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Filed Pursuant to Rule 424(b)(3)
File No.: 333-86547
PROSPECTUS
3,500,000 Shares
[Logo of Pennaco Energy, Inc.}
Common Stock
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Pennaco Energy, Inc. is offering 2,250,000 shares of common stock, and one of
our stockholders named in this prospectus is offering 1,250,000 shares of our
common stock. We will not receive any of the proceeds from the sale of shares
by the selling stockholder.
Our common stock trades on the American Stock Exchange under the symbol "PN."
On October 14, 1999, the last sale price of our common stock as reported on
the American Stock Exchange was $11.125 per share.
Pennaco is an independent energy company entirely focused on the acquisition,
exploration, development and production of natural gas from coal bed methane
properties located in the Powder River Basin of northeastern Wyoming and
southeastern Montana.
See "Risk Factors" beginning on page 8 to read about some of the risks that
you should consider before buying shares of our common stock.
Neither the Securities and Exchange Commission nor any other regulatory body
has approved or disapproved these securities or passed upon the adequacy or
accuracy of this prospectus. Any representation to the contrary is a criminal
offense.
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<CAPTION>
Per
Share Total
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<S> <C> <C>
Public Offering Price...................................... $11.125 $38,937,500
Underwriting discounts and commissions..................... $ 0.668 $ 2,336,250
Proceeds, before expenses, to Pennaco...................... $10.458 $23,529,375
Proceeds, before expenses, to the selling stockholder...... $10.458 $13,071,875
</TABLE>
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The underwriters may also purchase up to an additional 525,000 shares of
common stock from Pennaco at the public offering price less the underwriting
discount.
The underwriters are severally underwriting the shares being offered. The
underwriters expect to deliver the shares to purchasers on October 20, 1999.
----------------
Bear, Stearns & Co. Inc.
A.G. Edwards & Sons, Inc.
Howard, Weil, Labouisse, Friedrichs
Incorporated
Hanifen, Imhoff Inc.
The date of this prospectus is October 14, 1999.
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[MAP APPEARS HERE]
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TABLE OF CONTENTS
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Page
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Prospectus Summary....................................................... 1
Risk Factors............................................................. 8
Forward-Looking Statements............................................... 15
Use of Proceeds.......................................................... 15
Dividend Policy.......................................................... 16
Price Range of Common Stock.............................................. 16
Capitalization........................................................... 17
Dilution................................................................. 18
Selected Historical Financial Data....................................... 19
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 20
Business and Properties.................................................. 23
Management............................................................... 36
Principal and Selling Stockholders....................................... 44
Certain Relationships and Related Transactions........................... 46
Description of Capital Stock............................................. 47
Underwriting............................................................. 53
Experts.................................................................. 55
Legal Matters............................................................ 55
Where to Find More Information........................................... 55
Index to Financial Statements............................................ F-1
Report of Independent Petroleum Engineers................................ A-1
</TABLE>
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As used in this prospectus, any reference to the "Company," "Pennaco," "we"
or "our" means Pennaco Energy, Inc.
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PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in this prospectus.
This summary is not complete and does not contain all of the information that
you should consider before investing in the common stock offered through this
prospectus. You should read the entire prospectus carefully, especially the
risks of investing in the common stock discussed under "Risk Factors."
Pennaco Energy, Inc.
We are an independent energy company entirely focused on the acquisition,
exploration, development and production of natural gas from coal bed methane
properties located in the Powder River Basin of northeastern Wyoming and
southeastern Montana. We are one of the largest holders of oil and gas leases
covering coal bed methane properties in the Powder River Basin and believe we
are 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 September 15, 1999, we owned oil and gas lease rights with
respect to approximately 725,000 gross acres and 335,000 net acres in the
Powder River Basin. Of these amounts, 624,000 gross acres and 281,000 net acres
represent our portion of the leasehold interests contained in an area of mutual
interest, or AMI, we share with CMS Oil and Gas Company, a wholly owned
subsidiary of CMS Energy Corporation, a publicly traded global energy company.
We have leasehold interests covering 101,000 gross acres and 54,000 net acres
outside the AMI, the majority of which are located in our South Gillette Area.
On October 23, 1998, we 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 our leasehold position in the Powder River
Basin for approximately $28 million. Since the announcement of our agreement
with CMS, the jointly owned leasehold contained in the AMI has increased from
492,000 net acres to approximately 562,000 net acres through additional
leasehold 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.
Business Activities
On November 15, 1998, we initiated our drilling program and had drilled 383
gross (322 net) wells by October 14, 1999. Of these wells, 97 gross (87 net)
wells were producing and 286 gross (235 net) were shut-in but capable of
producing or were in various stages of completion, testing or connection to a
pipeline. We have drilled 312 gross wells in our South Gillette Area with an
average 92% working interest and 71 gross wells in the AMI with an average 50%
working interest. We operate all of the 312 wells drilled in the South Gillette
Area and approximately 50% of the 71 wells drilled in the AMI. Based on our
current inventory of drilling locations, we expect to drill 460 net wells
during 1999 with expected drilling costs of approximately $18 million. We
drilled 294 of these wells during the year-to-date period ended October 14,
1999. We have identified in excess of 1,400 additional net drilling locations
on our acreage based on drilling results to date. The number of locations we
actually drill will depend on our future operating results, availability of
capital and our ability to obtain the requisite regulatory approvals from state
and federal agencies.
