of Business.......................................................................... 3
Item 2. Description of Property.......................................................................... 20
Item 3. Legal Proceedings................................................................................ 28
Item 4. Submission of Matters to a Vote of Security Holders.............................................. 28
PART II
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Item 5. Market for Common Equity and Related Stockholder Matters......................................... 29
Item 6. Management's Discussion and Analysis of Financial Condition...................................... 30
Item 7. Financial Statements............................................................................. 33
Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............. 55
PART III
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Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with
Section 16(a) of the Exchange Act................................................................ 56
Item 10. Executive Compensation........................................................................... 59
Item 11. Security Ownership of Certain Beneficial Owners and Management................................... 59
Item 12. Certain Relationships and Related Transactions................................................... 59
Item 13. Exhibits and Reports on Form 8-K................................................................. 59
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PART I
Item 1. Description of Business
Pennaco Energy, Inc. ("Pennaco," "we," "our," "us," or the "Company") is an
independent energy company entirely focused on the exploration, development,
acquisition, and production of natural gas from coal bed methane properties
located in the Powder River Basin of northeastern Wyoming and southeastern
Montana. Pennaco is one of the largest holders of oil and gas leases covering
coal bed methane properties in the Powder River Basin and the Company believes
it is the only publicly traded company focused solely on coal bed methane
development in the Powder River Basin. Currently, the Powder River Basin has the
highest level of drilling activity of any onshore basin in the United States.
Pennaco was the most active coal bed methane operator in the Powder River Basin
in 1999 with 473 gross wells drilled and operated by the Company, based on State
of Wyoming Oil and Gas Commission information.
As of December 31, 1999, the Company owned oil and gas lease rights with
respect to approximately 743,600 gross acres (348,800 net acres) in the Powder
River Basin. Of these amounts, 644,000 gross acres (275,000 net acres) represent
the Company's portion of the acreage contained in the Area of Mutual Interest
("AMI") that the Company shares with CMS Oil and Gas Company ("CMS"). The
Company has leasehold interests covering 99,600 gross acres and 73,800 net acres
outside the AMI, the majority of which are located near the town of Gillette,
Wyoming and referred to as the Gillette Area.
Business Activities
On November 15, 1998, the Company initiated its drilling program and had
drilled 594 gross (454 net) wells by December 31, 1999 of which 32 gross (28
net) wells were drilled in 1998 and 562 gross (426 net) wells were drilled in
1999. Of these wells, 293 gross (250 net) wells were producing, and 301 gross
(204 net) wells were shut-in but capable of producing or were in various stages
of completion, dewatering, testing or connection to a pipeline. As of December
31, 1999 the Company has drilled 440 gross wells in its Gillette Area with an
average 86% working interest and 154 gross wells in the AMI with an average 50%
working interest. The Company operates all of the 440 wells drilled in its
Gillette Area and 65 of the 154 wells drilled in the AMI.
The Company's estimated net proved reserves as of January 1, 2000, were
101.5 billion cubic feet ("Bcf") of natural gas, an 83.4 Bcf increase from the
18.1 Bcf of estimated net proved reserves reported as of January 1, 1999. The
present value of estimated future net revenues, before income taxes, as of
January 1, 2000, totaled $74.6 million, using a 10% discount rate and a December
31, 1999 natural gas price of $2.12 per thousand cubic feet ("Mcf") (CIG Rocky
Mountain spot price) held constant.
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As of March 10, 2000 the Company's net working interest production was
approximately 52 million cubic feet ("MMcf") per day, or 38 MMcf per day net
after royalty interests and fuel, from 344 producing wells.
Business Strategy
The Company's objective is to build an exploration and production
company focused on creating value for its stockholders through profitable per
share growth in reserves, production and cash flow. The Company is implementing
this strategy as follows:
. Focus activities in the Powder River Basin coal bed methane project. During
1998 and 1999, the Company drilled a total of 454 net coal bed methane
wells. Pennaco has identified in excess of 1,800 additional net drilling
locations on portions of its acreage based on drilling results to date, of
which approximately 53% are located outside the AMI, primarily in its
Gillette Area, and 47% are in the AMI. Approximately 56% of these drilling
locations are on fee or state leases and 44% are located on federal leases.
The Company currently anticipates drilling over 500 net wells during 2000.
The actual number of wells the Company drills will depend on its future
operating results, availability of capital and the ability to obtain the
requisite regulatory approvals from state and federal agencies.
. Maintain low cost drilling program. The Company's coal bed methane wells in
the Powder River Basin have generally been 350 to 900 feet deep, have
typically taken two to three days to drill and complete and have cost
between $30,000 and $60,000 per well, including costs for water discharge
facilities. In comparison to conventional oil and gas wells, Powder River
Basin coal bed methane wells can be characterized by their low capital cost
and short drilling time frame. Pennaco added 86.1 Bcf of proved reserves
during 1999, before production of 2.7 Bcf during the year, at a finding and
development cost of $0.21 per Mcf, one of the lowest among U.S. publicly
traded exploration and production companies. Pennaco's finding and
development cost calculation for 1999 is based upon capital spending of
$18.0 million associated with properties which were added to the Company's
proved reserve base during 1999. Such capital spending includes costs of
drilling, completion, water discharge facilities and leasehold interests.
. Concentrate on lower risk development and exploration. The Company believes
at by focusing its capital budget on development drilling, it reduces its
risk of drilling wells that will not produce natural gas in commercial
quantities. Prior to making a significant capital investment in development
drilling in unproved areas, the Company typically drills a five to ten-well
pilot project. The Company completed approximately thirteen pilot or
exploratory projects during 1999.
. Acquire additional property interests that add to near term drilling
inventory. Through December 31, 1999, the Company has acquired leasehold
interests covering approximately 609,800 net acres in the Powder River
Basin for $39.9 million, with an average acquisition cost of $65 per acre.
The Company has sold a total of 261,000 net acres of this acreage to CMS.
The company believes that ownership of coal bed methane properties in the
Powder River Basin will continue to be consolidated by the larger leasehold
owners in the basin resulting in more efficient development and production
operations. The Company intends to continue to be one of the
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leaders in this consolidation. While the costs to acquire leasehold
interests in the Powder River Basin have increased, the Company believes
that attractive lease acquisition opportunities are still available.
. Focus on upstream operations to minimize capital costs. The Company intends
to focus its capital spending and management resources on areas with higher
potential returns, such as drilling, well completion, production and lease
acquisition activities, while outsourcing the gas gathering, compression
and transportation functions. The Company believes this will be a more
efficient use of its funds, which will allow the Company to maintain a
rapid rate of development of its properties.
. Maintain control of operations. The Company had an average 76% working
interest in all its wells drilled as of December 31, 1999. The Company's
objective is to maintain a minimum 50% working interest in its Powder River
Basin leases and wells. The Company operates all of its 440 wells drilled
as of December 31, 1999, in the Company's Gillette Area and, in accordance
with the Company's agreement with CMS, approximately one-half of the 154
wells drilled in the AMI. By operating a majority of its producing
properties, the Company believes it has greater control over the Company's
expenses and the timing of its exploration and development operations.
CMS Transaction
On October 23, 1998, the Company entered into a definitive agreement
with CMS Oil and Gas Company, under which CMS acquired an undivided 50% working
interest in approximately 492,000 net acres of the Company's leasehold position
in the Powder River Basin for approximately $28 million. The Company acquired
that portion of the leasehold position for approximately $7 million in 1998.
Since the announcement of the Company's agreement with CMS, the jointly owned
leasehold contained in the AMI has increased from 492,000 net acres to
approximately 550,0000 net acres through additional lease acquisitions. The CMS
agreement provides that Pennaco and CMS will each operate approximately 50% of
the wells to be drilled in the AMI. All the production from leases in the AMI is
dedicated to affiliates of CMS for gathering, compression and transportation.
Under the terms of the agreement, the Company will receive
approximately $.5 million from CMS upon the transfer of 15,500 net acres
acquired by the Company in the AMI since the announcement of the transaction.
The acreage data used throughout this document assumes that the transfer of
these 15,500 net acres has been completed. The agreement provides for a
preferential purchase right to the other party in the event either CMS or
Pennaco attempts to sell a portion of its interest in the acreage covered by the
agreement. There is no preferential purchase right in the event that either
party enters into a merger, reorganization or consolidation.
Gas Gathering, Compression and Transportation
The Company plans to continue to focus its capital spending and
management resources on leasehold acquisitions, drilling, well completion and
production activities rather than gas gathering, compression and transportation
operations. Accordingly, the Company is utilizing third party gathering services
to gather, compress and transport its natural gas from the wellhead to market in
return for gathering and compression fees.
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The Company has entered into an agreement with Bear Paw Energy under which
Bear Paw Energy will construct, own and operate gas gathering systems as well as
provide gas gathering and compression services to Pennaco in the South Gillette,
North Gillette and Bonepile projects located in the Company's Gillette Area.
Under the terms of the agreement, Bear Paw Energy will charge Pennaco a fixed
fee per Mcf to gather, compress and transport its natural gas production from
the wellhead to various delivery points. The fee varies by delivery point and
amount of compression. Bear Paw Energy's gathering system is required to meet
various performance standards, and Bear Paw is subject to penalties for
underperformance. If Bear Paw Energy elects not to connect a particular well or
group of wells, the Company has the right to either construct the gathering
system or allow a third party to do so.
The Company expects that it will have the ability to move its gas
production to market on an unrestricted basis until the Gillette Area gas
production reaches approximately 100 MMcf per day. There are three primary
takeaway points in the Gillette Area. First, Bear Paw Energy's Antelope Valley
Compressor Station which opened in December 1999, has 40 MMcf per day of
takeaway capacity and is expected to be expanded to 80 MMcf per day as
production from the Gillette Area increases. The Antelope Valley facility
delivers gas on an interruptable basis to the Fort Union Gas Gathering Pipeline.
The other takeaway points, as discussed below, are Kinder Morgan's Coal Seam
Booster Compressor Station which delivers gas production to the Thunder Creek
Gas Gathering Pipeline and Western Gas Resources' Dopplebach Compressor Station
which delivers gas production to the MIGC pipeline.
On March 30, 1999, Pennaco and CMS announced that Pennaco has entered into
a gas gathering contract with an affiliate of CMS. Under this contract, the
affiliate will provide gas gathering services to Pennaco and CMS within the AMI,
which excludes the Company's Gillette Area. Under the terms of a 20-year
contract, the Company will be charged a fixed fee per Mcf for the gathering,
compression and transportation of its natural gas production from each central
metering facility located adjacent to each pod, typically 15 to 30 producing
wells, to the Fort Union gas gathering system. The fee varies by well location
within the AMI. The gathering system is required to meet various performance
measures subject to penalties for underperformance. If the gatherer elects not
to connect a particular well or group of wells, the Company has the right to
connect the well or wells at its own cost and adjust the fixed fee accordingly
or allow a third party to do so.
Pennaco's ability to market its gas production from the Gillette Area and
the Northern Fairway Area has been greatly enhanced due to the opening of
several new pipelines and gathering facilities. Previously, only two pipelines
were available to transport coal bed methane gas out of the Powder River Basin.
The MIGC pipeline, which is operated by Western Gas Resources, has recently
undergone a 40 MMcf per day expansion to 130 MMcf per day. The MIGC line runs
south through the eastern side of the Powder River Basin to interconnect with
two interstate pipelines near Glenrock, Wyoming. A subsidiary of MDU Resources
operates the 42 MMcf per day Williston Basin Interstate pipeline which runs
northeast from Recluse, Wyoming to local markets throughout eastern Montana and
North Dakota and interconnects with the Northern Border pipeline, an interstate
pipeline which travels southeast to the Chicago markets.
Four new pipelines have recently been completed to transport additional
natural gas from the Powder River Basin. On December 23, 1998, CMS Gas
Transmission and Storage, Enron Capital and Trade Resources Corporation, Western
Gas and Colorado Interstate Gas Company, a subsidiary of The Coastal
Corporation, jointly announced the formation of Fort Union Gas Gathering, LLC
("Fort Union"). The Fort Union pipeline is a 106-mile, 24-inch gathering
pipeline which began
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operations on September 1, 1999. Fort Union has an initial capacity of
approximately 450 MMcf per day of and can be expanded with additional
compression to 700 MMcf per day. The Fort Union line moves gas from the center
of the Powder River Basin to interstate pipeline interconnects near Glenrock,
Wyoming.
In September 1998, Kinder Morgan, Inc. and Devon Energy Corporation
announced the formation of Thunder Creek Gas Services LLC ("Thunder Creek"). The
Thunder Creek pipeline is a 126-mile, 24-inch gathering pipeline which began
operations on September 1, 1999. The new pipeline has an initial capacity of
approximately 450 MMcf per day of natural gas, and can be expanded with
additional compression to 700 MMcf per day. The Thunder Creek pipeline moves gas
from the center of the Powder River Basin to multiple interstate pipelines near
Douglas, Wyoming. Both Fort Union and Thunder Creek connect to the KNI, Pony
Express, WIC Powder River Lateral and Medicine Bow Lateral pipelines.
Wyoming Interstate Gas Company, a subsidiary of The Coastal Corporation,
has constructed a new 143-mile, 24-inch natural gas pipeline known as the
Medicine Bow Lateral from Glenrock to Cheyenne, Wyoming where the line
interconnects with several interstate pipelines which serve the mid-continent
and west coast regions of the U.S. as well as the central Colorado markets. The
Medicine Bow Lateral began operations in December 1999. The pipeline has
capacity of 260 MMcf per day of natural gas and can be expanded with additional
compression to over 400 MMcf per day.
In the Northern Fairway Area, gas production moves south on the Bighorn Gas
Gathering Pipeline (formerly known as the Northern Header), a 250 MMcf per day
pipeline which opened in December 1999 and connects at its southern terminus
with the Fort Union pipeline. Bighorn Gas Gathering, LLC ("Bighorn") is owned
by CMS Field Services, Northern Border Partners and Enron Corporation. Bighorn
has announced plans to expand its pipeline system north into the Company's
Border Area and west into the Company's Sheridan Area.
The Company has entered into a ten-year firm transportation agreement with
Western Gas Resources ("Western Gas"). Under the terms of the agreement, Western
Gas will compress and transport 10 MMcf per day of the Company's natural gas
delivered by Bear Paw Energy to the Doppelbock compressor station located
southwest of its Gillette Area through the MIGC Pipeline to the interconnect
with the Williston Basin Interstate pipeline at Recluse, Wyoming for a fixed fee
per Mcf. The Company has dedicated a portion of its acreage in its Gillette
Area to Western Gas Resources' transportation system in connection with this
agreement.
Pennaco has entered into a five-year firm transportation agreement with
Thunder Creek to transport 10 MMcf per day of gas on the Thunder Creek Pipeline
in return for an acreage dedication in the Company's Gillette Area. Thunder
Creek began transporting the Company's natural gas, for a fixed fee per Mcf, on
September 4, 1999, at 4.3 MMcf per day which increased to 10 MMcf per day firm
commitment beginning November 1, 1999. The agreement expires in September 2004.
Thunder Creek takes the Company's natural gas at the Coal Seam Booster located
in the Company's Gillette Area and transports the natural gas down the Thunder
Creek gathering pipeline to multiple pipeline interconnects located near
Glenrock, Wyoming.
The Company has entered into a thirteen-year firm transportation agreement
with Colorado Interstate Gas Company, an affiliate of The Coastal Corporation,
to transport gas on the Medicine Bow Lateral pipeline. The initial 6 MMcf per
day firm commitment beginning in December 1999
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escalates monthly at 250 Mcf per day reaching 15 MMcf per day in years four
through ten of the agreement, then declines monthly beginning in year eleven to
3 MMcf per day for year thirteen.
The Company has entered into a ten-year interruptible transportation
agreement with a pipeline affiliate of CMS to transport all of the Company's
natural gas produced in the AMI through the Fort Union pipeline to the Medicine
Bow Lateral. The Company has the option to convert up to 50% of its average
monthly production from the AMI over the trailing calendar year, to up to 30
MMcf per day, to a firm transportation basis.
Gas Marketing and Customers
The Company is currently a party to four long-term natural gas sales
contracts. The agreements with Interenergy Resources Corporation and Montana-
Dakota Utilities Co. are each for 5,000 million British thermal units ("MMBtu")
per day (approximately 5 MMcf per day). Each of these contracts has a one-year
term beginning April 1, 1999 and terminating March 31, 2000. The third contract
is with Aquila Energy Marketing Corporation for 5,320 MMBtu per day. The
contract began on September 1, 1999, and extends until March 31, 2000. The
fourth contract is with Black Hills Power and Light for up to 9,000 MMbtu per
day at an indexed-base price. The 12 year contract will supply gas for a new
gas fired peaking generator facility which is under construction near Gillette,
Wyoming. The balance of the Company's gas production is sold on a spot basis
for 30 days or less.
Competition
The Company competes with a number of other potential purchasers of oil and
gas leases and producing properties, many of which have greater financial
resources. The bidding for oil and gas leases has become particularly intense in
the Powder River Basin with bidders evaluating potential acquisitions with
varying product pricing parameters and other criteria that result in widely
divergent bid prices. The presence of bidders willing to pay prices higher than
are supported by the Company's evaluation criteria could further limit the
Company's ability to acquire additional oil and gas leases. In addition, low or
uncertain prices for properties can cause potential sellers to withhold or
withdraw properties from the market. The Company cannot guarantee that there
will be a sufficient number of suitable oil and gas leases available for
acquisition or that the Company can sell oil and gas leases or obtain financing
for or participants to join in the development of prospects.