Our estimated net proved reserves as of September 1, 1999, were 56.1 billion
cubic feet, or Bcf, of natural gas, a 38.0 Bcf increase from the 18.1 Bcf of
estimated net proved reserves reported as of January 1, 1999. All of our net
proved reserves are located in the South Gillette Area. The present value of
estimated future net revenues, before income taxes, as of September 1, 1999,
totaled $50.6 million, using a 10% discount rate. Based on our proved reserves
as of September 1, 1999, and total drilling and completion costs of $9.8
million incurred from inception through that date, our drilling and completion
costs have averaged $0.17 per thousand
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cubic feet, or Mcf, making us one of the lowest cost finders and developers
among U.S. publicly traded exploration and production companies. Our drilling
and completion costs exclude the costs of well connection, gas gathering and
compression, which we currently outsource to third parties.
Business Strategy
Our objective is to build an exploration and production company focused on
creating value for our stockholders through profitable per share growth in
reserves, production and cash flow. We are implementing this strategy as
follows:
. Focus activities in the Powder River Basin coal bed methane
project. During 1999, we intend to drill a total of 460 net coal bed
methane wells, of which 294 had been drilled as of October 14, 1999. We
have identified in excess of 1,400 additional net drilling locations on
portions of our acreage based on drilling results to date, of which
approximately 31% are located outside the AMI, primarily in our South
Gillette Area, and 69% are in the AMI. We currently anticipate drilling
over 500 net wells during 2000. The actual number of wells we drill,
however, will depend on our future operating results, availability of
capital and our ability to obtain the requisite regulatory approvals
from state and federal agencies.
. Maintain low cost drilling program. Our 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 $45,000. In comparison to conventional oil and gas
wells, Powder River Basin coal bed methane wells can be characterized by
their low cost and short drilling time frame. Based on our proved
reserves as of September 1, 1999, and total drilling and completion
costs of $9.8 million incurred from inception through that date, our
drilling and completion costs have averaged $0.17 per Mcf, making us one
of the lowest cost finders and developers among U.S. publicly traded
exploration and production companies.
. Concentrate on lower risk development and exploration. We plan to
allocate at least 70% of our drilling expenditure budget over time to
development wells near existing coal bed methane production.
Approximately 380, or 83%, of the 460 net wells in our 1999 drilling
expenditure budget are development wells. We believe this allocation
reduces our risk of drilling wells that will not produce natural gas in
commercial quantities. Prior to making a significant capital investment
in development drilling outside of our proved reserves, we typically
drill a five to ten-well pilot project. We expect to complete
approximately 20 pilot or exploratory projects during 1999, of which 13
have either been completed or were in progress as of October 14, 1999.
. Acquire additional property interests that add to near term drilling
inventory. From our inception through September 15, 1999, we have
acquired leasehold interests covering approximately 596,000 net acres in
the Powder River Basin for $35.0 million, with an average acquisition
cost of $59 per acre. We have sold a total of 261,000 net acres of this
acreage to CMS. We believe that ownership of coal bed methane properties
in the Powder River Basin will continue to be consolidated by the larger
leaseholders in the basin resulting in more efficient development and
production operations. We intend to continue to be one of the leaders in
this consolidation. While the costs to acquire leasehold interests in
the Powder River Basin have increased, we believe that attractive lease
acquisition opportunities are still available.
. Lower capital costs through outsourcing. We intend to focus our 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. We believe this will be a more efficient
use of our funds and allow us to maintain a rapid rate of development of
our properties.
2
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. Maintain control of operations. We had an average 84% working interest
in our wells drilled as of October 14, 1999. Our objective is to
maintain a minimum 50% working interest in our Powder River Basin leases
and wells. We operate all of our 312 wells drilled in our South Gillette
Area and, in accordance with our agreement with CMS, approximately one-
half of the 71 wells drilled in the AMI. By operating a majority of our
producing properties, we believe we have greater control over our
expenses and the timing of our exploration and development operations.
Gas Gathering, Compression and Transportation
We plan to continue to focus our capital spending and management resources
on lease acquisition, drilling, well completion and production activities
rather than gas gathering, compression and transportation operations.
Accordingly, we will utilize third party gathering services to gather, compress
and transport our natural gas from the wellhead to the market in return for
gathering and compression fees. Pennaco and CMS have entered into a gas
gathering agreement under which an affiliate of CMS will provide gas gathering
services to Pennaco and CMS within the AMI. We have also entered into an
agreement with Bear Paw Energy, Inc., a subsidiary of Transmontaigne Inc.,
under which Bear Paw Energy constructs, owns and operates gas gathering systems
and provides gas gathering and compression services to Pennaco in our South
Gillette Area.
While coal bed methane production growth in the Powder River Basin has
historically been impeded by a shortage of pipeline capacity out of the basin,
two pipelines have recently been completed and one is under construction. The
two completed pipelines will provide an additional 900 million cubic feet, or
MMcf, of daily capacity as set forth below:
. Fort Union Gas Gathering, LLC's 106-mile, 24-inch gathering pipeline,
which commenced operations September 1, 1999, with an initial capacity
of 450 MMcf per day;
. Thunder Creek Gas Services, LLC's 126-mile, 24-inch gathering pipeline,
which commenced operations September 1, 1999, with an initial capacity
of 450 MMcf per day; and
. CMS Energy's 110-mile, Northern Header gathering pipeline, that will
connect to the northern terminus of the Fort Union pipeline, is under
construction and is expected to commence operations in November 1999
with an initial capacity of 256 MMcf per day.
Additionally, Wyoming Interstate Gas Company's 143-mile, 24-inch Medicine
Bow Lateral pipeline, which is under construction and is expected to commence
operations in November 1999 with an initial capacity of 260 MMcf per day, will
transport natural gas from the Thunder Creek and Fort Union pipelines at the
south end of the Powder River Basin to interconnect with multiple interstate
pipelines.
We are in the process of negotiating firm and interruptible transportation
for our anticipated natural gas production. We currently have long-term
transportation contracts with the following pipeline entities:
. a pipeline affiliate of CMS will take all of our natural gas produced in
the AMI through the Fort Union pipeline and the Medicine Bow Lateral on
an interruptible basis with Pennaco having the option to convert up to
50% of our average monthly production from the AMI over the trailing
calendar year to up to 30 MMcf per day of firm transportation;
. Thunder Creek Gas Services, LLC will take 4.3 MMcf per day of our gas
produced in the South Gillette Area on a firm basis beginning in
September 1999 under a five-year contract increasing to 10 MMcf per day
in November 1999; and
. Western Gas Resources is taking 11 MMcf per day of our gas produced in
the South Gillette Area, increasing to 20 MMcf per day when the Medicine
Bow Lateral commences operations, on a firm basis under a ten-year
contract.
3
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Recent Developments
Increased Production
Our working interest gas production has increased to 21 MMcf per day (14
MMcf per day net to Pennaco) from 97 producing wells located in the South
Gillette Area. The recent increase from 11 MMcf per day is due to the opening
of KN Energy's Coal Seam Booster Compressor Station in the South Gillette Area.
The Coal Seam Booster and related pipeline spur moves gas to the recently
opened Thunder Creek Gas Pipeline.
Recent Acquisitions
Since June 30, 1999, we have acquired leasehold interests covering 22,400
net acres of oil and gas properties in various transactions for $12.1 million.
These leasehold acquisitions cover properties that are either adjacent to
drilling activities or production in our South Gillette Area or near pilot
projects that we have recently drilled or plan to drill in 1999.
One of the larger acquisitions is a 1,900 net acre position in the Bonepile
area, which is located outside of the AMI approximately three miles west of our
current drilling activity in the South Gillette Area. The Bonepile acquisition
includes 15 coal bed methane wells, which are currently shut-in awaiting
pipeline connection, and 48 net drilling locations. We plan to drill most of
these locations in the fourth quarter of 1999.
We recently completed an acquisition that includes 6,400 net acres outside
of the AMI in an area called Deadhorse Creek, which is located approximately
eight miles southwest of our Felix pilot project. The Deadhorse Creek
acquisition includes seven coal bed methane wells which are currently shut-in
and awaiting pipeline connection. We have identified over 200 net drilling
locations in this area with each location targeting either the Big George or
Cook coal beds. Sixty percent of the purchase price is being held in escrow
until necessary third party consents releasing the property from a federal unit
agreement are received. Operators have recently conducted an increasing amount
of coal bed methane drilling activity in three separate pilot projects located
approximately six miles to the northeast, northwest and southwest of this area,
targeting the Big George coal bed.
Capital Spending
On June 16, 1999, we announced a revised capital budget of $26.5 million for
1999, all of which will be directed toward our Powder River Basin coal bed
methane properties. The revised budget represents an $8.1 million, or 44%,
increase over our original budget of $18.4 million. We plan to spend
approximately $18 million to drill 460 net wells in the project area during
1999. These wells will be a combination of joint Pennaco/CMS wells drilled in
the AMI and Pennaco wells drilled outside the AMI in our South Gillette Area.
Approximately $8.5 million of our revised budget is allocated to additional
leasehold acquisitions. However, due to our ability to identify attractive
acquisition opportunities, we acquired leasehold interests for $17.6 million
during the year-to-date period ended October 14, 1999, exceeding our budget for
the year by $9.1 million. We plan to continue to expand our leasehold position
in the Powder River Basin as attractive lease acquisition opportunities become
available.
Increased Borrowing Base Under Credit Facility
On July 23, 1999, we entered into a revolving line of credit with US Bank
National Association. US Bank increased Pennaco's borrowing base to $20.0
million on September 24, 1999, under the existing $25.0 million credit
facility. This reflects a $6.0 million increase from the previous $14.0 million
borrowing base and a $10.0 million increase from the initial $10.0 million
borrowing base. Our borrowing base has increased as our reserve base has
increased from 18.1 Bcf at January 1, 1999, to 56.1 Bcf at September 1, 1999.
4
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The Offering
Common Stock Offered by:
Pennaco.......................... 2,250,000 shares
The Selling Stockholder.......... 1,250,000 shares
Common Stock Outstanding............ 17,836,129 shares
Use of Proceeds..................... We intend to use the net proceeds from
this offering to repay existing
indebtedness incurred to fund lease
acquisitions and drilling operations, to
fund future lease acquisitions, for
planned exploration and development
drilling and for general corporate
purposes.
Offering Expenses................... The expenses of the offering will be
shared proportionately by Pennaco and the
selling stockholder based on the number
of shares sold by each party in this
offering.
American Stock Exchange Symbol...... PN
The number of shares of common stock outstanding after this offering is that
number of shares outstanding at June 30, 1999:
. excluding shares issuable under a 30-day option granted by Pennaco to
the underwriters to purchase up to 525,000 additional shares of common
stock to cover over-allotments, if any;
. excluding 4,142,818 shares of common stock issuable under options and
warrants outstanding at October 14, 1999, and 45,000 additional options
to be issued as a result of this offering; and
. including 416,950 shares of common stock issued under options and
warrants exercised from July 1, 1999 to October 14, 1999.
Risk Factors
For a description of some of the risks that you should consider before
buying shares of the common stock, see "Risk Factors" beginning on page 8.
5
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Summary Historical Financial and Operating Data
The following tables present summary financial and operating data for
Pennaco as of and for the periods indicated. You should read the following
summary data along with the section entitled "Management's Discussion and
Analysis of Financial Condition and Results of Operations," our financial
statements and the related notes and other information included in this
prospectus. The financial data for the period ended December 31, 1998, have
been derived from our financial statements that have been audited by KPMG LLP.