In addition to competition for leasehold acreage in the Powder River Basin,
the oil and gas exploration and production industry is intensely competitive as
a whole. The Company competes against well-established companies that have
significantly greater financial, marketing, personnel and other resources than
Pennaco.
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Regulation
General
The Company's operations are affected by numerous governmental laws and
regulations including energy, environmental, conservation, tax and other laws
and regulations relating to the energy industry. Many departments and agencies,
both federal and state, are authorized by statute to issue and have issued rules
and regulations binding on the oil and natural gas industry and its individual
participants. Changes in any of these laws and regulations could have a material
adverse effect on the Company's business. In view of the many uncertainties
with respect to current and future laws and regulations, including their
applicability to Pennaco, the Company cannot predict the overall effect of such
laws and regulations on its future operations.
The Company believes that its operations comply in all material respects
with all applicable laws and regulations and that the existence and enforcement
of such laws and regulations have no more restrictive effect on the Company's
method of operations than on other similar companies in the energy industry.
Operations Under Federal or State Leases
The Company's operations under federal or state oil and gas leases will be
subject to a number of restrictions. These operations are subject to a variety
of on-site security regulations and other permits and authorizations issued by
the Bureau of Land Management, or BLM, Minerals Management Service, the Wyoming
Department of Environmental Quality and other agencies. In order to drill wells
in Wyoming on federal, state or privately-owned land, the Company is required to
file an Application for Permit to Drill with the Wyoming Oil and Gas Commission.
Drilling on acreage controlled by the federal government requires the filing of
a similar application with the BLM. While the Company has been able to obtain
required drilling permits to date, the Company cannot guarantee that permitting
requirements will not adversely effect the Company's ability to complete its
drilling program at the cost and in the time period currently anticipated.
Drilling on federal lands in a large portion of the Powder River Basin is
currently limited until the completion of an environmental impact statement, or
EIS, by the BLM. The number of drilling permits allowed on federal lands subject
to the EIS are limited until the EIS is complete. This limitation could
adversely affect the Company's ability to drill on federal lands. Approximately
50% of the Company's leases are comprised of federal acreage.
An EIS was completed in November 1999 but will only allow the issuance of
approximately 800 to 1,000 drilling permits to the oil and gas industry on
federal lands. Pennaco estimates that it will receive approximately 100 of
these permits over the next several months. A new EIS will soon be initiated to
allow the drilling of wells on federal lands beyond the limits of the existing
EIS. The BLM estimates that the new EIS will require approximately 18 months to
complete and is likely to begin in the second quarter of 2000. The BLM also
estimates that the new EIS, when completed, will allow the drilling of 15,000 to
30,000 wells on federal, state and fee lands in the Powder River Basin.
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The BLM has also initiated an environmental assessment, or EA, which is
expected to allow the drilling of up to 1,500 wells on federal lands in the
Powder River Basin for the purpose of preventing the drainage of natural gas
from federal lands by producing wells on fee or state lands. The BLM estimates
that the EA will be completed in the fourth quarter of 2000. The Company cannot
provide any assurance as to the ultimate completion date of the new EIS or EA or
that, when completed, the new EIS and EA will permit the Company to develop
wells according to its current plans.
Transportation and Sale of Natural Gas
The FERC regulates interstate natural gas pipeline transportation rates as
well as the terms and conditions of service. FERC's regulations effect the
marketing of natural gas produced by us, as well as the revenues the Company
receives for sales of natural gas. In 1985, the FERC adopted policies that make
natural gas transportation accessible to natural gas buyers and sellers on an
open-access, nondiscriminatory basis. The FERC issued Order No. 636 on April 8,
1992, which, among other things, prohibits interstate pipelines from making
sales of gas tied to the provision of other services and requires pipelines to
"unbundle" the services they provide. This has enabled buyers to obtain
natural gas supplies from multiple sources and secure independent delivery
service from the pipelines. All of the interstate pipelines subject to FERC's
jurisdiction are now operating under Order No. 636, open access tariffs. On July
29, 1998, the FERC issued a Notice of Proposed Rulemaking regarding the
regulation of short term natural gas transportation services. FERC proposes to
revise its regulations to require all available short term capacity (including
capacity released by shippers holding firm entitlements) to be allocated through
an auction process. FERC also proposes to require pipelines to offer additional
services under open access principles, such as "park and loan" services if
possible under the pipeline's operational constraints. In a related initiative,
FERC issued a Notice of Inquiry on July 29, 1998, seeking input from natural gas
industry participants and affected entities regarding many aspects of the
regulation of interstate natural gas transportation services. Among other
things, FERC is seeking input on whether to retain cost-based rate regulation
for long-term transportation services, potential changes in the manner in which
rates are designed, and the use of index driven or incentive rates for
pipelines. The July 29, 1998, Notice of Inquiry may lead to a subsequent Notice
of Proposed Rulemaking to further revise FERC's regulations.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective or their effect, if any, on its operations. The
natural gas industry historically has been closely regulated. Accordingly, the
Company cannot guarantee that the regulatory approach currently pursued by the
FERC and Congress will continue indefinitely into the future.
Production
The production of oil and natural gas is subject to regulation under a wide
range of state and federal statutes, rules, orders and regulations. State and
federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Wyoming and Montana have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum rates of production from oil and natural gas wells and the regulation of
the spacing, plugging and abandonment of wells. The
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effect of these regulations is to limit the amount of oil and natural gas that
the Company can produce from its wells and to limit the number of wells or the
locations at which the Company can drill. Additionally, each state generally
imposes a production or severance tax with respect to production and sale of
crude oil, natural gas and gas liquids within its jurisdiction.
Environmental Regulations
Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, will affect the Company's operations and costs.
In particular, the Company's exploration, development and production operations,
its activities in connection with storage and transportation of liquid
hydrocarbons and the Company's use of facilities for treating, processing or
otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. Because coal bed methane wells typically produce
significant amounts of water, the Company is required to file applications with
state and federal authorities, as applicable, to enable it to dispose of water
produced from its wells. While the Company has been able to obtain required
water disposal permits for wells drilled to date, the Company cannot guarantee
that permitting requirements will not negatively affect its ability to complete
the Company's drilling and development program at the cost and in the time
period currently anticipated. The Wyoming Department of Environmental Quality
has imposed effluent limitations that would not allow water produced from
drilling operations to be discharged on surrounding acreage. The Company and
other companies in the industry are currently seeking changes in permit
requirements that would allow the Company to discharge water into surface
drainages. If these changes are not made, it may be necessary to install and
operate evaporators or drill disposal wells to reinject the produced water back
into underground sedimentary horizons adjacent to the coal seams.
As with the energy industry generally, compliance with existing regulations
will increase the Company's overall cost of doing business. These costs include
production expenses primarily related to the control and limitation of air
emissions and the disposal of produced water, capital costs to drill exploration
and development wells resulting from expenses primarily related to the
management and disposal of drilling fluids and other oil and gas exploration
wastes and capital costs to construct, maintain and upgrade production equipment
and facilities.
The Comprehensive Environmental Response, Compensation and Liability Act,
which is commonly referred to as CERCLA and is also known as "Superfund,"
imposes liability, without regard to fault or the legality of the original act,
on classes of persons that contributed to the release of a "hazardous
substance" into the environment. These persons include the "owner" or
"operator" of the site and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. CERCLA also authorizes
the Environmental Protection Agency and, in some instances, third parties, to
act in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs they incur. In the
course of its ordinary operations, the Company may generate waste that may fall
within CERCLA's definition of a "hazardous substance." The Company may be
jointly and severally liable under CERCLA for all or part of the costs required
to clean up sites at which such wastes have been disposed.
The Company may own or lease properties that have been used for the
exploration and production of hydrocarbons in the past. Many of these properties
will have been owned by third parties whose actions with respect to the
treatment and disposal or release of hydrocarbons or other
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wastes were not under the Company's control. These properties and wastes
disposed thereon may be subject to CERCLA and analogous state laws. Under these
laws, the Company could be required to remove or remediate previously disposed
wastes, including wastes disposed of or released by prior owners or operators,
to clean up contaminated property, including contaminated groundwater; or to
perform remedial plugging operations to prevent future contamination.
Employees
As of December 31, 1999, the Company had 30 full-time employees and
utilized the services of approximately 30 consulting geologists, engineers, and
lease acquisition professionals. The Company plans to hire additional employees
as needed.
Predecessor Entities
The Company was formed under the laws of the State of Nevada on January 26,
1998, to engage in the business of oil and gas exploration, production and
marketing. The original predecessor of Pennaco was incorporated on March 12,
1985 as VCI Video Communications, Inc. in the Province of British Columbia and
subsequently changed its name to AKA Video Communications, Inc. ("AVCI"). On
March 25, 1996 the shareholders of AVCI agreed to exchange all AVCI shares for
shares of International Metal Protection, Inc. ("IMP"), Pennaco's immediate
predecessor. After said exchange AVCI became inactive and the Directors and
shareholders approved the windup of AVCI. IMP was incorporated on March 5,
1996, in the State of Wyoming. Following an exchange of all the IMP outstanding
shares in a share for share exchange with Pennaco, IMP was dissolved in February
of 1998. The Company is the sole surviving entity of the reorganization.
Risk Factors
We are a new company with a limited operating history. We may not achieve our
business goals.
We are a new company and had no revenues until April 1999. We are subject
to all the risks inherent in the development of a new business. Consequently,
there is a limited operating history upon which to base an assumption that we
will be able to successfully implement our business plans and we may not achieve
our business goals.
We depend on gas gathering, compression and transportation facilities to move
our production to market and we cannot guarantee that these facilities will be
available when needed or that we will have access to these facilities when
needed. If these facilities are not available, we will be unable to sell the
natural gas we have produced.
The marketability of our natural gas production depends in part on the
availability, proximity and capacity of gas gathering and compression systems,
pipelines and if necessary, processing facilities. To accommodate the amount of
gas expected to be produced in the area, existing pipelines must eventually be
expanded. The expansion of pipeline capacity in the area is likely to require
significant capital outlays by the pipeline companies and the related plans and
specifications are
12
<PAGE>
subject to government regulatory review, permits and approvals. This approval
process may result in delays in the commencement and completion of any pipeline
construction project. Our ability to market our natural gas production could
also be limited because much of our gas production is transported on an
interruptible basis and, therefore, the transporter could unilaterally elect to
stop transporting our natural gas due to lack of available capacity. We cannot
guarantee that our wells will not be shut-in for significant periods of time due
to the lack of capacity in existing pipelines or an interruption in the
transportation we have contracted for. Further, we cannot guarantee that
existing pipeline capacity will be expanded on a timely basis or that we will be
permitted to transport any volumes on these pipelines.
Estimates of oil and gas reserves are uncertain and inherently imprecise. Our
actual reserves could be materially less than the estimates included in this
document.
This document contains estimates of our proved natural gas reserves and the
estimated future net revenues from these reserves. These estimates are based
upon various assumptions, including assumptions relating to natural gas prices,
drilling and operating expenses, capital expenditures, taxes and the
availability of funds. The process of estimating natural gas reserves is
complex. This process requires significant judgment in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. Therefore, these estimates are inherently imprecise. Because of the
limited amount of performance data currently available for our wells, the
potential for future reserve revisions, either upward or downward, is
significantly greater than normal.
Actual future production, natural gas prices, revenues, operating expenses,
taxes, development expenditures and quantities of recoverable natural gas
reserves will most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of future net
revenues set forth in this document. Our properties may also be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.
In addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing natural gas prices
and other factors, many of which are beyond our control.
At January 1, 2000, approximately 31% of our estimated proved reserves were
undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery
of undeveloped reserves requires significant capital expenditures and successful
drilling operations. The reserve data assumes that we will make significant
capital expenditures to develop our reserves. Although we have prepared
estimates of our natural gas reserves and the costs associated with these
reserves in accordance with industry standards, we cannot assure you that the
estimated costs are accurate, that development will occur as scheduled or that
the actual results will be as estimated.
You should not assume that the present value of future net cash flows
referred to in this document is the current market value of our estimated
natural gas reserves. In accordance with SEC requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate. Any changes in consumption by natural gas purchasers or in
governmental regulations or taxation will also affect actual future net cash
flows. The timing of both the production and the expenses from the development
and production of natural gas properties will affect the timing of actual future
net cash flows from proved reserves and their present value. In addition, the
10% discount factor, which is
13
<PAGE>
required by the SEC to be used in calculating discounted future net cash flows
for reporting purposes, is not necessarily the most appropriate discount factor.
The effective interest rate at various times and the risks associated with
Pennaco or the oil and gas industry in general will affect the accuracy of the
10% discount factor.
Compliance with environmental laws and regulations could limit our drilling
activities and increase our costs to operate. In turn, this could adversely
affect our development program.
Currently, the Wyoming Department of Environmental Quality has restrictive
regulations applying to the surface disposal of water produced from our drilling
operations. We, along with other companies in the industry, are currently
seeking changes in permit requirements and department policy that would allow
operators more flexibility to discharge water into the surface drainages. If
these changes are not made, it may be necessary to install and operate treatment
facilities or to drill disposal wells to reinject the produced water back into
underground sedimentary formations adjacent to the coal seams. In the event we
are unable to obtain the appropriate permits or if applicable laws or
regulations require water to be disposed of in an alternative manner, the costs
to dispose produced water will increase. These costs could have a material
adverse effect on some of our operations in this area, including potentially
rendering future production and development in these affected areas uneconomic.
Drilling on federal lands in a large portion of the Powder River Basin is
currently limited until the completion of an environmental impact statement, or
EIS, by the BLM. The number of drilling permits allowed on federal lands subject
to the EIS are limited until the EIS is complete. This limitation could
adversely affect our ability to drill on federal lands. Approximately 50% of our
leasehold is comprised of federal acreage.
An EIS, the Existing EIS, was completed in November 1999 but will only
allow the issuance of approximately 800 to 1,000 drilling permits on federal
lands. Pennaco estimates that it will receive approximately 100 of these
permits over the next several months. The new EIS will allow the drilling of
wells on federal lands beyond the limits of the Existing EIS. The BLM estimates
that the new EIS, which began in the first quarter of 2000, will require
approximately 18 months to complete. The BLM also estimates that the new EIS,
when completed, will allow the drilling of 15,000 to 30,000 wells on federal,
state and fee lands in the Powder River Basin before further drilling on federal
lands is restricted. Finally, there can be no assurance that the BLM will
issue new drilling permits on federal lands, once the new EIS is complete, at a
pace that will allow the Company to meet its drilling and growth objectives.
The BLM has also initiated an environmental assessment, or EA, which is
expected to allow the drilling of up to 1,500 wells on federal lands in the
Powder River Basin for the purpose of preventing the drainage of natural gas
from federal lands by producing wells on adjoining fee or state lands. The BLM
estimates that the EA will be completed in the fourth quarter of 2000. We
cannot provide any assurance as to the ultimate completion date of the EIS or EA
or that, when completed, the new EIS and EA will permit us to develop wells
according to our current plans.
We could face significant liabilities to governmental agencies and third
parties for discharging oil, natural gas or other pollutants into the air, soil
or water, and be required to spend substantial amounts on investigations,
litigation and remediation. We cannot be certain that existing environmental
laws or regulations, as interpreted now or in the future, or future laws or
regulations
14
<PAGE>
will not materially adversely affect our results of operations and financial
condition or that we will not face material indemnity claims with respect to
properties we own.
Our industry is subject to extensive regulation which may increase our costs.
Our business is subject to substantial regulation under local, state
and federal laws relating to the exploration for, and the development,
production, marketing, pricing, transportation and storage of natural gas, as
well as environmental and safety matters. New laws or regulations, or changes to
current requirements, could have a material adverse effect on our business. In
the past, prices of natural gas have been controlled by governmental regulation
and there can be no assurance that price controls will not be implemented again.
Depressed prices for natural gas would affect our business.
Our revenues, operating results, profitability, future rate of growth
and the carrying value of our properties depend heavily on prevailing market
prices for natural gas. We expect the markets for natural gas to continue to be
volatile. Any substantial or extended decline in the price of natural gas would
have a material adverse effect on our financial condition and results of
operations. A decline could reduce our cash flow and borrowing capacity, as well
as the value and quantity of its natural gas reserves. Various factors beyond
our control will affect prices of natural gas, including:
. domestic supplies of natural gas;
. domestic economic conditions;
. marketability of production;
. the level of consumer demand;
. the price, availability and acceptance of alternative fuels;
. the availability of pipeline capacity;
. weather conditions; and
. actions of federal, state, local and foreign authorities.
These external factors and the volatile nature of the energy markets
make it difficult to estimate future prices of natural gas.
We face risks related to title to the leases we enter into that may result in
additional costs and affect our operating results.
It is customary in the oil and gas industry to acquire a leasehold
interest in a property based upon a preliminary title investigation. If the
title to the leases we plan to acquire is defective, we
15
<PAGE>
could lose the money already spent on acquisition and development, or incur
substantial costs to cure the title defect. Our oil and gas leases give us the
right to develop and produce oil and gas from the leased properties. It is
possible that the terms of our oil and gas leases may be interpreted differently
depending on the state in which the property is located. For instance, royalty
calculations can be substantially different from state to state, depending on
each state's interpretation of lease language concerning the costs of
production. We cannot guarantee that there will be no litigation concerning the
proper interpretation of the terms of our leases. Adverse decisions in such
litigation could result in material costs or the loss of one or more leases.