The financial data for the period ended June 30, 1998, and the six months ended
June 30, 1999, have been derived from our unaudited financial statements that,
in the opinion of management, reflect all adjustments necessary for a fair
presentation of the financial data for those periods. Both our audited and
unaudited financial statements are included in this prospectus.
<TABLE>
<CAPTION>
Period From Period From
Six Months January 26, 1998 January 26, 1998
Ended (inception) to (inception) to
June 30, 1999 June 30, 1998 December 31, 1998
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(in thousands, except per share amounts)
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Statement of Operations Data:
Revenue:
Natural gas revenue......... $ 628 $ -- $ --
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Total revenue............. 628 -- --
------- ------- -------
Operating Expenses:
Production and lease
operating expenses......... 486 -- --
Production taxes............ 52 -- --
Exploration................. 108 860 1,825
Depreciation, depletion and
amortization............... 148 8 62
General and administrative.. 2,425 401 3,978
------- ------- -------
Total expenses............ 3,219 1,269 5,865
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Loss from operations.......... (2,591) (1,269) (5,865)
Interest income............... 239 20 55
Interest expense.............. -- (475) (682)
Gain on sale of properties.... 12,431 -- 1,413
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Income (loss) before income
taxes........................ 10,079 (1,724) (5,079)
Income tax benefit (expense).. (3,612) -- 1,266
------- ------- -------
Net income (loss)............. $ 6,467 $(1,724) $(3,813)
======= ======= =======
Basic earnings (loss) per
share........................ $ .43 $ (.19) $ (.34)
======= ======= =======
Diluted earnings (loss) per
share........................ $ .37 $ (.19) $ (.34)
======= ======= =======
Cash Flow Data:
Net cash provided by (used
by):
Operating activities........ $(3,906) $(1,098) $(3,517)
Investing activities........ 7,831 (13,051) (11,313)
Financing activities........ (4,834) 14,684 20,453
Other Financial Data:
Capital expenditures.......... $11,546 $12,856 $19,198
Balance Sheet Data (end of
period):
Cash and cash equivalents..... $ 4,714 $ 5,623
Total assets.................. 24,573 22,026
Long-term debt................ -- --
Total stockholders' equity.... 20,323 13,843
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Summary Reserve and Acreage Data
The reserve estimates and present value data for our properties as shown
below were prepared by Ryder Scott Company, petroleum consultants. You should
read the following table along with the sections entitled "Risk Factors,"
"Business and Properties" and note 9 to our annual financial statements
included in this prospectus.
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As of As of As of
September 1, 1999 July 1, 1999 January 1, 1999
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Estimated Proved Reserves: (1)
Natural gas (Bcf)............. 56.1 42.7 18.1
Percent proved developed...... 76% 69% 30%
Present value of estimated
future net revenues, before
income taxes (2)(3)
(in thousands)............... $50,600 $ 28,300 $8,500
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<CAPTION>
As of As of
June 30, 1999 December 31, 1998
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Acreage:
Gross acres:
Developed............................................. 5,000 1,800
Undeveloped........................................... 698,900 669,200
Net acres:
Developed............................................. 4,700 1,600
Undeveloped........................................... 310,700 285,000
</TABLE>
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(1) The term "present value of estimated future net revenues, before income
taxes," when used with respect to natural gas reserves in this prospectus,
means the estimated future revenue to be generated from the production of
proved reserves, net of estimated future production and development costs,
using prices and costs in effect as of the date of the report or estimate,
without giving effect to non-property related expenses such as general and
administrative expenses and debt service or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
(2) Weighted average Rocky Mountain CIG natural gas price used in the
estimation of net proved reserves and the calculation of present value was
$2.49 per million British Thermal Units, or MMBtu, at August 31, 1999,
$2.00 per MMBtu at June 30, 1999, and $1.80 per MMBtu at December 31, 1998.
(3) The standardized measure of discounted future net cash flows at January 1,
1999, was $6,142,000.
7
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RISK FACTORS
An investment in Pennaco involves a significant degree of risk. You should
carefully consider the specific factors set forth below, as well as the other
information set forth in this prospectus, before you purchase the common stock
offered in this prospectus.
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 late April 1999. We are
subject to all the risks inherent in the creation of a new business. Since our
principal activities to date have been limited to organizational activities,
acquisition of leasehold interests, prospect development and commencement of a
drilling program, we have a limited record of any revenue-producing operations.
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. There is currently limited
pipeline capacity available to transport natural gas out of the Powder River
Basin. To accommodate the amount of gas expected to be produced in the area,
existing pipelines must be expanded and additional pipelines must be built. The
expansion of pipeline capacity in the basin is likely to require significant
capital outlays by the pipeline companies and the related plans and
specifications are 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 one of our transportation
contracts is interruptible 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
any additional pipeline capacity will be completed 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
prospectus.
This prospectus 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 prospectus. 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.
8
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At September 1, 1999, approximately 24% 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 prospectus 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 required by the SEC to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most accurate 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 are currently seeking changes in permit requirements
and department policy that would allow operators more flexibility to discharge
water on the surface. 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 the underground rock formations adjacent to the
coal seams or lower sandstone horizons. 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.
Our development on federal lands in the Powder River Basin has been slowed
by an ongoing environmental impact study which is scheduled for completion in
November 1999. We cannot be certain when this study will be completed. We also
cannot be sure that the study, when completed, will allow us to proceed with
our exploration and development plans. Approximately 47% of the locations we
have identified for possible drilling are located on federal properties that
could be impacted by the results of this study.
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 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.
9
<PAGE>
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 amount of our 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 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 averaged historically.