We face competition from other companies in the exploration and development of
natural gas and for the acquisition of suitable leasehold interests. This
competition could result in an increase in our costs to acquire leasehold
interests and/or reduce the margins we achieve on sales of natural gas.
Competition to acquire leasehold interests, as well as competition in the
oil and gas exploration and production industry as a whole, is intense. We
compete with a number of companies that possess greater financial, marketing,
personnel, and other resources than are available to us. Different companies
evaluate potential acquisitions differently. This results in widely differing
bids. If other bidders are willing to pay higher prices than we believe are
supported by our evaluation criteria, then our ability to acquire prospects
could be limited. Low or uncertain prices for leasehold interests could cause
potential sellers to withhold or withdraw properties from the market. In such an
environment, we cannot guarantee that there will be a sufficient number of
suitable prospects available for acquisition. We may also be limited in our
options for developing prospects. As consolidation continues in the Powder River
Basin we expect leasehold acquisition costs to increase. In this type of an
environment, we will be required to acquire leasehold interests for costs that
are greater than we have paid historically.
We may not be able to obtain adequate financing to execute our operating
strategy.
We will address our long-term liquidity needs through the use of bank
credit facilities, the issuance of debt and equity securities, joint venture
financing, production payments and the use of cash provided by operating
activities.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, natural gas prices and the market
value and operating performance of Pennaco. We may be unable to execute our
operating strategy if we cannot obtain capital from these sources.
Shut-in wells, curtailed production and other production interruptions may
affect our ability to do business and result in decreased revenues.
Our production may be curtailed or shut-in for considerable periods of time
due to any of the following factors:
. a lack of market demand;
16
<PAGE>
. government regulation;
. pipeline and processing interruptions;
. production allocations;
. equipment or manpower shortages;
. diminished pipeline capacity; and
. force majeure.
These curtailments may continue for a considerable period of time
resulting in a material adverse effect on our results of operations and
financial condition.
We are subject to operating risks that may not be covered by our insurance.
The exploration for and production of natural gas involves certain
operating hazards, such as:
. well blowouts;
. craterings;
. explosions;
. uncontrollable flows of natural gas or well fluids;
. fires;
. formations with abnormal pressures;
. pipeline ruptures or spills;
. pollution;
. releases of toxic gas; and
. other environmental hazards and risks.
Any of these hazards could cause us to suffer substantial losses if
they occur. We may also be liable for environmental damage caused by previous
owners of the property we have leased. As a result, substantial liabilities to
third parties or governmental entities may be incurred, the payment of which
could reduce or eliminate our funds available for acquisitions, exploration and
development or cause us to suffer losses. In accordance with customary industry
practices, we maintain insurance against some, but not all, risks and losses. We
currently carry well control insurance as well as property and general liability
insurance. We may elect to self-insure if our management believes that the cost
of insurance, although available, is excessive relative to the risks presented.
The occurrence
17
<PAGE>
of an event that is not covered, or not fully covered, by insurance could have a
material adverse effect on our financial condition and results of operations.
Exploratory drilling is an uncertain process with many risks.
Exploratory drilling involves numerous risks, including the risk that
we will not find any commercially productive natural gas reservoirs. The cost of
drilling, completing and operating wells is often uncertain, and a number of
factors can delay or prevent drilling operations, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs and the
delivery of equipment.
Our future drilling activities may not be successful, nor can we be
sure that our overall drilling success rate or our drilling success rate for
activity within a particular area will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease
rights in potential drilling locations. Although we have identified numerous
potential drilling locations, we cannot be sure that we will ever drill them or
that we will produce natural gas from them or any other potential drilling
locations.
Hedging transactions may limit our potential gains.
To manage our exposure to price risks in the marketing of our natural
gas, we may enter into natural gas price hedging arrangements with respect to a
portion of our current production. These arrangements may include futures
contracts on the New York Mercantile Exchange. While intended to reduce the
effects of volatile natural gas prices, these transactions may limit our
potential gains if natural gas prices were to rise substantially over the price
established by the hedge. In addition, such transactions may expose us to the
risk of financial loss in certain circumstances, including instances in which:
. our production is less than expected;
. there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge
arrangement;
. the counterparties to our future contracts fail to perform the
contracts; or
. a sudden, unexpected event materially impacts natural gas prices.
18
<PAGE>
The loss of key personnel could adversely affect our ability to operate.
Our operations depend on a relatively small group of key management and
technical personnel. We cannot assure you that these individuals will remain
with us for the immediate or foreseeable future. The unexpected loss of the
services of one or more of these individuals could have a detrimental effect on
Pennaco. We have entered into employment agreements with only two of our
principal executive officers, Mr. Rady and Mr. Warren. Our future success will
depend on our ability to attract and retain skilled management personnel.
Our shares that are eligible for future sale may have an adverse effect on the
price of our stock.
As of December 31, 1999, 18,813,344 shares of common stock were
outstanding. In addition, options and warrants to purchase 4,024,978 shares are
outstanding, of which 1,249,500 were exercisable at December 31, 1999. These
outstanding options and warrants are exercisable at prices ranging from $1.25 to
$11.13 per share. Sales of substantial amounts of common stock, or a perception
that such sales could occur, and the existence of options or warrants to
purchase shares of common stock at prices that may be below the then current
market price of the common stock could adversely affect the market price of the
common stock and could impair our ability to raise capital through the sale of
our equity securities.
We do not anticipate paying dividends in the foreseeable future.
We do not anticipate paying cash dividends on our common stock in the
foreseeable future. Further, our ability to pay dividends is limited by our
credit facility with US Bank.
Our articles of incorporation and bylaws have provisions that discourage
corporate takeovers and could prevent stockholders from realizing a premium on
their investment.
Provisions in our articles of incorporation, bylaws and stockholders'
rights plan and the provisions of the Nevada General Corporation Law may
encourage persons considering unsolicited tender offers or other unilateral
takeover proposals to negotiate with our board of directors rather than pursue
non-negotiated takeover attempts. Our articles of incorporation provide for a
classified board of directors. Our articles of incorporation also authorize our
board of directors to issue preferred stock without stockholder approval and to
set the rights, preferences, voting rights and other designations of those
shares as the board may determine. Additional provisions include restrictions on
business combinations and the availability of authorized but unissued common
stock. These provisions, alone or in combination with each other and with the
rights plan described below, may discourage transactions involving actual or
potential changes of control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to stockholders for
their common stock.
On February 24, 1999, our board of directors adopted a stockholders' rights
plan, under which uncertificated stock purchase rights were distributed to our
stockholders at a rate of one right for each share of common stock held of
record as of March 9, 1999. The rights plan is designed to enhance the board's
ability to prevent an acquirer from depriving stockholders of the long-term
value of their investment and to protect stockholders against attempts to
acquire Pennaco by means of unfair or abusive takeover tactics. However, the
existence of the rights plan may impede a takeover of Pennaco not supported by
the board, including a takeover that may be desired by a majority of our
stockholders or involving a premium over the prevailing stock price.
19
<PAGE>
Item 2. Description of Property
Operations
The Company is entirely focused on the exploration, development,
acquisition and production of natural gas from coal bed methane properties
located in the Powder River Basin of northeastern Wyoming and southeastern
Montana. The Company is one of the largest holders of oil and gas leases
covering coal bed methane properties in the Powder River Basin and the Company
believes it is the only publicly traded company focused solely on coal bed
methane development in the Powder River Basin. Currently, the Powder River Basin
has the highest level of drilling activity of any onshore basin in the United
States. As of December 31, 1999, the Company owned oil and gas lease rights with
respect to approximately 743,600 gross acres (348,800 net acres) in the Powder
River Basin. Of these amounts, 644,000 gross acres (275,000 net acres) represent
the Company's portion of the acreage contained in the Area of Mutual Interest
that the Company shares with CMS Oil and Gas Company. The Company has leasehold
interests covering 99,600 gross acres (73,800 net acres) outside the AMI, the
majority of which are located in the Gillette Area.
Drilling Activity
The Company drilled 562 gross (426 net) wells during 1999 and 32 gross (28
net) wells during 1998. The following table summarizes the number of
development and exploration wells drilled which were determined to be either
productive or non-productive during 1999 and 1998, all of which were natural gas
wells located in the Powder River Basin. At December 31, 1999, the Company was
drilling, completing, dewatering, or testing 268 gross (169 net) natural gas
wells which are not included in the table below.
<TABLE>
<CAPTION>
Period From
Inception
Year (January 26,
Ended 1998) to
December 31, 1999/(3)/ December 31, 1998/(3)/
---------------------- ----------------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
Development Natural Gas Wells: /(2)/
Productive /(1)/.................................. 276 251 24 20
Non Productive.................................... - - - -
--- --- --- ---
Total........................................ 276 251 24 20
--- --- --- ---
Exploratory Natural Gas Wells: /(2)/
Productive /(1)/.................................. 24 12 2 2
Non-productive.................................... - - - -
--- --- --- ---
Total........................................ 24 12 2 2
--- --- --- ---
Total Natural Gas Wells................................ 300 263 26 22
=== === === ===
</TABLE>
(1) Productive wells are producing wells and wells capable of production,
including shut-in wells.
(2) Development wells are generally wells drilled within a proved area of a
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive. Exploratory wells are generally wells drilled on the Company's
pilot projects before confirmation of commercial production.
(3) "Gross" refers to the total wells in which the Company has an interest, and
"net" refers to the gross wells multiplied by the percentage of working
interest owned by the Company.
20
<PAGE>
The wells the Company has drilled to date have each taken an average of two
to three days to drill. The total cost per well is approximately $30,000 to
$60,000 to drill and complete. The drilling portion of the total per well cost
is approximately $10,000 per well. Additionally, the cost to connect the
wellbore to the pod where the gas is metered and compressed is approximately
$15,000 to $20,000 per well including electrical and water discharge lines. In
the North Gillette and South Gillette projects, Pennaco has outsourced to Bear
Paw Energy to construct, own and operate gas gathering systems, as well as to
provide gas gathering and compression services.
The Company contracts with various parties for the provision of drilling
services and is therefore not dependent on any one party for drilling services.
Natural Gas Reserves
The table below sets forth the Company's quantities of proved natural gas
reserves as of January 1, 2000, and January 1, 1999, all of which were located
in the Powder River Basin and the present value of estimated future net revenue
attributed to those reserves. The reserve estimates were prepared for Pennaco by
Ryder Scott Company, an independent petroleum engineering firm.
<TABLE>
<CAPTION>
As of January 1,
----------------------
2000 1999
---- ----
<S> <C> <C>
Proved natural gas reserves (Bcf)................................. 101.5 18.1
======== =======
Proved developed natural gas reserves (Bcf)....................... 69.7 5.5
======== =======
Present value of estimated future net revenues, before
income taxes (1)(2) (in thousands)........................... $ 74,581 $ 8,529
======== =======
</TABLE>
(1) The CIG Rocky Mountain spot natural gas price used in the estimation of net
proved reserves and the calculation of present value was $2.12 per Mcf at
December 31, 1999, and $1.80 per Mcf at December 31, 1998.
(2) The standardized measure of discounted future net cash flows at January 1,
2000 and 1999, was $52,052,000 and $6,142,000, respectively.
In accordance with SEC requirements, estimates of the Company's proved
reserves and future net revenues are made using sales prices estimated to be in
effect as of the date of such reserve estimates and are held constant throughout
the life of the properties, with consideration of price changes only to the
extent provided by contractual arrangements. Estimated quantities of proved
reserves and future net revenues therefrom are affected by natural gas and oil
prices, which have fluctuated widely in recent years. There are numerous
uncertainties inherent in estimating natural gas and oil reserves and their
estimated values, including many factors beyond the control of the producer. The
reserve data set forth in this document represents only estimates. Reservoir
engineering is a subjective process of estimating underground accumulation of
natural gas and oil that cannot be measured in an exact manner. The accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result,
21
<PAGE>
estimates of different engineers, including those used by the Company, may vary.
In addition, estimates of reserves are subject to revision based upon actual
production, results of future development and exploration activities, prevailing
natural gas and oil prices, operating costs and other factors, which revisions
may be material. Accordingly, reserve estimates are often different from the
quantities of natural gas and oil that are ultimately recovered and are highly
dependent upon the accuracy of the assumptions upon which they are based.
In general, the volume of production from natural gas properties the
Company owns declines as reserves are depleted. Except to the extent the Company
acquires additional leasehold interests containing proved reserves or conducts
successful exploration and development activities, or both, the Company's proved
reserves will decline as reserves are produced. Volumes generated from the
Company's future activities are therefore highly dependent upon the Company's
level of success in acquiring or finding additional reserves and the costs
incurred in doing so.
Production
Pennaco began producing natural gas in late April 1999. As of March 10,
2000, the Company's net working interest production from 344 producing wells was
approximately 52 MMcf per day, or 38 MMcf per day net of royalty interests and
fuel.
The following table summarizes the Company's net production and average
unit prices and costs for the year ended December 31, 1999. The Company began
producing natural gas in late April 1999.
<TABLE>
<CAPTION>
Year Ended
December 31, 1999
-----------------
<S> <C>
Production of natural gas (MMcf)................... 2,745
=========
Average sales price of natural gas (per Mcf)....... $ 1.66 /(1)/
=========
</TABLE>
(1) Hedging and long-term sales contracts, which were entered into in February
1999, during a period of significantly lower gas prices, reduced the
Company's average realized price by $0.33 per Mcf.
Productive Wells
As of December 31, 1999, the Company owned an interest in 335 gross and 289
net productive natural gas wells. Productive wells are producing wells and wells
capable of production, including shut-in wells.
22
<PAGE>
Developed and Undeveloped Acreage
The gross and net acres of developed and undeveloped oil and gas leases the
Company held as of December 31, 1999, are summarized in the following table:
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage/(1)/ Acreage/(2)/
----------- ------------
Gross/(3)/ Net/(3)/ Gross/(3)/ Net/(3)/
---------- -------- ---------- --------
<S> <C> <C> <C> <C>
Wyoming...................... 13,400 11,500 523,500 243,800
Montana...................... - - 206,700 93,500
---------- -------- ---------- ----------
13,400 11,500 730,200 337,300
========== ======== ========== ==========
</TABLE>
(1) Developed acreage is acreage assignable to productive wells or wells
capable of production.
(2) Undeveloped acreage is leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether the acreage
contains proved reserves.
(3) "Gross" refers to the total acres in which the Company has a working
interest, and "net" refers to gross acres multiplied by the percentage of
working interest owned by the Company
A majority of the leases summarized in the preceding table will expire at
the end of their respective primary terms unless the existing leases are renewed
or production has been obtained from the acreage subject to the lease prior to
that date, in which event the lease will remain in effect until the cessation of
production. The following table sets forth the gross and net acres to leases
summarized in the preceding table that will expire during the period indicated:
<TABLE>
<CAPTION>
Acres Expiring Twelve Months Ending: Undeveloped Acreage
----------------------------------- -------------------
Gross Net
----- ---
<S> <C> <C>
December 31, 2000............................. 9,000 5,600
December 31, 2001............................. 9,800 8,400
December 31, 2002............................. 55,200 17,200
December 31, 2003............................. 225,500 89,000
December 31, 2004 and thereafter.............. 377,800 185,300
-------- ---------
Primary Term Acreage.......................... 677,300 305,500
Held by Production Acreage (1)................ 52,900 31,800
-------- ---------
Total Undeveloped Acreage..................... 730,200 337,300
======== =========
</TABLE>
(1) Held by production acreage, for purposes of this table, is leasehold
interest in oil and gas properties which are being kept in force by virtue
of production of oil or gas in commercial quantities from formations other
than coal beds
Coal Bed Methane Versus Conventional Natural Gas
Methane is the primary commercial component of the natural gas stream
produced from conventional natural gas wells. Methane also exists in its natural
state in coal seams. Natural gas produced from conventional natural gas wells
also contains, in varying amounts, other hydrocarbons, which generally require
the natural gas to be processed. However, the natural gas produced from coal
23
<PAGE>
beds generally contains only methane and, after simple water dehydration, is
pipeline-quality natural gas.
Coal bed methane production is similar to conventional natural gas
production in terms of the physical producing facilities and the product
produced. However, the subsurface mechanisms that allow the natural gas to move
to the wellbore and the producing characteristics of coal bed methane wells are
very different from traditional natural gas production. Unlike conventional
natural gas wells, which require a porous and permeable reservoir, hydrocarbon
migration and a natural structural or stratigraphic trap, the coal bed methane
gas is trapped (adsorbed) in the molecular structure of the coal itself until
released by pressure changes resulting from the removal of water contained in
the coal bed.
Methane is a common component of coal since methane is created as part of
the coalification process, though coals vary in their methane content per ton.
In addition to being in open spaces in the coal structure, methane is adsorbed
onto the inner coal surfaces. When the coal is exposed to lower pressures
through the de-watering process, the natural gas leaves, or desorbs from, the
coal. Whether a coal bed will produce commercial quantities of methane gas
depends on the coal quality, its content of natural gas per ton of coal, the
thickness of the coal beds, the reservoir pressure, and the existence of natural
fractures, or the permeability of the coal. Frequently, coal beds are partly or
completely saturated with water. As the water is produced, internal pressures on
the coal are decreased, allowing the natural gas to desorb from the coal and
flow to the wellbore. Contrary to conventional natural gas wells, new coal bed
methane wells often initially produce water for several months and then, as the
water production decreases, natural gas production increases as the coal seams
de-water and the resultant pressure on the gas held in the coal decreases.
Powder River Basin Geology
Coal bed methane is natural gas which is both generated and stored in coal
beds. The first commercial coal bed methane fields were developed in high rank
bituminous coals located in the Appalachians and the San Juan Basin of Colorado
and New Mexico. Powder River Basin coals are lower rank subbituminous coals.
These coals are among the thickest coals in the world and occur within the
Tongue River Member of the Paleocene Fort Union and lower Eocene Wasatch
formations. Depending on the location within the Powder River Basin, the coals
may be arranged in as many as ten distinct coal beds individually ranging in
thickness from 5 to 200 feet.
Higher rank bituminous coals contain natural gas that is thermally
generated by heat and pressure. Lower rank Powder River Basin coals contain
natural gas that is primarily created by the alteration of the coal by bacteria,
or biogenesis. While the Powder River Basin coals have lower natural gas content
per ton of coal than most Appalachian or San Juan Basin coals, the Powder River
coal beds are generally thicker, shallower and more permeable, resulting in
lower drilling and completion costs and attractive production economics.
Powder River Basin Properties
As of December 31, 1999, the Company owned oil and gas leases covering
approximately 348,800 net acres in the Powder River Basin. Approximately 50% of
the leasehold acreage is located on federal land, 6% on state land and
approximately 44% of the leasehold acreage is located on
24
<PAGE>
private or fee land. The Company's leases generally have five to ten year
primary terms. The federal leases are generally ten year term leases and newly
acquired fee and state leases are generally five year term leases.
The Company's Powder River Basin leasehold can generally be divided into
four separate project areas as follows:
Gillette Area
The Company holds approximately 51,900 net acres of leases in this area
located primarily near the town of Gillette, Wyoming. All of the Company's
acreage in this area are outside of the Pennaco/CMS AMI. Approximately 10,900
net acres (21%) are developed. The Company began its initial drilling program in
this area and 440 of its 594 gross wells drilled as of December 31, 1999, were
located in the Gillette Area. The Company operates 100% of its Gillette Area
wells where the Company has an average working interest of 86%. As of March 10,
2000 approximately 314 gross wells in the Company's Gillette Area were
producing, while 209 wells were either shut-in awaiting pipeline connection or
were in various stages of being tested, dewatered or connected to gas gathering
and compression systems. Most of the Company's wells in this area are drilled on
40-acre well spacing.
Pennaco's first natural gas production began flowing from this area in late
April 1999. The Company's gross gas production in the Gillette Area was 52 MMcf
per day resulting in net working interest production of approximately 50 MMcf
per day (37 MMcf per day net to Pennaco) from approximately 314 gross producing
wells as of March 10, 2000. The Company has identified over 900 net additional
drilling locations of which 147 net locations are included in its proved
undeveloped reserve base as of January 1, 2000. All of the Company's development
drilling to date has targeted a coal bed known as the Wyodak Anderson, which is
generally 60 to 75 feet thick and approximately 350 to 800 feet deep.
Further, the Company is currently testing a 45 well pilot project targeting
a deeper coal bed. This deep pilot project is drilled to approximately 1,050
feet to test the Wildcat-Moyer coal bed which lies below the Wyodak Anderson
coal and is approximately 30 to 35 feet thick. If the pilot project is
successful, the Company has over 400 net drilling locations for the Wildcat-
Moyer coal bed which would adjoin the Company's Wyodak Anderson well locations.
Northern Fairway Area
The Company holds approximately 144,000 net acres in this project area
located between the town of Gillette, Wyoming and the Montana border on the east
side of the basin. Approximately 600 net acres are currently developed.
Approximately 135,300 net acres are included in the AMI and approximately 8,700
net acres are excluded from the AMI. As of March 10, 2000, the Company and CMS
have drilled 274 gross wells in the Northern Fairway Area. Many of the wells
were drilled in five to ten-well pilot projects in 13 different pilot areas. Six
of the pilot projects are operated by Pennaco and seven are operated by CMS.
In the Northern Fairway Area, Pennaco and CMS recently began producing gas
from 44 wells in the LS Draw, Kline Draw and Wildhorse development projects. As
of March 10, 2000, gross gas production from these three projects was
approximately 4 MMcf per day. Pennaco's net working interest production in the
Northern Fairway was approximately 2 MMcf per day.
25
<PAGE>
Dewatering continues in these projects while gas production continues to
increase. CMS Field Services, also a subsidiary of CMS Energy Corporation, is in
the process of building facilities to gather and compress the gas production and
connect additional wells which have been drilled both in the LS Draw, Kline
Draw, Wildhorse and Railroad projects operated by CMS, as well as in the Felix
and Fitch Ranch projects operated by Pennaco.
In addition to the 71 gross development wells drilled in LS Draw, Kline
Draw and Wildhorse projects, Pennaco and CMS have drilled 46 gross wells in the
Felix project, 46 gross wells in the Railroad project, 52 gross wells in the
Fitch Ranch project and 35 wells in the Hank Williams project as of March 10,
2000, all located in the Northern Fairway Area. Most of these wells are either
dewatering and flow testing or awaiting connection to gas gathering and water
discharge facilities. Many of the drilling projects are testing two or three
separate coal beds that each range in thickness from 30 to 50 feet and depth
from 400 feet to 1,200 feet. Based upon drilling results to date, the Company
believes that it has identified over 800 net drilling locations in the Northern
Fairway Area.
Most of the pilot projects are drilled adjacent to the Bighorn Gas
Gathering Pipeline which was completed in December 1999. Development of areas
adjacent to the Bighorn Gas Gathering Pipeline will allow Pennaco and CMS to
connect producing wells to the pipeline quickly and move the natural gas
production to market.
Border Area
The Company holds approximately 93,500 net undeveloped acres in this
project area located in Montana adjoining the Wyoming border north of the
Northern Fairway Area and the Sheridan Area. Approximately 88,100 net acres are
included in the AMI and 5,400 net acres are excluded from the AMI. The Company
drilled one exploratory well in this area in 1999 and plans to drill two more in
2000. The Border Area has up to five coal bed targets which range in thickness
from 15 feet to 30 feet and depth from 350 feet to 900 feet. CMS plans to
eventually extend the Bighorn Gas Gathering Pipeline into this area contingent
on successful drilling results.
Sheridan Area
The Company holds approximately 59,400 net undeveloped acres in this
project area located primarily east of the town of Sheridan, Wyoming on the west
side of the basin. Approximately 51,600 net acres are included in the AMI and
7,800 net acres are excluded from the AMI. The Company has drilled three
exploratory wells in this area. CMS plans to eventually extend the Bighorn Gas
Gathering Pipeline into this area contingent on successful drilling results.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time the Company acquires oil and gas leases
covering properties for possible drilling operations. Prior to the commencement
of drilling operations, a thorough title examination of the drill site tract is
conducted by independent attorneys. Once production from a given well is
established, the Company prepares a division order title report indicating the
proper parties and percentages for payment of production proceeds, including
royalties. Based on the Company's preliminary title examination, the Company has
no reason to believe that title to the Company's leasehold properties as a whole
is not good and defensible in accordance with standards generally
26
<PAGE>
acceptable in the oil and gas industry. The Company's properties are subject to
customary royalty interests, liens incident to operating agreements, liens for
current taxes and other burdens which the Company believes do not materially
interfere with the use of or affect the value of such properties.
Office Facilities
The Company currently subleases office space in Denver, Colorado under an
agreement with Evansgroup, Inc., which expires on September 30, 2000. The
Company has entered into a short-term lease on the same property with Amstar
which expires on January 15, 2001. Both the sublease and short-term lease cover
approximately 11,500 square feet at an annual rent of approximately $173,000.
Additionally, the Company has entered into a lease on office space in a building
which is currently under construction at 16 Market Street in downtown Denver.
The 16 Market Street lease is a seven year lease that commences upon occupancy
and covers 17,000 square feet at an annual rent of approximately $490,000.
Initially, the Company expects sublet a portion of the 16 Market Street office
space to a third party.
The Company also leases office and warehouse space in Gillette, Wyoming.
The lease covers approximately 20,000 square feet at an annual rent of
approximately $67,000 through March 31, 2002.
27
<PAGE>
Item 3. Legal Proceedings
The Company may be subject from time to time to routine litigation in
connection with its oil and gas operations. The Company is not currently
involved in litigation that could have a material impact on the Company's
financial condition, results of operations, or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of 1999.
28
<PAGE>
PART II
Item 5. Market for Common Equity and Related Stockholder Matters
Since April 19, 1999, the Company's common stock has been traded on the
American Stock Exchange. From July 1, 1998, to April 16, 1999, the Company's
common stock was traded over the counter and quoted on the OTC Bulletin Board
system. The following table sets forth the high and low closing prices for the
common stock as reported on the OTC Bulletin Board system for the period from
July 1, 1998, through April 16, 1999, and on the American Stock Exchange since
April 19, 1999.
High Low
---- ---
1998:
Third quarter................................... $ 6.16 $ 3.00
Fourth quarter.................................. $ 5.38 $ 2.50
1999:
First quarter................................... $ 5.25 $ 2.97
Second quarter.................................. $12.63 $ 4.88
Third quarter................................... $12.63 $10.31
Fourth quarter.................................. $12.06 $ 7.56
2000:
First quarter (through March 10, 2000).......... $11.25 $ 7.81
As of March 10, 2000 there were approximately 4,800 holders of record of
the Company's common stock.
Dividend Policy
The Company has never paid cash dividends on its capital stock and the
Company does not anticipate paying cash dividends in the foreseeable future. Any
future determination to pay cash dividends will be at the discretion of the
Company's board of directors and will be dependent upon the Company's financial
condition, results of operations, capital requirements and other factors that
the board of directors deems relevant. In addition, the Company's credit
facility restricts its ability to pay cash dividends.
29
<PAGE>
Item 6. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following information should be read with the financial statements and
notes to the financial statements presented elsewhere in this Form 10-KSB. The
Company follows the successful efforts method of accounting for oil and gas
properties. See "Organization and Summary of Significant Accounting Policies,"
included in note 1 of the Company's financial statements.
Pennaco is an independent energy company entirely focused on the
exploration, development, acquisition, and production of natural gas from coal
bed methane properties located in the Powder River Basin of northeastern Wyoming
and southeastern Montana. The Company was a development stage company until late
April 1999, when it began producing natural gas from its coal bed methane
properties.
Results of Operations
The Company's first gas sales occurred in late April 1999 and the Company's
gas sales were limited by pipeline capacity constrains until November 1999. As
reflected in the unaudited quarterly statement of operations and summary
production, price and cost data shown below, the Company's operating activities
have grown significantly. Therefore, the Company does not believe that its
results of operations for the year ended December 31, 1999, are indicative of
the Company's expected future results.
<TABLE>
<CAPTION>
Three Months Ended
---------------------------------------------------
Year Ended
March 31, June 30, September 30, December 31, December 31,
STATEMENT OF OPERATIONS DATA: 1999 1999 1999 1999 1999
---- ---- ---- ---- ----
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Revenue:
Natural gas revenue....................... $ - $ 628 $ 1,121 $ 2,801 $ 4,550
------- ------- ------- ------- -------
Total revenue...................... - 628 1,121 2,801 4,550
------- ------- ------- ------- -------
Operating expenses:
Production and lease operating............ - 486 789 1,653 2,928
Production taxes.......................... - 52 70 162 284
Exploration............................... 51 57 286 324 718
Depletion, depreciation and amortization... 30 118 196 467 811
General and administrative................ 1,045 1,380 1,315 1,497 5,237
------- ------- ------- ------- -------
Total expenses..................... 1,126 2,093 2,656 4,103 9,978
------- ------- ------- ------- -------
Loss from operations............................ (1,126) (1,465) (1,535) (1,302) (5,428)
Other income (expense):
Interest income.............................. 109 130 23 108 370
Interest expense............................. - - (62) - (62)
Gain on sale of properties................... 11,946 485 - 168 12,599
------- ------- ------- ------- -------
Total other income (expense)....... 12,055 615 (39) 276 12,907
------- ------- ------- ------- -------
Income (loss) before income taxes............... 10,929 (850) (1,574) (1,026) 7,479
Income tax benefit (expense).................... (3,916) 304 563 444 (2,605)
------- ------- ------- ------- -------
Net income (loss)............................... $ 7,013 $ (546) $(1,011) $ (582) $ 4,874
======= ======= ======= ======= =======
Earnings (loss) per share:
Basic..................................... $ .47 $ (.04) $ (.07) $ (.03) $ .31
======= ======= ======= ======= =======
Diluted................................... $ .44 $ (.04) $ (.07) $ (.03) $ .27
======= ======= ======= ======= =======
Weighted average common shares outstanding:
Basic.................................. 14,944 15,153 15,291 17,989 15,859
======= ======= ======= ======= =======
Diluted................................ 16,082 15,153 15,291 17,989 18,141
======= ======= ======= ======= =======
SUMMARY PRODUCTION, PRICE AND COST DATA:
Natural gas sales volume for period (MMcf)...... - 398 743 1,604 2,745
Average daily natural gas sales volume (MMcf)... - 4.4 8.1 17.4 7.5
Average realized gas price (per Mcf)............ - $1.58 $1.51 $ 1.75 $ 1.66
Per-unit cash production costs (per Mcf) (1).... - $1.35 $1.16 $ 1.13 $ 1.17
DD &A on producing gas properties (per Mcf)..... - $0.21 $0.21 $ 0.26 $ 0.24
</TABLE>
(1) Includes lease operating expenses, production taxes, gathering, compression
and transportation costs.
30
<PAGE>
The Company reported net income of $4,874,000 for the year ended December
31, 1999. This amount includes a gain on the sale of properties in connection
with the CMS transaction of $12,599,000 based upon proceeds received of
$20,415,000. During the period from its inception on January 26, 1998, through
December 31, 1998, the Company reported a net loss of $3,813,000. The Company
realized a gain on the sale of properties in the 1998 period of $1,413,000,
based on $7,600,000 of proceeds received in the first closing of the CMS
transaction which occurred on November 20, 1998.
The Company's natural gas production began in late April 1999 and resulted
in production of 398 MMcf for the three months ended June 30, 1999. The
Company's production rate increased throughout the balance of 1999 with
production totaling 743 MMcf and 1,604 MMcf for the three months ended September
30, 1999 and December 31, 1999, respectively. The Company's production rate was
constrained by pipeline takeaway capacity limitations until Bear Paw Energy
Antelope Valley Compressor Station opened in early December 1999. Net production
for the year ended December 31, 1999, totaled 2,745 MMcf. The natural gas
production was sold at an average realized price of $1.66 per Mcf. Hedging and
long-term sales contracts which were entered into in February 1999, during a
period of significantly lower gas prices, reduced the Company's average realized
price by $0.33 per Mcf for the year ended December 31, 1999. The Company entered
into the sales contracts in order to secure the last available pipeline capacity
out of the basin.
The Company's natural gas revenues totaled $628,000, $1,121,000 and
$2,801,000 for the three months ended June 30, 1999, September 30, 1999,
December 31, 1999, respectively, resulting in natural gas revenues of $4,550,000
for the year ended December 31, 1999. The Company had no revenue from operations
in 1998.
The Company's production costs have increased in each of the three month
periods of 1999 as a result of the Company's increasing production. However, on
a per Mcf basis, the Company's production costs have decreased from $1.35 per
Mcf for the three months ended June 30, 1999 to $1.16 per Mcf and $1.13 per Mcf
for the three months ended September 30, 1999 and December 31, 1999,
respectively. Production costs for the year ended December 31, 1999 were $1.17
per Mcf.
General and administrative expenses for 1999 increased over 1998 due to the
substantial increase in the scope of the Company's operations. The 1999 period
also reflects a reduction of interest expense and an increase in interest income
compared to 1998 due to the repayment of debt and increase in short-term
investments resulting from net proceeds received in the CMS transaction.
In accordance with APB No. 25 "Accounting for Stock Issued to Employees,"
the Company recognized a non-cash charge to earnings for compensation expense of
approximately $1,790,000 for the period from inception through December 31,
1998, for common stock, warrants, and options issued to certain officers and
employees. Compensation expense was calculated based on the difference between
the closing price per share on the last trading day prior to the date of
employment with Pennaco and the $1.75 per unit price for shares and warrants
purchased by one of the Company's officers hired at the beginning of July and
the option price for options awarded to officers and key employees hired in July
and August 1998. The restricted securities were offered as an incentive to
attract a senior management team. The Company believes that the offers made by
the Board of Directors were at fair market value due to the restricted nature of
the securities to be issued and the lack of a liquid trading market for the
Company's common stock at the time of the offer. However, APB No. 25 requires
the measurement of compensation expense at the date of employment rather than at
the offer date. Further, APB No. 25 requires that compensation be measured based
on the quoted market price of the stock once a Company
31
<PAGE>
stock is publicly traded. While the Company was not an SEC registrant until
September 8, 1998, the Company's shares were quoted on the OTC Bulletin Board
system beginning July 1, 1998.