10
<PAGE>
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;
. 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
11
<PAGE>
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 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 futures contracts fail to perform the
contracts; or
. a sudden, unexpected event materially impacts natural gas prices.
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.
12
<PAGE>
Our shares that are eligible for future sale may have an adverse effect on the
price of our stock.
As of June 30, 1999, pro forma to give effect to this offering and shares
issued pursuant to options and warrants exercised since that date, 17,836,129
shares of common stock were outstanding (18,361,129 shares if the underwriters'
over-allotment option is exercised in full). In addition, options and warrants
to purchase 4,142,818 shares are outstanding and 45,000 additional options will
be issued as a result of this offering, of which 1,648,840 were exercisable at
October 14, 1999. These outstanding options and warrants are exercisable at
prices ranging from $1.25 to $12.19 per share. Of the shares to be outstanding
after this offering, approximately 15,050,000 shares (15,575,000 shares if the
underwriters' over-allotment option is exercised in full) will be freely
tradeable without substantial restriction or the requirement of future
registration under the Securities Act of 1933. Our officers, directors and
certain other stockholders will enter into lock-up agreements under which they
have agreed not to offer or sell shares of common stock or similar securities
for a period of 180 days from the date of this prospectus without the prior
written consent of Bear, Stearns & Co. Inc., on behalf of the underwriters
(except that we may issue or grant additional shares, warrants or options under
our employee benefit plans). However, one stockholder has entered into a lock-
up agreement related to 200,000 of his shares under which he has agreed not to
offer or sell these shares for a period of 120 days. Also, Bear, Stearns & Co.
Inc. may at any time waive the terms of these lock-up agreements. 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. If you anticipate the need for immediate income from your
investment, you should refrain from purchasing the securities offered by this
prospectus.
Purchasers of common stock will experience immediate and substantial dilution.
The public offering price will exceed the pro forma net tangible book value
per share. You will incur immediate and substantial dilution of your
investment. See "Dilution."
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 Corporate 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.
13
<PAGE>
We are subject to risks related to the Year 2000 that could negatively impact
our business.
We depend on information technology and other computer systems in operating
our business. We also depend indirectly on the proper functioning of the
computer systems of third parties with which we do business. If any of these
systems fail as a result of Year 2000 deficiencies, our business could be
materially adversely affected. We have conducted a review to identify and are
currently engaged in a process to rectify any potential internal or third party
Year 2000 problems. We cannot, however, guarantee that we or the third parties
with whom we transact business will be successful in eliminating all Year 2000
problems. Specific factors that might affect the success of our Year 2000
efforts and the occurrence of Year 2000 disruption or expense include:
. our failure to properly identify deficient systems;
. the failure of our selected remedial action to adequately address any
deficiencies;
. our failure to complete the remediation in a timely manner, due to
shortages of qualified labor or other factors;
. unforeseen expenses related to the remediation of existing systems or
the transition to replacement systems; and
. the failure of third parties to become compliant or to adequately notify
us of potential non-compliance.
14
<PAGE>
FORWARD-LOOKING STATEMENTS
Some of the statements contained in this prospectus under "Prospectus
Summary," "Risk Factors," "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Business and Properties" that relate
to our business and the industry we operate in, are forward-looking. Statements
or assumptions related to or underlying such forward-looking statements
include, without limitation, statements regarding:
. the quality of our properties with regard to, among other things, the
existence of reserves in economic quantities;
. our ability to increase our reserves through exploration and
development;
. the number of locations to be drilled and the time frame within which
they will be drilled;
. our ability to transport gas out of the Powder River Basin in a timely
fashion;
. anticipated domestic demand for natural gas; and
. the adequacy of our sources of capital resources and liquidity.
Actual results may differ materially from those suggested by the forward-
looking statements for various reasons, including those discussed under "Risk
Factors."
USE OF PROCEEDS
We estimate that the net proceeds to Pennaco from the sale of the 2,250,000
shares of common stock in this offering will be approximately $23.3 million
($28.8 million if the underwriters' over-allotment option is exercised in
full), after deducting underwriting discounts and commissions of $1.5 million
and estimated offering expenses of $0.2 million net to Pennaco. We will not
receive any proceeds from the sale of common stock by the selling stockholder.
Pennaco will use the net proceeds of this offering for the following
purposes:
. repay outstanding indebtedness under our credit facility that was
incurred to acquire additional leasehold interests in the Powder River
Basin since June 30, 1999 and fund drilling operations;
. fund future leasehold acquisitions;
. fund planned exploration and development activities in the Powder River
Basin; and
. general corporate purposes.
At October 14, 1999, we had $14.7 million of borrowings outstanding under
our credit facility bearing interest at an average annual rate of 8%. These
borrowings are repayable over a four-year period beginning in 2001. Following
completion of this offering and the application of a portion of the net
proceeds to repay the borrowings, the entire $20.0 million of borrowing base
under our credit facility will be available.
15
<PAGE>
DIVIDEND POLICY
We have never paid cash dividends on our capital stock and we do not
anticipate paying cash dividends in the foreseeable future. Any future
determination to pay cash dividends will be at the discretion of our board of
directors and will be dependent upon our financial condition, results of
operations, capital requirements and other factors that the board of directors
deems relevant. In addition, our credit facility restricts our ability to pay
cash dividends.
PRICE RANGE OF COMMON STOCK
Since April 19, 1999, our common stock has been traded on the American Stock
Exchange. From July 1, 1998, to April 16, 1999, our 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 for the period from
April 19, 1999, through October 14, 1999.
<TABLE>
<CAPTION>
High Low
------ ------
<S> <C> <C>
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 (through October 14, 1999)................... $12.06 $10.63
</TABLE>
As of August 31, 1999, there were approximately 160 stockholders of record
of our common stock.