Liquidity and Capital Resources
The Company's capital resources are limited. Until April 1999, the Company
had no operating revenue and the Company's main source of funds was the sale of
its equity securities and the proceeds from the CMS transaction. Since its
inception through December 31, 1999, the Company has issued equity securities
for net proceeds of $44,143,000, the most recent of which was the October 1999
sale of 2,775,000 shares of the Company's common stock resulting in net proceeds
of $28,764,000. The CMS transaction resulted in net proceeds to the Company of
$28,015,000, which were received in late 1998 and early 1999. The sale of
equity securities and the proceeds from the CMS transaction have funded the
Company's net cash used in operating activities of $3,408,000 and $3,517,000 for
the year ended December 31, 1999 and the period from January 26, 1998
(inception) to December 31,1998, as well as capital expenditures of $44,692,000
and $19,199,000 during the corresponding periods. The Company's total capital
expenditures in 1999 included $22,494,000 for drilling, completion and water
discharge, and $21,722,000 for lease acquisitions. A large portion of the
Company's capital budget in 1999 was spent on lease acquisitions and drilling
operations on properties which have yet to be fully evaluated for reserve base
purposes, but which are expected to add to Pennaco's growth in reserves and
production in the year 2000 and beyond.
On July 23, 1999, the Company entered into a revolving line of credit with
US Bank National Association which provided for loans of up to $25,000,000 with
an initial borrowing base of $10,000,000. The borrowing base was subsequently
increased to $14,000,000 and then further increased to $20,000,000 based upon
the Company's proved reserve additions through September 1999. Based upon the
Company's proved reserves at January 1, 2000, the credit facility was again
increased to provide for loans of up to $75,000,000 limited to a borrowing base
of $40,000,000 through September 30, 2000, with the capacity for expansion as
the Company's reserve base expands further. The Company had no balance
outstanding under the revolving credit facility at December 31, 1999, and as of
March 10, 2000, the Company had borrowings outstanding of $9,420,000.
The Company anticipates its cash flow from operations as well as bank debt
to provide the funds for its 2000 capital spending. Should the Company's cash
flow from operations or availability under its revolving credit agreement be
insufficient to satisfy the Company's planned capital expenditure requirements,
there can be no assurance that additional debt or equity financing will be
available to meet these requirements.
Quantitative and Qualitative Disclosures about Market Risk
The Company is exposed to market risk, including the effects of adverse
changes in commodity prices and interest rates as discussed below.
32
<PAGE>
Commodity Price Risk
The Company's financial results are affected when prices for natural gas
fluctuate. Such effects can be significant. To manage the risks related to
commodity prices and to reduce the impact of fluctuations in prices, the Company
enters into long-term contracts and uses a hedging strategy. Under the Company's
hedging strategy, the Company enters into energy swaps and uses other financial
instruments. The Company uses the hedge or deferral method of accounting for
these activities and, as a result, gains and losses on the related instruments
are generally offset by similar changes in the realized prices of the
commodities.
Long-term Sales Contracts
The Company has four long-term sales contracts for its natural gas
production. One agreement is for 5,000 MMBtu per day at a fixed price of $1.55
per MMBtu and expires March 31, 2000. Another agreement is for 5,000 MMBtu per
day at an index price less $0.38 per MMBtu and expires March 31, 2000. The third
agreement is for 5,320 MMBtu per day at an index price less $0.15 per MMBtu
through March 31, 2000. The fourth agreement is for up to 9,000 MMBtu per day
at an index price less $0.085 per MMBtu and expires March 31, 2012.
Hedging Program
In a typical swap agreement, the Company receives the difference between a
fixed price per unit of production and a price based on an agreed-upon third-
party index if the index price is lower. If the index price is higher, the
Company pays the difference. Swaps are generally settled on a monthly basis. As
of December 31, 1999, the Company had a swap in place for 5,000 MMBtu per day at
a fixed price of $2.005 per MMBtu which expires on March 31, 2000.
Interest Rate Risk
The Company's exposure to changes in interest rates results from borrowings
with floating interest rates. At the present time, the Company has no financial
instruments in place to manage the impact of changes in interest rates. As of
March 10, 2000, the Company had borrowings outstanding of $9,420,000 under its
credit facility at an interest rate of 8.3%. Amounts drawn under the facility
are repayable over a four-year term beginning in 2001.
Item 7. Financial Statements
The information concerning this item begins on the following page
33
<PAGE>
INDEPENDENT ACCOUNTANTS' REPORT
The Board of Directors
Pennaco Energy, Inc.:
We have audited the accompanying balance sheets of Pennaco Energy, Inc., as
of December 31, 1999 and 1998, and the related statements of operations,
stockholders' equity and cash flows for the year ended December 31, 1999 and for
the period from January 26, 1998 (inception) to December 31, 1998. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pennaco Energy, Inc. as of
December 31, 1999 and 1998, and the results of its operations and its cash flows
for the year ended December 31, 1999 and for the period from January 26, 1998
(inception) to December 31, 1998, in conformity with generally accepted
accounting principles.
KPMG LLP
Denver, Colorado
February 25, 2000
34
<PAGE>
PENNACO ENERGY, INC.
BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
(in thousands)
<S> <C> <C>
Current assets:
Cash and cash equivalents................................................................... $ 2,908 $ 5,623
Accounts receivable......................................................................... 5,308 375
Subscriptions receivable.................................................................... - 764
Assets held for sale........................................................................ - 6,932
Drilling deposit............................................................................ 140 333
Inventory................................................................................... 1,715 231
Prepaid expenses and other current assets................................................... 230 152
----------- ----------
Total current assets.................................................................. 10,301 14,410
----------- ----------
Property and equipment, at cost:
Natural gas properties, using the successful efforts method of accounting:
Proved........................................................................ 19,343 1,359
Unproved...................................................................... 30,006 4,657
Other property and equipment................................................................ 772 296
----------- ----------
50,121 6,312
Less accumulated depletion, depreciation and amortization................................... (873) (62)
----------- ----------
Net property and equipment............................................................. 49,248 6,250
----------- ----------
Other assets:
Deferred income taxes (note 5).............................................................. - 1,266
Other....................................................................................... 108 100
----------- ----------
Total other assets.................................................................... 108 1,366
----------- ----------
$59,657 $22,026
=========== ==========
Current liabilities:
Bridge loan payable (note 4)................................................................ $ - $ 5,600
Accounts payable .......................................................................... 7,733 1,762
Accrued liabilities......................................................................... 2,153 202
Lease acquisition payable................................................................... - 619
----------- ----------
Total current liabilities............................................................. 9,886 8,183
----------- ----------
Deferred income taxes (note 5)................................................................ 810 -
----------- ----------
Commitments (note 9)
Stockholders' equity (note 6):
Common stock, $.001 par value (Authorized 50,000,000 shares; issued and
outstanding 18,813,000 shares at December 31, 1999 and 14,795,000 shares
at December 31, 1998)..................................................................... 19 15
Additional paid-in capital.................................................................. 48,241 17,641
Retained earnings (accumulated deficit)..................................................... 701 (3,813)
----------- ----------
Total stockholders' equity............................................................ 48,961 13,843
----------- ----------
$59,657 $22,026
=========== ==========
</TABLE>
See accompanying notes to financial statements.
35
<PAGE>
PENNACO ENERGY, INC.
STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
Period From
January 26, 1998
(inception) to
Year Ended December 31,
December 31, 1999 1998
----------------- ----------------
(in thousands, except per
share amounts)
<S> <C> <C>
Revenue:
Natural gas revenue............................. $ 4,550 $ -
------------ ------------
Total revenue................................. 4,550 -
------------ ------------
Operating expenses:
Production and lease operating.................. 2,928 -
Production taxes................................ 284 -
Exploration..................................... 718 1,826
Depletion, depreciation and amortization........ 811 62
General and administrative...................... 5,237 3,977
------------ ------------
Total expenses................................ 9,978 5,865
------------ ------------
Loss from operations.............................. (5,428) (5,865)
------------ ------------
Other income (expense):
Interest income................................. 370 55
Interest expense................................ (62) (682)
Gain on sale of properties...................... 12,599 1,413
------------ ------------
Total other income............................ 12,907 786
------------ ------------
Income (loss) before income taxes................. 7,479 (5,079)
Income tax benefit (expense) (note 5)............. (2,605) 1,266
------------ ------------
Net income (loss)................................. $ 4,874 $ (3,813)
============ ============
Earnings (loss) per share:
Basic........................................... $ .31 $ (.34)
============ ============
Diluted......................................... $ .27 $ (.34)
============ ============
Weighted average common shares outstanding:
Basic........................................... 15,859 11,245
============ ============
Diluted......................................... 18,141 11,245
============ ============
</TABLE>
See accompanying notes to financial statements.
36
<PAGE>
STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Retained
Common Stock Additional Earnings
-----------------------
Paid-in (Accumulated
Shares Amount Capital Deficit) Total
--------- ---------- ------- -------- -----
(in thousands)
<S> <C> <C> <C> <C> <C>
Balance, January 26, 1998 (inception).............................. - $ - $ - $ - $ -
Common stock issued in connection with share
exchange (note 1)............................................... 995 1 (1) - -
Common stock issued for cash, net of offering costs of
$178,000 (note 6)............................................... 12,030 12 10,607 - 10,619
Compensation relating to common stock and warrants (note 7)........ - - 1,340 - 1,340
Stock option compensation (note 6)................................. - - 450 - 450
Units issued for cash, net of offering costs of $325,000 (note 6 ). 1,770 2 4,232 - 4,234
Warrants issued for properties and services (note 6)............... - - 249 - 249
Units to be issued from escrow (note 6)............................ 357 - 764 - 764
Net loss for the period............................................ - - - (3,813) (3,813)
-------- -------- --------- --------- -------
Balance, December 31, 1998......................................... 15,152 15 17,641 (3,813) 13,843
Common stock issued for options and warrants exercised............. 894 1 1,705 - 1,706
Common stock issued for cash, net of offering costs of $255,000
(note 6)...................................................... 2,775 3 28,761 - 28,764
Issuance of additional units (note 6).............................. - - 360 (360) -
Additional offering costs and other, net .......................... (8) - (226) - (226)
Net income......................................................... - - - 4,874 4,874
-------- -------- --------- --------- -------
Balance, December 31, 1999......................................... 18,813 $19 $48,241 $ 701 $48,961
======== ======== ========= ========= =======
</TABLE>
See accompanying notes to financial statements.
37
<PAGE>
PENNACO ENERGY, INC.
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Period from
January 26, 1998
Year Ended (inception) to
December 31, 1999 December 31, 1998
----------------- -----------------
(in thousands)
<S> <C> <C>
Cash flows from operating activities:
Net income (loss)................................................................ $ 4,874 $ (3,813)
Adjustments to reconcile net (loss) to net cash used in operating activities:
Gain on the sale of properties................................................ (12,599) (1,413)
Depreciation, depletion and amortization...................................... 811 62
Compensation relating to common stock and warrants issued..................... 11 1,340
Stock option compensation..................................................... - 450
Warrants issued for services.................................................. - 17
Deferred income tax expense (benefit)......................................... 2,076 (1,266)
Increases in operating assets and liabilities:
Accounts receivable........................................................ (4,933) (375)
Prepaid expenses and other current assets.................................. (78) (152)
Inventory.................................................................. (1,484) (231)
Other assets............................................................... (8) (100)
Accounts payable and accrued liabilities................................... 7,922 1,964
--------------- ---------------
Net cash used in operating activities................................... (3,408) (3,517)
--------------- ---------------
Cash flows from investing activities:
Capital expenditures............................................................. (44,692) (19,199)
Proceeds from sale of properties................................................. 20,415 7,600
Increase (decrease) in lease acquisitions payable................................ (619) 619
Other............................................................................ 193 (333)
--------------- ---------------
Net cash used in investing activities................................... (24,703) (11,313)
--------------- ---------------
Cash flows from financing activities:
Proceeds from issuance of bridge loans........................................... - 8,800
Repayment of bridge loan......................................................... (5,600) (3,200)
Proceeds from issuance of note payable........................................... - 500
Repayment of note payable........................................................ - (500)
Borrowing of long-term debt...................................................... 15,339 -
Payments of long-term debt....................................................... (15,339) -
Proceeds from issuance of common stock, net of offering costs.................... 29,290 14,853
Proceeds from exercise of options and warrants................................... 1,706 -
--------------- ---------------
Net cash provided by financing activities............................... 25,396 20,453
--------------- ---------------
Net increase (decrease) in cash and cash equivalents............................... (2,715) 5,623
Cash and cash equivalents at beginning of period.................................. 5,623 -
--------------- ---------------
Cash and cash equivalent at end of period.......................................... $ 2,908 $ 5,623
=============== ===============
Supplemental disclosures of cash flow information:
Cash paid for interest........................................................... $ 152 $ 682
=============== ===============
Cash paid for income taxes....................................................... $ 570 $ -
=============== ===============
</TABLE>
See accompanying notes to financial statements.
38
<PAGE>
PENNACO ENERGY, INC.
Notes to Financial Statements
For the year ended December 31, 1999 and the period
from January 26, 1998 (inception) to December 31, 1998
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Organization and Basis of Presentation
Pennaco Energy, Inc. (the ''Company'') is an independent exploration and
production company. The Company's current operations are completely focused on
the acquisition and development of natural gas production from coal bed methane
properties in the Powder River Basin in northeastern Wyoming and southeastern
Montana. The Company was incorporated on January 26, 1998 under the laws of the
state of Nevada and is headquartered in Denver, Colorado.
From its inception through March 31, 1999, the Company's activities had
been limited to organizational activities, prospect development activities,
acquisition of leases and option rights, and commencement of its drilling
program. In April 1999 the Company began gas production from certain of its gas
properties in the Gillette area of Wyoming. As a result, the Company is no
longer considered a development stage company.
The Company was incorporated as a wholly-owned subsidiary of International
Metal Protection Inc. (''International Metal''). Subsequently, all of the
outstanding shares of International Metal were exchanged for shares of the
Company and International Metal was merged into the Company. The 995,000 shares
issued in the exchange were recorded at their par value of $.001 per share as
International Metal had no assets or liabilities at the date of the merger.
International Metal and its predecessor, AKA Video Communications Inc., had been
inactive for the year ended December 31, 1997 and prior thereto.
(b) Reclassifications
Certain amounts in the 1998 financial statements have been reclassified to
conform to the 1999 financial statement presentation.
(c) Use Of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities in the financial statements and
the reported amounts of revenues and expenses during the reporting period,
including estimates and assumptions as to the future production from proved
developed reserves. Actual results could differ from those estimates.
39
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
(d) Significant Risks
The Company is subject to a number of risks and uncertainties inherent in
the oil and gas industry. Among these are risks related to fluctuating oil and
gas prices, uncertainties related to the estimation of oil and gas reserves and
the value of such reserves, effects of competition and extensive environmental
regulation, risks associated with the search for and the development of oil and
gas reserves, and numerous other factors, many of which are necessarily beyond
the Company's control.
The Company's financial condition and results of operations will depend
significantly upon the Company's ability to find and develop natural gas and oil
reserves and upon the prices received for natural gas and oil produced. These
prices are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the control of
the Company.
The Company's financial results are affected when prices for natural gas
fluctuate. Such effects can be significant. To manage the risks related to
commodity prices and to reduce the impact of fluctuations in prices, the Company
sometimes enters into long-term sales contracts and uses a hedging strategy. To
implement the hedging strategy, the Company enters into energy swaps and uses
other financial instruments.
(e) Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an
initial maturity of three months or less to be cash equivalents.
(f) Assets held for sale
Assets held for sale at December 31, 1998, represent the Company's basis in
properties which were subject to the CMS Agreement, but which were not sold
until 1999.
(g) Inventory
Inventory consisting primarily of materials and supplies are valued at the
lower of average cost or market.
40
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
(h) Oil and Gas Activities
The Company follows the successful efforts method of accounting for its
natural gas activities. Accordingly, costs associated with acquiring, drilling
and equipping successful exploratory wells and pilot projects are capitalized.
Geological and geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells, are charged to expense as incurred. Pilot
projects are assessed periodically and the costs associated with such projects
are charged to expense when and if the project is determined to be uneconomical.
Costs of drilling development wells, both successful and unsuccessful, are
capitalized. Upon the sale or retirement of oil and gas properties, the cost
thereof and the accumulated depreciation and depletion are removed from the
accounts and any gain or loss is recorded to operations. Upon the sale of a
partial interest in an unproved property, the proceeds are treated as a recovery
of cost. If the proceeds exceed the carrying amount of the property, a gain is
recognized in operations. Depletion of capitalized acquisition, exploration and
development costs is computed on the units-of-production method by individual
fields as the related proved reserves are produced.
Capitalized costs of unproved properties are assessed periodically and a
provision for impairment is recorded, if necessary, through a charge to
operations. During the year ended December 31, 1999, the Company capitalized
interest of $104,000 on unproved properties that are under development.
Proved oil and gas properties are assessed for impairment on a field-by-
field basis. If the net capitalized costs of proved properties exceeds the
estimated undiscounted future net cash flows from the property, a provision for
impairment is recorded to reduce the carrying value of the property to its
estimated fair value.
(i) Other Property and Equipment
Other property and equipment is recorded at cost. Depreciation and
amortization is provided using the straight-line method over the estimated
useful lives of the assets, which range from 3 to 5 years.
(j) Natural Gas Revenues
The Company uses the entitlement method of recording gas revenues. Under
such method, sales are recorded based upon the Company's proportionate share of
gas sold. The Company records a receivable or payable to the extent it receives
less or more than its proportionate share of the net gas revenues. At December
31, 1999, the Company had net gas balancing liabilities of $228,000 associated
with approximately 215 MMcf of overproduction. There was no gas balancing
liability at December 31, 1998.
41
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
(k) Income Taxes
The Company provides for income taxes using the asset and liability method
of accounting for income taxes. 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 and net operating
loss carryforwards. Deferred tax assets and liabilities are measured using
enacted income tax rates expected to apply to taxable income in the years in
which those differences are expected to be recovered or settled. Under the asset
and liability method, the effect on deferred tax assets and liabilities of a
change in income tax rates is recognized in the results of operations in the
period that includes the enactment date.
(l) Stock-based Compensation
Statement of Financial Accounting Standards No. 123, Accounting for Stock-
Based Compensation (FAS 123), defines a fair value method of accounting for
stock compensation plans. FAS 123 allows an entity to measure compensation costs
for these plans using the intrinsic value based method of accounting as
prescribed in Accounting Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (APB 25), which the Company has elected to follow. The pro
forma disclosures for the year ended December 31, 1999 and the period from
January 26, 1998 (inception) to December 31, 1998 of net income (loss) and
earnings (loss) per share required by FAS 123 are included in note 7.
(m) Earnings (Loss) Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
<TABLE>
<CAPTION>
Period from
January 26, 1998
Year Ended (inception)
December 31, to December 31,
1999 1998
----------------- --------------------
(in thousands except per share amounts)
<S> <C> <C>
Numerator for basic and diluted earnings (loss) per share--
Net income (loss)............................................... $ 4,874 $(3,813)
============ ===========
Denominator for basic earnings (loss) per share--
Weighted average shares-basic................................... 15,859 11,245
Effect of dilutive securities;
Stock warrants.............................................. 40 -
Stock options............................................... 2,242 -
------------ -----------
Denominator for diluted earnings (loss) per share--
Adjusted weighted average shares-diluted...................... 18,141 11,245
============ ===========
Basic earnings (loss) per share..................................... $ .31 $ (.34)
============ ===========
Diluted earnings (loss) per share................................... $ .27 $ (.34)
============ ===========
</TABLE>
42
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
Potentially dilutive common shares attributable to outstanding options and
warrants to purchase common shares of 310,000 and 4,185,000, were excluded from
the calculation of diluted earnings (loss) per share for the year ended December
31, 1999 and the period from January 26, 1998 (inception) to December 31, 1998,
as their effect was antidilutive.
(2) CMS TRANSACTION
On October 23, 1998, the Company and CMS Oil and Gas Company ("CMS") signed
a definitive agreement (the "CMS Agreement") relating to the development of the
Company's Powder River Basin acreage (the "CMS Transaction"). Pursuant to the
terms of the CMS Agreement, CMS acquired an undivided 50% working interest in
approximately 492,000 net undeveloped acres of the Company's leasehold position
in the Powder River Basin for $28,015,000. The Company originally acquired the
50% leasehold position that was conveyed in the CMS Transaction for
approximately $7,000,000. The purchase price in the CMS Agreement was the result
of arm's length negotiations between the Company and CMS. The joint operating
agreement between the parties is modeled after the 1989 AAPL Model Form of Joint
Operating Agreement. The CMS Agreement provides that the parties will in good
faith negotiate a development agreement for the exploration, development and
production of coal bed methane from the leases. The development agreement will
provide that each party will operate approximately 50% of the wells drilled in
the area of mutual interest. Pennaco and CMS have divided the acreage in the
area of mutual interest into project areas which will be operated by one party
or the other. Under the Company's accounting policies, the proceeds from the
sale are treated as a recovery of cost, with any additional amounts recorded as
a gain. The proceeds on the sale of these undeveloped properties exceeded their
cost. Accordingly, the Company has no basis in its retained 50% ownership in
such properties. As is customary in oil and gas leasehold transactions, the
agreement provides for the adjustment of the purchase price for title defects
discovered prior to closing and for the opportunity for one party to participate
in acquisitions made by the other party in the area of mutual interest defined
in the agreement.
The agreement also provides for a preferential purchase right to the other
party in the event either CMS or the Company attempts to sell a portion of its
interest in the acreage covered by the agreement. There is no preferential
purchase right in the event that either party enters into a merger,
reorganization or consolidation. All of the leases in the area of mutual
interest are dedicated to CMS Gas Transmission and Storage, an affiliate of
CMS, for gathering, compression and transportation.
Pursuant to the terms of the CMS Agreement executed in October 1998, CMS
paid Pennaco $5,600,000 of earnest money in the form of a non-interest bearing
bridge loan (the "CMS Bridge Loan") that was secured by substantially all of the
Company's gas leases. Approximately $3,200,000 of such amount was used to repay
existing creditors of the Company. The CMS Transaction was structured such that
the conveyance of the working interests occurred at two separate closings. The
first closing occurred on November 20, 1998, and the second occurred on January
15, 1999. The Company received $7,600,000 at the first closing and $18,600,000
at the second closing. The CMS
43
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
Bridge Loan was canceled and the security was released at the second closing.
The remaining $1,815,000 was held in escrow subject to customary closing
adjustments. Following completion of title curative work, the Company received
all of the escrow funds during the balance of 1999.
Under the terms of the CMS Agreement, CMS will pay the Company for its
share of the costs of acquiring any acreage in excess of the original 492,000
net acres in the area of mutual interest.
The joint venture acreage in the area of mutual interest includes
approximately 550,000 net acres as of December 31, 1999.
(3) LONG-TERM DEBT
On July 23, 1999 the Company entered into a revolving line of credit with
US Bank National Association ("USB") which provided for loans of up to
$25,000,000 with an initial borrowing base of $10,000,000. The borrowing base
was subsequently increased to $14,000,000 and then further increased to
$20,000,000 limited to the Company's proved reserve additions through September
1999. Based upon the Company's reserves at January 1, 2000, the credit facility
was increased to provide for loans of up to $75,000,000 limited to a borrowing
base, as determined by USB, of $40,000,000 through September 30, 2000, with the
capacity for expansion as the Company's reserve base expands further. The
credit facility is secured by mortgages on substantially all of the Company's
properties. The credit facility provides for a revolving period ending on June
30, 2001, after which the loan is to be repaid over 48 months. The credit
facility contains certain covenants, including restrictions on indebtedness,
requirements with respect to working capital and tangible net worth. Interest
is payable at a variable rate based on LIBOR or the prime rate. The Company had
no loans outstanding under the credit facility at December 31, 1999.
(4) BRIDGE LOAN
The Company borrowed $3,200,000 on September 4, 1998 under a bridge loan
with interest payable at 18% per year. The bridge loan was paid in full on
October 23, 1998 with proceeds from the CMS Transaction.
(5) INCOME TAXES
The income tax expense of $2,605,000 for the year ended December 31, 1999
includes current federal and state income tax expense of $518,000 and $11,000,
respectively, and deferred federal and state income tax expense of $2,034,000
and $42,000, respectively. The income tax benefit of $1,266,000 for the period
from inception to December 31, 1998 includes a deferred federal and state income
tax benefit of $1,196,000 and $70,000, respectively. The income tax benefit
(expense) recorded for such periods differs from the expected income tax benefit
(expense) (based on the Federal statutory rate of 34%) primarily as a result of
state income taxes, and stock and stock option compensation which is not
deductible for tax purposes.
44
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
At December 31, 1999, the Company has an alternative minimum tax credit
carryforward for federal income tax purposes of approximately $520,000 which is
available to offset future Federal taxable income, if any, indefinitely. At
December 31, 1998 the company had a net operating loss carryforward for federal
income tax purposes of approximately $431,000 which was used to offset 1999
Federal taxable income. The tax effects of temporary differences that give rise
to the deferred tax assets at December 31, 1999 and 1998, relate to the
alternative minimum tax credit carryforward and the net operating loss
carryforward, respectively. The tax effects of temporary differences that give
rise to significant portions of the deferred tax liabilities at December 31,
1999 are due to differences in depletion for oil and gas properties.
The components of the net deferred tax liability (assets) at December 31,
1999 and 1998 are presented below:
December 31,
------------------------
1999 1998
-------- --------
(in thousands)
Deferred tax liabilities.................. $ 1,330 $ -
Deferred tax assets....................... (520) (1,266)
-------- --------
Net deferred tax liabilities (assets)..... $ 810 $(1,266)
======== ========
(6) STOCKHOLDERS' EQUITY
Common Stock
During October 1999, the Company completed a public offering of 4,025,000
shares of the Company's common stock at a price to the public of $11.125 per
share, of which 2,775,000 shares were sold by the Company and 1,250,000 shares
were sold by the Company's largest shareholder at the time, RIS Resources
International Corporation. Proceeds to the Company totaled $29,019,000 after
underwriting discounts and commissions. Costs of the transaction were $255,000
resulting in net proceeds of $28,764,000.
On February 24, 1999, the Board of Directors adopted a stockholder rights
plan pursuant to which the Company distributed a dividend of one right (a
"Right") for each outstanding share of Common Stock. The Rights have anti-
takeover effects. The Rights will cause substantial dilution to a person or
group that attempts to acquire the Company on terms not approved by the Board of
Directors, except pursuant to an offer conditioned on a substantial number of
rights being acquired.
From its formation in January 1998 through December 31, 1998, the Company
completed four private placement offerings of common stock. In February 1998,
500,000 shares were issued at $0.10 per share. Proceeds to the Company were
approximately $50,000. Also in February 1998, 4,530,000 shares were issued at
$0.22 per share. Proceeds to the Company were approximately
45
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
$997,000. In April 1998, 5,000,000 shares were issued at $1.25 per share. The
proceeds to the Company were $6,250,000. In June 1998, 2,000,000 shares were
issued at $1.75 per share. Proceeds to the Company were approximately
$3,500,000. The Company incurred approximately $178,000 in offering costs
relating to these offerings, which have been charged to additional paid-in
capital.
In June 1998, the Company offered certain individuals the right to acquire
common stock at $1.75 per share along with a share purchase warrant for every
two shares purchased, conditioned upon their acceptance of employment as
officers of the Company. No compensation cost was recorded for the individuals
who commenced employment with the Company prior to July 1, 1998 (the date the
Company's common stock commenced trading on the OTC Bulletin Board) as the
estimated fair value of common stock approximated the common stock issuance
price and the warrant exercise price. Compensation expense of $450,000 was
recorded for the shares and warrants issued subsequent to July 1, 1998 based on
the difference between the closing price per share on the last trading day prior
to the date of employment with the Company and the common stock issuance price
and the warrant exercise price.
During the period from inception to December 31, 1998 a total of 796,429
units were issued at $1.75 per unit to officers and key employees of the Company
resulting in proceeds to the Company of $1,394,000. The units consist of one
share of common stock and one warrant for each two shares issued. The warrants
have an exercise price of $1.75 per share in the first year and $1.96 per share
in the second year, all of which were exercised during 1999.
Under the terms of the Company's 1998 Stock Subscription Agreements, in
September 1998 the Company issued 980,000 units at $3.25 per unit, which
includes proceeds received subsequent to December 31, 1998 of $20,000. The
units consists of i) 980,000 shares of common stock and ii) warrants to acquire
an additional 490,000 shares of common stock at an exercise price of $5.00 per
share. The Company received proceeds of approximately $3,165,000. The Company
incurred offering costs of $325,000 which were charged to additional paid-in
capital.
The Company issued 235,000 additional units under the terms of the
September 1998 Stock Subscription Agreement and placed the units in an escrow
account. Subscription payments of $764,000, which represents the aggregate
purchase price of the 235,000 units, were deposited into an escrow account,
together with certificates representing the units to be purchased. Under the
terms of the escrow agreement, the common stock shares and the shares of common
stock underlying the warrants were to be registered for resale under the
Securities Act of 1933 with the Securities and Exchange Commission by December
31, 1998. The Company has also undertaken to have the shares qualified by way of
an exemption order provided by the respective Securities Commissions in Canada.
Under the terms of the September 1998 Stock Subscription Agreement, if the
registration statement was not declared effective and the Canadian exemption
order was not obtained on or before December 31, 1998, each subscriber was
entitled to additional rights. The registration
46
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
statement was not declared effective by this date. Accordingly, as of December
31, 1998, each subscriber was entitled to elect to either receive the units from
the escrow account or receive a cash refund from the escrow account plus
interest thereon. Additionally, the Company was required to issue to the
subscribers an additional unit for each 10 units purchased in the offering. On
February 28, 1999, subscribers representing 222,500 units held in escrow elected
to receive the escrowed units and the Company received proceeds of $723,000 from
the escrow account. One subscriber representing 12,500 units elected not to
receive the escrowed units and instead received a refund from escrow of $41,000.
Therefore, the total units issued in connection with the September 1998 Stock
Subscription Agreement included the original 1,202,500 units and the 120,250
additional units required to be issued, as discussed above, for a total of
1,322,750 units. The warrants issued in connection with the units expired
unexercised on March 4, 1999. The 120,250 additional units have been reflected
in the accompanying financial statements as an increase to paid in capital and
as a reduction to retained earnings of $360,000.
(b) Warrants
At December 31, 1998, the Company has outstanding 607,500 warrants with an
exercise price of $5.00 per share. These warrants were exercisable any time
within six months of the date of issuance. The warrants expired unexercised on
March 4, 1999.
During April 1998 the Company issued warrants to purchase 128,000 shares of
common stock to a Company for corporate finance services for a period of one
year commencing April 15, 1998. The warrants were exercisable at $1.25 per share
anytime after April 15, 1999 and were to expire April 15, 2000. The estimated
fair value of the warrants issued of $17,000 was charged to expense during the
period from January 26, 1998 (inception) to December 31, 1998. In September
1998, the Company agreed to issue warrants to purchase 75,200 shares of common
stock to the same Company in connection with the placement of units in the
September 1998 unit offering. The warrants were exercisable at a price of $3.58
per share and were to expire September 4, 2000. All such warrants were
exercised during 1999 for proceeds to the Company of $429,000.
During 1998, the Company issued warrants to purchase 398,215 shares of
common stock. The warrants were exercised during 1999 resulting in proceeds to
the Company of $758,000.
The Company issued warrants to purchase 90,000 shares of common stock to
SMS Operating, LLC as partial consideration for a lease acquisition made during
November 1998. The warrants are exercisable at $4.72 per share anytime after
November 24, 1998 and expire November 24, 2002. The estimated fair value of the
warrants issued of $232,000 was capitalized as lease acquisition cost. These
warrants are still outstanding as of December 31, 1999.
47
<PAGE>
(c) Preferred Stock
In June 1999 the Company's stockholders approved the issuance by the Board
of Directors of up to 10,000,000 shares of preferred stock. No preferred stock
has been issued as of December 31, 1999.
(7) BENEFIT PLANS
On March 24, 1998, the Company adopted the 1998 Stock Option and Incentive
Plan (the Plan). The aggregate number of shares which may be issued as awards
under the Plan is 4,500,000 shares. During the year ended December 31, 1999,
292,750 options were exercised for proceeds to the Company of $519,000. No
options were exercised during the period January 26, 1998 (inception) to
December 31, 1998. Stock option activity for the Plan is as follows:
<TABLE>
<CAPTION>
Year Ended January 26, 1998 (inception) to
December 31, 1999 December 31, 1998
---------------------------------- --------------------------------------
Weighted Weighted
Average Average
Exercise Price Number of Exercise Price Number of
per Share Options per Share Options
--------- ------- --------- -------
<S> <C> <C> <C> <C>
BALANCE, BEGINNING OF PERIOD 2.74 2,886,228 $ - -
Granted 4.93 1,577,500 2.70 2,965,228
Exercised 1.77 (292,750) - -
Canceled 1.53 (236,000) 1.31 (79,000)
--------- ---------
BALANCE, END OF PERIOD 3.76 3,934,978 2.74 2,886,228
========= =========
</TABLE>
A summary of the stock options outstanding and stock options exercisable at
December 31, 1999 is as follows:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
----------------------------------------------- ---------------------------------
Weighted Average
Range of Exercise Weighted Average Remaining life Weighted Average
Prices Amount Exercise Price (Years) Amount Exercise Price
- ----------------- ---------- ---------------- ----------------- ------------ ----------------
<S> <C> <C> <C> <C> <C>
$ 1.00 - $1.99 550,000 $ 1.25 8.2 550,000 $1.25
$ 2.00 - $2.99 795,000 2.50 8.0 168,750 2.50
$ 3.00 - $3.99 1,546,478 3.21 6.5 288,750 3.21
$ 4.00 - $4.99 8,000 4.50 7.4 2,000 4.50
$ 5.00 - $5.99 600,000 5.00 8.5 150,000 5.00
$ 6.00 - $6.99 - - - - -
$ 7.00 - $7.99 120,000 7.85 7.1 - -
$ 8.00 - $8.99 9,000 8.45 7.2 - -
$ 9.00 - $9.99 182,000 9.49 6.6 - -
$10.00 - $11.13 124,500 11.07 5.4 - -
---------- -------------
$ 1.25 - $11.13 3,934,978 3.76 7.4 1,159,500 2.41
========== =============
</TABLE>
The Company applies APB Opinion 25 and related interpretations in
accounting for its stock option plans. No compensation expense has been
recognized for options granted at or above market value at date of grant.