16
<PAGE>
CAPITALIZATION
The following table shows as of June 30, 1999, total capitalization of
Pennaco: (1) on an actual basis, (2) pro forma to give effect to borrowings
under the credit facility and the exercise of warrants and options from July 1,
1999, to October 14, 1999, and (3) pro forma as adjusted to give effect to this
offering and the application of the net proceeds to Pennaco as described under
"Use of Proceeds," assuming no exercise of the underwriters' over-allotment
option. This table should be read together with the financial statements and
related notes in this prospectus.
<TABLE>
<CAPTION>
As of June 30, 1999
-----------------------------
Pro Forma
Actual Pro Forma As Adjusted
------- --------- -----------
(In thousands)
(unaudited)
<S> <C> <C> <C>
Credit Facility.................................. $ -- $14,700 $ --
Stockholders' Equity:
Common Stock ($.001 par value, 50,000,000 shares
authorized, 15,169,179, 15,586,129 and
17,836,129 shares issued and outstanding actual,
pro forma and pro forma as adjusted,
respectively) (1)............................... 15 15 17
Additional paid-in capital....................... 18,014 18,855 42,152
Retained earnings................................ 2,294 2,294 2,294
------- ------- -------
Total stockholders' equity..................... 20,323 21,164 44,463
------- ------- -------
Total capitalization........................... $20,323 $35,864 $44,463
======= ======= =======
</TABLE>
- --------
(1) Does not include a total of 4,142,818 shares that may be issued under stock
options and warrants outstanding as of October 14, 1999, and 45,000 shares
that may be issued under stock options to be issued as a result of this
offering.
17
<PAGE>
DILUTION
Our net tangible book value per share on June 30, 1999, was $1.34. After
giving effect to this offering, our pro forma net tangible book value at June
30, 1999, is $2.50 per share. Purchasers of common stock in this offering will
experience substantial and immediate dilution in net tangible book value per
share for financial accounting purposes, as illustrated in the following table:
<TABLE>
<S> <C>
Offering price per share........................................... $11.125
Less pro forma net tangible book value per share after the offering
(1)............................................................... 2.500
-------
Immediate dilution in net tangible book value per share to new in-
vestors........................................................... $ 8.625
=======
</TABLE>
The following table sets forth the number of shares that we will issue and
the total consideration contributed by the purchasers of the common stock we
are selling in this offering:
<TABLE>
<CAPTION>
Shares Acquired Total Consideration
------------------ ---------------------- Average Price
Number Percent Amount Percent Per Share
---------- ------- ---------- ---------- -------------
(in millions)
<S> <C> <C> <C> <C> <C>
Existing stockholders.... 15,169,179 87.1 $18.5 42.5 $ 1.220
New investors............ 2,250,000 12.9 25.0 57.5 11.125
</TABLE>
- --------
(1) Determined by dividing the total number of shares to be outstanding after
the offering into our pro forma net tangible book value, after giving
effect to the application of the net proceeds of this offering.
18
<PAGE>
SELECTED HISTORICAL FINANCIAL DATA
The following tables present selected historical financial information for
Pennaco as of and for the periods indicated. The financial data for the period
ended December 31, 1998, have been derived from our financial statements that
have been audited by KPMG LLP. The financial data for the period ended June 30,
1998, and the six months ended June 30, 1999, have been derived from our
unaudited financial statements that, in the opinion of management, reflect all
adjustments necessary for a fair presentation of the financial position for
those periods. You should read the following selected historical financial data
along with the section entitled "Management's Discussion and Analysis of
Financial Condition and Results of Operations," to our financial statements and
the related notes and other information included in this prospectus.
<TABLE>
<CAPTION>
Period From Period From
Six Months January 26, 1998 January 26, 1998
Ended (inception) to (inception) to
June 30, 1999 to June 30, 1998 December 31, 1998
------------- ---------------- -----------------
(in thousands, except per share amounts)
<S> <C> <C> <C>
Statement of Operations Data:
Revenue:
Natural gas revenue......... $ 628 $ -- $ --
------- -------- --------
Total revenue............. 628 -- --
------- -------- --------
Operating Expenses:
Production and lease
operating expenses......... 486 -- --
Production taxes............ 52 -- --
Exploration................. 108 860 1,825
Depreciation, depletion and
amortization............... 148 8 62
General and administrative.. 2,425 401 3,978
------- -------- --------
Total expenses............ 3,219 1,269 5,865
------- -------- --------
Loss from operations.......... (2,591) (1,269) (5,865)
Interest income............... 239 20 55
Interest expense.............. -- (475) (682)
Gain on sale of properties.... 12,431 -- 1,413
------- -------- --------
Income (loss) before income
taxes........................ 10,079 (1,724) (5,079)
Income tax benefit (expense).. (3,612) -- 1,266
------- -------- --------
Net income (loss)............. $ 6,467 $ (1,724) $ (3,813)
======= ======== ========
Basic earnings (loss) per
share........................ $ .43 $ (.19) $ (.34)
======= ======== ========
Diluted earnings (loss) per
share........................ $ .37 $ (.19) $ (.34)
======= ======== ========
Cash Flow Data:
Net cash provided by (used
by):
Operating activities........ $(3,906) $ (1,098) $ (3,517)
Investing activities........ 7,831 (13,051) (11,313)
Financing activities........ (4,834) 14,684 20,453
Other Financial Data:
Capital expenditures.......... $11,546 $ 12,856 $ 19,198
Balance Sheet Data (end of
period):
Cash and cash equivalents..... $ 4,714 $ 5,623
Total assets.................. 24,573 22,026
Long-term debt................ -- --
Total stockholders' equity.... 20,323 13,843
</TABLE>
19
<PAGE>
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 in this prospectus. We follow the successful
efforts method of accounting for oil and gas properties. See "Organization and
Summary of Significant Accounting Policies," included in note 1 of our annual
financial statements.