Compensation expense of $1,340,000 has been recorded for the period from
inception to December 31, 1998 for options granted below the market value, based
upon the difference between the option price and the quoted market price at the
date of grant.
48
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
Had compensation cost for the Company's stock-based compensation plans been
determined based upon the fair value of options on the grant dates, consistent
with the provisions of SFAS 123, the Company's pro forma net income (loss) and
basic earnings (loss) per share for the year ended December 31, 1999 would have
been $3,422,000 and $0.22, respectively and for the period from January 26, 1998
(inception) to December 31, 1998 would have been $(6,447,000) and $(0.57),
respectively.
The weighted average fair value of options granted during 1999 and 1998 was
$3.68 per share and $1.34 per share, respectively. The weighted average
remaining contractual life of all options outstanding at December 31, 1999 and
1998 was approximately 7.4 and 8.8 years. The fair value of each option grant
was estimated at the date of grant using the Black-Scholes option-pricing model
with the following assumptions: no expected dividends, expected life of the
options of 1 to 10 years, volatility of 74%, for 1999 and 72% for 1998 and a
risk-free interest rate of 5.9% for 1999 and 5.5% for 1998.
During 1999, the Company adopted a 401(k) Plan for all full-time employees.
The 401(k) Plan allows for voluntary employee contributions and for
discretionary Company contributions. No Company contributions were made for the
year ended December 31, 1999.
(8) RELATED PARTY TRANSACTIONS
RIS Resources International Corporation (RIS International) owned 4,000,000
shares of the Company's common stock at December 31, 1998. A former member of
the Board of Directors of the Company also served as a consultant to RIS
International. From April 1, 1998 through June 22, 1998 he served as an officer
of the Company. Subsequently to that date he consulted with the Company and
received approximately $5,700 as compensation for his services during the period
from inception to December 31, 1998.
During the period from January 26, 1998 (inception) to December 31, 1998, a
Company for which the Company's former Chairman serves as a director provided
administrative services for the Company for which it received compensation of
approximately $16,000. In addition, the former Chairman was paid approximately
$150,000 for consulting services for the period from January 26, 1998
(inception) to December 31, 1998.
One of the Company's Directors provided legal services to the Company
during the period from January 26, 1998 (inception) to December 31, 1998. The
Director's firm was paid approximately $192,000 and the Director was paid
approximately $22,500.
49
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
(9) COMMITMENTS
(a) Employment Agreements
The Company has entered into four-year employment agreements with two
officers: (i) its President, Chief Executive Officer and Chairman and (ii) its
Chief Financial Officer and Executive Vice President. Under the terms of the
agreement with the President, Chief Executive Officer and) Chairman, if
employment is terminated without cause before the expiration of his employment
agreement in June 2002, the President, Chief Executive Officer and Chairman is
entitled to termination compensation of $3,000,000. Under terms of the
agreement with the Executive Vice President and Chief Financial Officer, if
employment is terminated without cause before July 1, 2000, the Chief Financial
Officer and Executive Vice President is entitled to termination compensation of
$750,000 and $1,250,000 if he is terminated without cause thereafter but prior
to the expiration of his employment agreement in July 2002.
(b) Lease Commitments
The Company has lease commitments for various office facilities and
equipment. Future minimum annual rental payments required under such leases for
the year ending December 31, 2000 through 2004 are $240,000, $530,000, $501,000,
$492,000 and $492,000. Rental expense for the years ended December 31, 1999 and
for the period from January 26, 1998 (inception) to December 31, 1998 totaled
$234,000 and $111,000, respectively.
(c) Long-term Sales Contracts
During the year ended December 31, 1999, the Company sold a portion of its
natural gas production through three long-term sales contracts. One agreement
is for 5,000 MMBtu per day at a fixed price of $1.55 per MMBtu and expires March
31, 2000. Another agreement is for 5,000 MMBtu per day at an index price less
$0.38 per MMBtu and expires March 31, 2000. The third agreement is for 5,320
MMBtu per day at an index price less $0.15 per MMBtu through March 31, 2000.
(d) Hedging Program
In a typical swap agreement, the Company receives the difference between a
fixed price per unit of production and a price based on an agreed-upon third-
party index if the index price is lower. If the index price is higher, the
Company pays the difference. Swaps are generally settled on a monthly basis. As
of December 31, 1999, the Company had a swap in place for 5,000 MMBtu per day at
a fixed price of $2.005 per MMBtu which expires on March 31, 2000. The Company
uses the hedge or deferral method of accounting for these activities and as a
result, gains and losses on the related instruments are generally offset by
similar charges in the realized prices of the commodities.
50
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
(10) MAJOR CUSTOMERS
The Company had three customers which accounted for in excess of 10% of the
Company's gas revenues during 1999. The sales to these customers totaled 39%,
38% and 17% of gas revenues. A discontinuance of gas sales to these three
customers would not have a material impact on the Company's operations since a
number of other companies are available to purchase its gas production. There
were no gas revenues for the period from January 26, 1998 (inception) to
December 31, 1998.
(11) SUPPLEMENTAL FINANCIAL DATA-OIL AND GAS ACTIVITIES
Capitalized costs related to oil and gas activities are as follows:
<TABLE>
<CAPTION>
December 31,
---------------------------------
1999 1998
---- ----
(in thousands)
<S> <C> <C>
Proved ...................................................... $19,343 $1,359
Unproved .................................................... 30,006 4,657
Accumulated depletion, depreciation and amortization.......... (660) -
------------ -----------
Net capitalized costs ....................................... $48,689 $6,016
============ ===========
</TABLE>
Costs incurred in oil and gas activities are as follows:
<TABLE>
<CAPTION>
Period from
January 26, 1998
Year ended (inception)
December 31, 1999 to December 31, 1998
------------------- -----------------------
(in thousands except Mcf amounts)
<S> <C> <C>
Property acquisition costs:
Proved................................................... $ 4,948 $ -
Unproved ............................................... 16,774 18,132
------------------ -----------------
Total................................................. 21,722 18,132
Development costs ......................................... 21,817 735
Exploration costs ......................................... 1,395 1,861
------------------ -----------------
Total costs incurred ...................................... $44,934 $ 20,728
================== =================
Depletion, depreciation and amortization.................... $ 660 $ -
================== =================
Depletion, depreciation and amortization per Mcf............ $ .24 $ -
================== =================
</TABLE>
51
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
Unproved property acquisition costs include costs incurred to purchase,
lease or otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, dry holes, delay rentals, and drilling and
equipping exploratory wells. Development costs include costs incurred to gain
access to and prepare development well locations for drilling, and to drill and
equip development wells.
(12) INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
The table below sets forth the Company's quantities of proved reserves as
estimated by independent petroleum engineers, all of which were located in the
United States, and the present values attributed to those reserves. Reserve
estimates are inherently imprecise and are continually subject to revisions
based on production history, results of additional exploration and development,
prices of oil and gas and other factors.
<TABLE>
<CAPTION>
Period from
January 26, 1998
Year ended (inception)
December 31, 1999 to December 31, 1998
----------------- --------------------
(Bcf)
<S> <C> <C>
Proved gas reserves:
Beginning of period.................................... 18.1 -
Extensions and discoveries............................. 85.2 18.1
Revisions of previous estimates........................ (.6) -
Purchase of reserves in place.......................... 1.5 -
Production............................................. (2.7)
---------- ----------
End of period.......................................... 101.5 18.1
========== ==========
Proved developed gas reserves, end of period............. 69.7 5.5
========== ==========
</TABLE>
52
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
Discounted Future Net Cash Flows Relating to Proved Gas Reserves are as
follows:
<TABLE>
<CAPTION>
December 31
------------------------------
1999 1998
----------- ---------
(in thousands)
<S> <C> <C>
Future cash inflows, net of production taxes............................... $144,876 $20,250
Future production costs.................................................... (45,011) (6,831)
Future development costs................................................... (4,032) (1,422)
---------- ----------
Future net cash flows before income tax.................................... 95,833 11,997
Future income tax expenses................................................. (30,180) (3,468)
---------- ----------
Future net cash flows...................................................... 65,653 8,529
10% annual discount for estimated timing of cash flows..................... (13,601) (2,387)
---------- ----------
Standardized measure of discounted future net cash flows................... $ 52,052 $ 6,142
========== ==========
Discounted future net cash flows before income taxes....................... $ 74,581 $ 8,529
========== ==========
</TABLE>
Future net cash flows are computed using year-end prices and costs. Future
corporate overhead expenses and interest expense have not been included.
The principal sources of changes in the standardized measure of discounted
future net cash flows, are as follows:
<TABLE>
<CAPTION>
Period from
January 26, 1998
Year ended (inception)
December 31, to December 31,
1999 1998
------------- ----------------
(in thousands)
<S> <C> <C>
BEGINNING OF PERIOD....................................................... $ 6,142 $ -
Sales of natural gas produced, net of production costs.................... (1,338) -
Purchases of reserves in place............................................ 1,182 -
Net changes in prices and production costs................................ 3,081
Extensions and discoveries................................................ 61,316 8,529
Previously estimated development costs incurred during the year........... 1,422 -
Revisions of previous quantity estimates.................................. (315) -
Accretion of discount..................................................... 852 -
Net change in income taxes .............................................. (20,142) (2,387)
Changes in production rates and other..................................... (148) -
------------- ----------------
END OF PERIOD .......................................................... $ 52,052 $ 6,142
============= ================
</TABLE>
53
<PAGE>
Pennaco Energy, Inc.
Notes to Financial Statements
(continued)
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves and the changes in standardized measure of
discounted future net cash flows relating to proved oil and gas reserves were
prepared in accordance with the provisions of Statement of Financial Accounting
Standards No. 69. Future cash inflows were computed by applying current prices
at year-end to estimated future production. Future production and development
costs are computed by estimating the expenditures to be incurred in developing
and producing the proved oil and gas reserves at year-end, based on year-end
costs and assuming continuation of existing economic conditions. Future income
tax expenses are calculated by applying appropriate year-end tax rates to future
pretax net cash flows relating to proved oil and gas reserves, less the tax
basis of properties involved and tax credits and loss carryforwards relating to
oil and gas producing activities. Future net cash flows are discounted at a rate
of 10% annually to derive the standardized measure of discounted future net cash
flows. This calculation procedure does not necessarily result in an estimate of
the fair market value or the present value of the Company's oil and gas
properties.
54
<PAGE>
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable
55
<PAGE>
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act
The information required by this item is incorporated by reference from the
sections entitled "Management" and "Section 16(a) Beneficial Ownership Reporting
Compliance" in the Company's definitive Proxy Statement for it's 2000 Annual
Meeting of Stockholders (the "Proxy Statement")to be filed with the Securities
and Exchange Commission no later than April 30, 2000.
Directors and Executive Officers of the Registrant
The directors and officers of the Company and their respective ages and
positions are set forth in the following table
The following tables show the Company's officers and directors:
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
Paul M. Rady........................ 46 President, Chief Executive Officer, Chairman of the
Board
Glen C. Warren, Jr.................. 43 Chief Financial Officer, Executive Vice President,
Director
Gregory V. Gibson................... 49 Vice President-Legal, Secretary, Director
Terrell A. Dobkins.................. 46 Vice President-Production
Brian A. Kuhn....................... 40 Vice President-Land
David W. Lanza...................... 31 Director
Kurt M. Petersen................... 47 Director
</TABLE>
The board of directors is divided into three separate classes. Class I
consists of Mr. Petersen, whose term will expire at the 2000 annual meeting.
Class II consists of Messrs. Warren and Lanza, whose terms will expire at the
2001 annual meeting. Class III consists of Messrs. Rady and Gibson, whose terms
will expire at the 2002 annual meeting. The term of office for directors elected
at each annual meeting is three years.
Paul M. Rady, Chief Executive Officer, President, Chairman of the Board
Mr. Rady became Chairman of the Board of Directors of Pennaco in September
1999. He joined the Company in June 1998 as its Chief Executive Officer,
President and Director. Mr. Rady has entered into an employment agreement with
an initial term of four years with automatic renewal provisions. Mr. Rady was
with Barrett Resources Corporation, an oil and gas exploration and production
company listed on the New York Stock Exchange, for approximately eight years.
During his tenure at Barrett, Mr. Rady held various executive positions
including his most recent position as Chief Executive Officer, President and
Director. As Chief Executive Officer he was responsible for all aspects of
Barrett's operations, including financings, representing the corporation to the
investment community, and working with the Board of Directors to set the
direction of the Company. Other positions held by Mr. Rady were Chief Operating
Officer, Executive Vice President-
56
<PAGE>
Exploration, and Chief Geologist-Exploration Manager. Prior to his employment at
Barrett, Mr. Rady was with Amoco Production Company based in Denver, Colorado
for approximately ten years. Mr. Rady received a Bachelor of Arts degree in
Geology from Western State College of Colorado and a Master of Science degree in
Geology from Western Washington University.
Glen C. Warren, Jr., Chief Financial Officer, Executive Vice President, Director
Mr. Warren joined the Company in July 1998 as its Chief Financial Officer,
Executive Vice President and Director. Mr. Warren has entered into an employment
contract with an initial term of four years with automatic renewal provisions.
Prior to assuming his duties as Pennaco's Chief Financial Officer, Mr. Warren
was an investment banker with Lehman Brothers Inc. in New York and focused on
equity and debt financing, as well as mergers and acquisitions for energy and
natural resource companies. Prior to Lehman Brothers, Mr. Warren was also an
investment banker with Dillon, Read & Co., Inc. and Kidder, Peabody & Co.
Incorporated with a total of nine years of investment banking experience. Mr.
Warren also has six years of oil and gas exploration and production experience
with Amoco Production Company in New Orleans. Mr. Warren received a Master of
Business Administration degree from the Anderson Graduate School of Management
at U.C.L.A. and a Juris Doctorate degree and a Bachelor of Arts degree in
Interdisciplinary Science, both from the University of Mississippi.
Gregory V. Gibson, Vice President-Legal, Secretary, Director
Mr. Gibson has been an attorney specializing in securities and securities
broker dealerships for over 15 years. Mr. Gibson is a southern California-based
practicing attorney with the law firm of Gibson, Haglund & Paulsen. Mr. Gibson
is also an officer and director of Ubrandit.com, a southern California based
company that provides internet services. Prior to his present affiliations, Mr.
Gibson was corporate counsel for three years to Global Resource Investment
Limited, a southern California-based broker-dealer specializing in resource and
foreign publicly traded securities. Prior to working at Global, Mr. Gibson was
practicing securities and international law with the law firms of Gibson &
Haglund and Gibson, Ogden & Johnson. Mr. Gibson attended Claremont Men's College
and Brigham Young University for undergraduate studies and received his Juris
Doctorate degree from Pepperdine University School of Law.
Terrell A. Dobkins, Vice President-Production
Mr. Dobkins has over 20 years of experience in the oil and gas industry.
Mr. Dobkins started his career at Amoco Production Company where he had
extensive experience in Rocky Mountain low permeability gas reservoirs and
worked in operations, completions and reservoir engineering. Mr. Dobkins worked
as a manager for three years at American Hunter Exploration where he was
involved in all U.S. operations and engineering. More recently, Mr. Dobkins
served eight years at Barrett Resources, most recently as Manager of
Acquisitions, and was involved in the development of several projects, including
completions, operations and reservoir engineering. Mr. Dobkins received a
Bachelor of Science degree in Chemical Engineering from the University of New
Mexico.
57
<PAGE>
Brian A. Kuhn, Vice President-Land
Mr. Kuhn has 19 years experience in the oil and gas industry as a landman.
Mr. Kuhn worked as a landman for 13 years at Amoco Production Company. While at
Amoco, Mr. Kuhn spent three years in the Powder River Basin and other basins of
the Rocky Mountain region. Most recently, Mr. Kuhn was employed as a Division
Landman for five years at Barrett Resources Corporation where he worked in the
Rocky Mountain region and numerous other basins. Mr. Kuhn has extensive
experience in the acquisition of producing properties, testifying as expert
witness before state regulatory agencies, management of lease acquisition and
negotiation of both large and small exploration agreements. Mr. Kuhn earned a
Bachelor of Business Administration degree in Petroleum Land Management from the
University of Oklahoma in May 1980. Mr. Kuhn is also a member of the American
Association of Petroleum Landmen and the Denver Association of Petroleum
Landmen.
David W. Lanza, Director
Mr. Lanza has been a real estate developer, oil and gas real property and
lease developer, and business owner in California, Nevada, Colorado, Texas and
Wyoming for the past ten years. He is currently the President of Hust Brothers,
a commercial real estate and development company, Vice President and principal
of Hust Brothers Inc., a national automotive wholesale company, and President
and principal of Colusa Motor Sales. Mr. Lanza has majority interest in
Marysville Auto Parts which owns and operates 13 automotive chain stores. Mr.
Lanza graduated from the University of Southern California receiving his
Bachelor of Science in Business Administration.
Kurt M. Peterson, Director
Mr. Petersen is a partner in the corporate law department of Davis, Graham
& Stubbs, LLP, a Denver law firm. Mr. Petersen has been an attorney
specializing in oil and gas, mining, real state, tax and environmental issues
for 14 years. He has extensive experience in the acquisition and divestiture of
oil and gas properties. Mr. Petersen is also a member of the Board of Trustees
of the National Outdoor Leadership School (NOLS). Mr. Petersen received a
Bachelor of Arts degree from St. Olaf College, a Masters in Education from
Harvard University and a Juris Doctorate degree from the University of Denver
College of Law.
58
<PAGE>
Item 10. Executive Compensation
The information required by this item is incorporated by reference from the
section entitled "Executive Compensation" in the Proxy Statement. Nothing in
this report shall be construed to incorporate by reference the Board
Compensation Committee Report on Executive Compensation or the Stock Performance
Graph which are contained in the Proxy Statement, but expressly not incorporated
herein.
Item 11. Security Ownership of Certain Beneficial Owners and Management
The information required by this item is incorporated by reference from the
section entitled "Security Ownership of Certain Beneficial Owners and
Management" in the Proxy Statement.
Item 12. Certain Relationships and Related Transactions
The information required by this item is incorporated by reference from the
section entitled "Certain Relationships and Other Transactions" in the Proxy
Statement.
Item 13. Exhibits and Reports on Form 8-K
Exhibit
No. Title
- --- -----
3.1 Amended and Restated Articles of Incorporation (filed as Exhibit 3.1 to
the Company's Form S-1, File No. 333- 86547 filed September 3, 1999 and
included herein by reference)
3.2 Bylaws (filed as Exhibit 3.2 to the Company's Form 10-SB, File No. 00-
24881, filed September 15, 1998 and included herein by reference)
4.1 Form of Warrant (filed as Exhibit 4.1 to the Company's Form SB-2 File
No. 333-68317, filed December 3, 1998 and included herein by reference)
10.1 Mineral Lease Purchase Agreement dated February 23, 1998 between High
Plains Associates, Inc. and Pennaco Energy, Inc. (filed as Exhibit 10.1
to the Company's Form 10-SB/A File No. 00-24881, filed September 15,
1998 and included herein by reference)
10.2 Letter Agreement dated January 23, 1998 between High Plains Associates,
Inc. and Taylor Oil Properties (filed as Exhibit 10.2 to the Company's
Form 10-SB/A File No. 00-24881, filed September 15, 1998 and included
herein by reference)
10.3 Assignment of Option and Exercise of Option dated March 6, 1998 between
High Plains Associates, Inc. and Pennaco Energy, Inc. (filed as Exhibit
10.3 to the Company's Form 10-SB/A File No. 00-24881, filed September
15, 1998 and included herein by reference)
59
<PAGE>
Exhibit
No. Title
- --- -----
10.4 Agreement dated March 6, 1998 between High Plains Associates, Inc. and
Pennaco Energy, Inc. (filed as Exhibit 10.4 to the Company's Form 10-
SB/A File No. 00-24881, filed September 15, 1998 and included herein by
reference)
10.5 Pennaco Energy, Inc. 1998 Stock Option and Incentive Plan (filed as
Exhibit 10.5 to the Company's Form 10-SB, File No. 00-24881, filed
September 15, 1998 and included herein by reference)
10.6 Form of Pennaco Energy, Inc. Incentive Stock Option Agreement (filed as
Exhibit 10.6 to the Company's Form 10-SB, File No. 00-24881, filed
September 15, 1998 and included herein by reference)
10.7 Form of Pennaco Energy, Inc. Non-Statutory Stock Option Agreement (filed
as Exhibit 10.7 to the Company's Form 10-SB, File No. 00-24881, filed
September 15, 1998 and included herein by reference)
10.8 Employment Agreement dated June 10, 1998 between Pennaco Energy, Inc.
and Paul M. Rady (filed as Exhibit 10.8 to the Company's Form 10-SB,
File No. 00-24881, filed September 15, 1998 and included herein by
reference)
10.9 Employment Agreement dated July 2, 1998 between Pennaco Energy, Inc. and
Glen C. Warren, Jr. (filed as Exhibit 10.9 to the Company's Form 10-SB,
File No. 00-24881, filed September 15, 1998 and included herein by
reference)
10.10 Secured Promissory Note dated August 13, 1998 from Pennaco Energy, Inc.
to Venture Capital Sourcing, SA (filed as Exhibit 10.10 to the Company's
Form 10-SB/A File No. 00-24881, filed September 15, 1998 and included
herein by reference)
10.11 Second Amendment to Security Agreement dated August 13, 1998 between
Pennaco Energy, Inc. and Venture Capital Sourcing, SA (filed as Exhibit
10.11 to the Company's Form 10-SB/A File No. 00-24881, filed September
15, 1998 and included herein by reference)
10.12 Purchase and Sale Agreement between Pennaco Energy, Inc., as Seller and
CMS Oil and Gas Company, as Buyer, dated October 23, 1998 (filed as
Exhibit 10.12 to the Company's Form 10-SB, File No. 00-24881, filed
September 15, 1998 and included herein by reference)
10.13 Secured Promissory Note dated October 23, 1998 from Pennaco Energy, Inc.
to CMS Oil and Gas Company (filed as Exhibit 10.13 to the Company's Form
10-SB, File No. 00-24881, filed November 24, 1998 and included herein by
reference)
10.14 Agreement Regarding the Drilling of Coal Bed Methane Wells (filed as
Exhibit 10.15 to the Company's Form 10-SB/A File No. 00-24881, filed
December 22, 1998 and included herein by reference)
10.15 First Amendment to Purchase and Sale Agreement dated November 20, 1998
(filed as Exhibit 10.16 to the Company's Form 10-SB/A File No. 00-24881,
filed January 28, 1999 and included herein by reference)
10.16 Second Amendment to Purchase and Sale Agreement dated January 15, 1999
(filed as Exhibit 10.17 to the Company's Form 10-SB/A File No. 00-24881,
filed January 28, 1999 and included herein by reference)
10.17 Gas Gathering Agreement between Bear Paw Energy, Inc. and Pennaco
Energy, Inc. dated February 1, 1999 (Portions of this Gas Gathering
Agreement have been omitted based upon a request for confidential
treatment. Additionally, the omitted portions have been filed with the
SEC. Filed as Exhibit 10.18 to the Company's Form SB-2 (Reg. No. 333-
68317) and included herein by reference)
60
<PAGE>
Exhibit
No. Title
- --- -----
10.18 Gas Gathering Agreement between CMS Continental Natural Gas, Inc. and
Pennaco Energy, Inc. dated March 1, 1999 (Portions of this Gas Gathering
Agreement have been omitted based upon a request for confidential
treatment. Additionally, the omitted portions have been filed with the
SEC. Filed as Exhibit 10.19 to the Company's Form SB-2 (Reg. No. 333-
68317) and included herein by reference)
10.19 Gas Purchase Agreement between Western Gas Resources, Inc. and Pennaco
Energy, Inc. dated April 1, 1999 (Portions of this Gas Purchase
Agreement have been omitted based upon a request for confidential
treatment. Additionally, the omitted portions have been filed with the
SEC. Filed as Exhibit 10.20 to the Company's Form SB-2 (Reg. No. 333-
68317) and included herein by reference)
10.20 Base Contract for Short-Term Sale and Purchase of Natural Gas between
Pennaco Energy, Inc. and Interenergy Resources Corporation dated April
1, 1999 (Portions of this Base Contract for Short-Term Sale and Purchase
of Natural Gas have been omitted based upon a request for confidential
treatment. Additionally, the omitted portions have been filed with the
SEC. Filed as Exhibit 10.21 to the Company's Form SB-2 (Reg. No. 333-
68317) and included herein by reference)
10.21 Gas Sales and Purchase Agreement between Montana-Dakota Utilities Co.
and Pennaco Energy, Inc. dated March 1, 1999 (Portions of this Gas Sales
and Purchase Agreement have been omitted based upon a request for
confidential treatment. Additionally, the omitted portions have been
filed with the SEC. Filed as Exhibit 10.22 to the Company's Form SB-2
(Reg. No. 333-68317) and included herein by reference)
10.22 Credit Facility (filed as Exhibit 4.1 to the Company's Form 10-QSB File
No. 001-14943 for the quarter ended June 30, 1999, and included herein
by reference).
*10.23 Amendment to Credit Facility
*23.1 Consent of KPMG LLP
*23.2 Consent of Ryder Scott Company
*27 Financial data schedule
* Filed herewith.
61
<PAGE>
SIGNATURES
In accordance with Section 12 of the Securities Exchange Act of 1934, the
registrant caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized.
PENNACO ENERGY, INC.
By: /s/ Paul M. Rady
------------------------------------
Paul M. Rady, Chairman of the Board, President
and Chief Executive Officer (Principal Executive Officer)
By: /s/ Glen C. Warren, Jr.
------------------------------------
Glen C. Warren, Jr., Executive Vice President and
Chief Financial Officer (Principal Financial and
Accounting Officer)
By: /s/ Gregory V. Gibson
------------------------------------
Vice President-Legal, Secretary and Director
By: /s/ David W. Lanza
------------------------------------
Director
By: /s/ Kurt M. Petersen
------------------------------------
Director
62
<PAGE>
FIRST AMENDMENT OF CREDIT AGREEMENT
-----------------------------------
THIS FIRST AMENDMENT OF CREDIT AGREEMENT (this "Amendment"), dated as
of March 6, 2000, is by and between PENNACO ENERGY, INC., a Nevada corporation
(herein called "Borrower"), U.S. BANK NATIONAL ASSOCIATION, a national banking
association (herein called "USB").
RECITALS
A. Borrower and USB entered into a Credit Agreement dated as of July
23, 1999 (the "Credit Agreement"), in order to set forth the terms upon which
USB would make advances to Borrower and issue letters of credit at the request
of Borrower and by which such advances and letters of credit would be governed
and repaid. Capitalized terms used herein but not defined herein shall have the
same meanings as set forth in the Credit Agreement.
B. Borrower and USB wish to enter into this Amendment in order to
amend certain terms and provisions of the Credit Agreement.
AGREEMENT
NOW, THEREFORE, in consideration of $10.00 and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereby agree as follows:
1. Credit Agreement. The Credit Agreement shall be, and hereby is,
----------------
amended as follows as of the date hereof:
(a) The following shall be substituted for the definition of
"Borrowing Base" in Section 1.1 on pages 1 and 2 of the Credit Agreement:
"Borrowing Base" means, at any time prior to the
--------------
Maturity Date, the aggregate loan value of all Borrowing Base
Properties, as determined by USB in its sole and absolute discretion,
using such assumptions as to pricing, discount factors, discount
rates, expenses and other factors as USB customarily uses as to
borrowing-base oil and gas loans at the time such determination is
made; provided that the Borrowing Base for the time period from March
6, 2000 through September 30, 2000 shall be $40,000,000, unless
Borrower and USB hereafter mutually agree upon a different amount or
unless the Borrowing Base is redetermined pursuant to Section 2.8
below prior to any such date.
<PAGE>
(b) The following shall be substituted for the definition of
"Maximum Loan Amount" in Section 1.1 on page 7 of the Credit Agreement:
"Maximum Loan Amount" means $40,000,000; provided that,
-------------------
upon the request of Borrower, USB may, in its sole discretion,
increase said amount to an amount not greater than $75,000,000 by
giving written notice of such increase to Borrower, but nothing
contained in this Agreement, the Note or any other Loan Document shall
be deemed to commit or require USB to grant any such increase.
(c) The following new Section 3.4(d) shall be inserted
immediately after Section 3.4(c) on page 16 of the Credit Agreement:
(d) If at any time the Borrowing Base is increased to an amount
in excess of $40,000,000 (or in excess of such higher amount as to which
Borrower has already paid a fee pursuant to this Section 3.4(d)), Borrower
shall pay to USB a fee in an amount equal to: (1) 0.0025, times (2) the
amount by which the Borrowing Base exceeds $40,000,000 (or by which the
Borrowing Base exceeds such higher amount as to which Borrower has already
paid a fee pursuant to this Section 3.4(d)).
2. The Note. The Promissory Note dated July 23, 1999 (the
--------
"Note"), in the face amount of $25,000,000, made by Borrower, payable to the
order of USB, shall be amended, such amendment to be effected by an Allonge (the
"Allonge"), between Borrower and USB, to be attached to the Note and to be
substantially in the form of Exhibit A attached hereto and made a part hereof.
3. Loan Documents. All references in any document to the
--------------
Credit Agreement shall be deemed to refer to the Credit Agreement, as amended
pursuant to this Amendment. All references in any document to the Note shall be
deemed to refer to the Note, as amended pursuant to the Allonge.
4. Conditions Precedent. The obligations of the parties
--------------------
under this Amendment and the Allonge are subject, at the option of USB, to the
prior satisfaction of the condition that Borrower shall have delivered to USB
the following (all documents to be satisfactory in form and substance to USB
and, if appropriate, duly executed and/or acknowledged on behalf of the parties
other than USB):
(a) This Amendment.
(b) The Allonge.
(c) Any and all other loan documents required by USB,
including without limitation such amendments to the Security Documents as
-2-
<PAGE>
may be required by USB.
(d) A fee in the amount of $50,000 in connection with the
increase in the Borrowing Base being made pursuant to the terms hereof.
5. Representations and Warranties. Borrower hereby certifies to USB
------------------------------
that as of the date of this Amendment all of Borrower's representations and
warranties contained in the Credit Agreement are true, accurate and complete in
all material respects, and no Default or Event of Default has occurred under the
Credit Agreement.
6. Continuation of the Credit Agreement. Except as specified in
------------------------------------
this Amendment and the Allonge, the provisions of the Credit Agreement and the
Note shall remain in full force and effect, and if there is a conflict between
the terms of this Amendment or the Allonge and those of the Credit Agreement or
the Note, the terms of this Amendment and the Allonge shall control.
7. Expenses. Borrower shall pay all expenses incurred in connection
--------
with the transactions contemplated by this Amendment, including without
limitation all fees and expenses of the attorney for USB and any and all
recording fees and expenses.
8. Miscellaneous. This Amendment shall be governed by and construed
-------------
under the laws of the State of Colorado and shall be binding upon and inure to
the benefit of the parties hereto and their successors and assigns. This
Amendment may be executed in any number of counterparts, each of which shall be
an original, but all of which together shall constitute one instrument.
EXECUTED as of the date first above written.
PENNACO ENERGY, INC.
By: __________________________
Glen C. Warren, Jr.,
Executive Vice President
U.S. BANK NATIONAL ASSOCIATION
By: ____________________________
Caroline McClurg,
Vice President
-3-
<PAGE>
EXHIBIT A
---------
ALLONGE
-------
Reference is made to a Promissory Note dated July 23, 1999 (the
"Note"), in the face amount of $25,000,000, made by PENNACO ENERGY, INC., a
Nevada corporation ("Borrower"), payable to the order of U.S. BANK NATIONAL
ASSOCIATION, a national banking association.
The Note is hereby modified by substituting "$75,000,000" for
"$25,000,000" in the caption of the Note and in line 4 of the first paragraph on
page 1 of the Note.
EXECUTED as of March 6, 2000.
PENNACO ENERGY, INC.
By: __________________________
Glen C. Warren, Jr.,
Executive Vice President
U.S. BANK NATIONAL ASSOCIATION
By: __________________________
Caroline McClurg,
Vice President
A-4
<PAGE>
Exhibit 23.1
------------
The Board of Directors
Pennaco Energy, Inc.
We consent to incorporation by reference in the registration statement (No. 333-
81989) on Form S-8 of Pennaco Energy, Inc. of our report dated February 25,
2000, relating to the balance sheets of Pennaco Energy, Inc. as of December 31,
1999, and 1998, and the related statements of operations, stockholders' equity,
and cash flows for the year ended December 31, 1999 and for the period from
January 26, 1998 (inception) to December 31, 1998.
KPMG LLP
Denver, Colorado
March 16, 2000
<PAGE>
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum consultants, we hereby consent to the
inclusion of our report dated February 18, 2000, on the estimates of the net
proved natural gas reserves of Pennaco Energy, Inc. and their present values, as
of January 1, 2000, in this registration statement and the prospectus
incorporated therein, and all references to our firm therein.
/s/ Ryder Scott Company, L.P.
------------------------------
RYDER SCOTT COMPANY, L.P.
Denver, Colorado
March 16, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-KSB
FOR THE YEAR ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 2,908,000
<SECURITIES> 0
<RECEIVABLES> 5,308,000
<ALLOWANCES> 0
<INVENTORY> 1,715,000
<CURRENT-ASSETS> 10,301,000
<PP&E> 50,121,000
<DEPRECIATION> 873,000
<TOTAL-ASSETS> 59,657,000
<CURRENT-LIABILITIES> 9,886,000
<BONDS> 0
0
0
<COMMON> 19,000
<OTHER-SE> 48,942,000
<TOTAL-LIABILITY-AND-EQUITY> 59,657,000
<SALES> 4,550,000
<TOTAL-REVENUES> 4,550,000
<CGS> 3,212,000
<TOTAL-COSTS> 9,978,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 62,000
<INCOME-PRETAX> 7,479,000
<INCOME-TAX> 2,605,000
<INCOME-CONTINUING> 4,874,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,874,000
<EPS-BASIC> .31
<EPS-DILUTED> .27
</TABLE>