Pennaco is an independent energy company entirely focused on the
acquisition, exploration, development and production of natural gas from coal
bed methane properties located in the Powder River Basin of northeastern
Wyoming and southeastern Montana. We were a development stage company until
late April 1999, when we began producing natural gas from our coal bed methane
properties. Our gross working interest production is approximately 21 MMcf per
day (14 MMcf per day net to Pennaco) from approximately 97 gross producing
wells in our South Gillette Area as of October 14, 1999. Pipeline capacity
limitations have constrained production from these wells. As of October 14,
1999, another 215 wells in the South Gillette Area were either shut-in awaiting
pipeline connection or in various stages of completion, testing and well
connection. We anticipate connecting these wells and significantly increasing
our production now that the Fort Union and Thunder Creek gas gathering
pipelines are operational.
Results of Operations
We had no revenue from operations in 1998. During the period from our
inception on January 26, 1998, through December 31, 1998, we reported a net
loss of $3,813,000. We realized a gain on the sale of property of $1,413,000
based on the $7,600,000 of proceeds received in the first closing of the CMS
transaction, which occurred on November 20, 1998. Expenses incurred from
inception through December 31, 1998, totaled $6,547,000 including general and
administrative expenses of $3,978,000 and exploration expenses of $1,825,000.
In accordance with APB No. 25 "Accounting for Stock Issued to Employees," we
have 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 our 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. We believe 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 our 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's stock is publicly traded. While we
were not an SEC registrant until September 8, 1998, our shares were quoted on
the OTC Bulletin Board system beginning July 1, 1998.
Because our first gas sales occurred in late April 1999 and our gas sales
have been limited by pipeline capacity, we do not believe our results of
operations for the six months ended June 30, 1999, are indicative of our
expected future results.
We had net income of $6,467,000 for the six months ended June 30, 1999,
compared to a net loss of $1,724,000 for the period from inception to June 30,
1998. This amount includes a gain on the sale of properties in connection with
the CMS transaction of $12,431,000 for the six months ended June 30, 1999. The
six months ended June 30, 1999, reflects net production of 398,000 Mcf at an
average realized price of $1.58 per Mcf in accordance with fixed price gas
sales contracts which expire March 31, 2000. General and administrative
expenses for 1999 increased over 1998 due to the substantial increase in the
scope of our operations. The 1999 period also reflects a reduction of interest
expense and an increase in interest income
20
<PAGE>
compared to 1998 due to the repayment of debt and increase in short-term
investments resulting from proceeds received in the CMS transaction.
Liquidity and Capital Resources
Our capital resources are limited. Until late April 1999, we had not
produced any revenue and our main source of funds was the sale of our equity
securities and, to a greater extent, the proceeds from the CMS transaction. We
had approximately $4,714,000 in cash as of June 30, 1999. The proceeds of the
CMS transaction have allowed us to repay current liabilities and have funded
our cash used in operating activities of $3,906,000 and capital expenditures of
$11,546,000 for the six months ended June 30, 1999. During the period from
inception to June 30, 1998, we had net cash used in operating activities of
$1,098,000. This amount was less than cash used in operating activities for the
six months ended June 30, 1999, due to the start-up nature of Pennaco's
operations in 1998. We had capital expenditures from inception to June 30,
1998, of $12,856,000, which were funded by loans and proceeds from the sale of
our equity securities.
We had capital expenditures of approximately $11,546,000 in the six months
ended June 30, 1999, including approximately $5,546,000 for leasehold
acquisitions and $6,000,000 for drilling activities. On June 16, 1999, we
announced a revised capital budget of $26,500,000 for 1999 which was an
$8,100,000 increase from our original capital budget, all of which will be
directed towards our Powder River Basin coal bed methane project. We plan to
spend approximately $18,000,000 to drill approximately 460 net wells in the
Powder River Basin during 1999, 294 of which were drilled as of October 14,
1999. The wells will be a combination of joint Pennaco/CMS wells drilled in the
AMI and Pennaco wells drilled primarily on a 100% working interest basis
located in our South Gillette Area. The balance of the 1999 capital budget,
approximately $8,500,000, is allocated to leasehold acquisitions. There can be
no assurance that we will have sufficient funds to execute our capital
expenditure budget, that it will be economic to do so, that the wells drilled
will ultimately be productive, or that any additional leasehold acreage will be
acquired.
On July 23, 1999, we entered into a revolving line of credit with US Bank
National Association. The credit agreement provides for loans of up to
$25,000,000 based upon a borrowing base determined by US Bank. The borrowing
base has been determined to be $20,000,000 through March 31, 2000, with the
capacity for expansion as our reserve base increases. As of October 14, 1999,
we had $14,700,000 of borrowings outstanding under the revolving credit
facility.
Should our cash flow from operations or availability under our revolving
credit agreement be insufficient to satisfy our planned capital expenditure
requirements, there can be no assurance that additional debt or equity
financing will be available to meet these requirements.
Our future debt level could affect our future operations, including:
. a substantial portion of our cash flow could be dedicated to the payment
of interest on our indebtedness and would not be available for other
purposes; and
. our ability to obtain additional financing in the future may be
impaired.
Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risk, including the effects of adverse changes in
commodity prices and interest rates as discussed below.
Commodity Price Risk
We currently produce natural gas and outsource the marketing of our
production under a gas brokerage and administration agreement with Mercator
Energy, Inc. As a result, our financial results are affected when
21
<PAGE>
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, we enter into long-term contracts and use a hedging strategy. Under
our hedging strategy, we enter into energy swaps and use other financial
instruments. We use 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. As of August 31, 1999, all of our natural gas
production was sold through three long-term sales contracts. One agreement was
for 5,000 MMBtu per day at a fixed price of $1.55 per MMBtu and had a term
expiring March 31, 2000. Another agreement was for 5,000 MMBtu per day at an
index price less $0.38 per MMBtu with a term expiring March 31, 2000. The third
agreement was for 5,320 MMBtu per day at an index price less $0.15 per MMBtu
for the period from September 1, 1999, through March 31, 2000.
Hedging Program. In a typical swap agreement, we receive 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, we pay the difference. Swaps are generally settled on a monthly basis.
As of August 31, 1999, we 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
Our exposure to changes in interest rates results from borrowings with
floating interest rates. At the present time, we have no financial instruments
in place to manage the impact of changes in interest rates. As of October 14,
1999, we had borrowings outstanding of $14,700,000 under our credit facility at
an interest rate of 8%. Amounts drawn under the facility are repayable over a
four-year term beginning in 2001.
Year 2000
We have conducted a review of our computer systems to identify the systems
that could be affected by the "Year 2000" problem. The Year 2000 problem is the
result of computer programs being written using two digits rather than four to
define the applicable year. Any of our programs that have time-sensitive
software may recognize a date using "00' as the year 1900 rather than the year
2000. This could result in a major system failure or miscalculations.
We believe that the Year 2000 problem will not pose material operational
problems for us and that we are adequately prepared for the Year 2000. Our
computer software provider has assured us that all of our software is Year 2000
compliant and will function properly in the year 2000 and beyond. To our
knowledge after investigation, we do not have any material Year 2000 problems
presented by imbedded chips, such as microchips in an electronic control
system. Because we believe that we have no material internal Year 2000
problems, we have not and do not expect to incur material expenditures to
address Year 2000 problems. It is our policy to continue to review the Year
2000 compliance of our suppliers, natural gas purchasers and service providers;
however, this monitoring does not involve a significant cost to Pennaco.
In addition, we have contacted our major vendors and we are in the process
of obtaining either oral or written assurances that they have no material Year
2000 problems. In the event that one or more of our vendor-provided systems
were to have a material Year 2000 problem, we believe that the most reasonably
likely worst case scenario would be a temporary delay in revenue collection
caused by an interruption in computerized billing, which would have no
substantial long-term impact on our ability to conduct operations. It is
unlikely there would be an interruption in the actual flow of our natural gas
production.
22
<PAGE>
BUSINESS AND PROPERTIES
Pennaco Energy, Inc.
Pennaco Energy, Inc. is an independent energy company entirely focused on
the acquisition, exploration, development, and production of natural gas from
coal bed methane properties located in the Powder River Basin of northeastern
Wyoming and southeastern Montana. We are one of the largest holders of oil and
gas leases covering coal bed methane properties in the Powder River Basin and
we believe we are 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 September 15 , 1999, we owned oil and gas lease rights
with respect to approximately 725,000 gross acres and 335,000 net acres in the
Powder River Basin. Of these amounts, 624,000 gross acres and 281,000 net acres
represents our portion of the acreage contained in the AMI that we share with
CMS Oil and Gas Company. We have leasehold interests covering 101,000 gross
acres and 54,000 net acres outside the AMI, the majority of which are located
in the South Gillette Area.
Business Activities
On November 15, 1998, we initiated our drilling program and had drilled 383
gross (322 net) wells by October 14, 1999. Of these wells, 97 gross (87 net)
wells were producing, and 286 gross (235 net) were shut-in but capable of
producing or were in various stages of completion, testing or connection to a
pipeline. We have drilled 312 gross wells in our South Gillette Area with an
average 92% working interest and 71 gross wells in the AMI with an average 50%
working interest. We operate all of the 312 wells drilled in our South Gillette
Area and approximately 50% of the 71 wells drilled in the AMI. Based on our
current inventory of drilling locations, we expect to drill approximately 460
net wells during 1999, with expected drilling costs of approximately $18
million. We drilled 294 of these wells during the year-to-date period ended
October 14, 1999. We have identified in excess of 1,400 additional net drilling
well locations on our acreage based on drilling results to date. The number of
locations we actually drill will be dependent on our future operating results,
availability of capital and our ability to obtain the requisite regulatory
approvals from state and federal agencies.
Our estimated net proved reserves as of September 1, 1999, were 56.1 Bcf of
natural gas, a 38.0 Bcf increase from the 18.1 Bcf of estimated net proved
reserves reported as of December 31, 1998. All of our net proved reserves are
located in the South Gillette area. The present value of estimated future net
revenues, before income taxes, as of September 1, 1999, totaled $50.6 million,
using a 10% discount rate. Based on our proved reserves as of September 1,
1999, and the total costs of $9.8 million incurred from inception through that
date, our drilling and completion costs have averaged $0.17 per Mcf, making us
one of the lowest cost finders and developers among U.S. publicly traded
exploration and production companies. These costs exclude the costs of well
connection, gas gathering and compression, which we currently outsource to
third parties.
Business Strategy
Our objective is to build an exploration and production company focused on
creating value for our stockholders through profitable per share growth in
reserves, production and cash flow. We are implementing this strategy as
follows:
. Focus activities in the Powder River Basin coal bed methane
project. During 1999, we intend to drill a total of 460 net coal bed
methane wells, of which 294 had been drilled as of October 14, 1999. We
have identified in excess of 1,400 additional net drilling locations on
portions of our acreage based on drilling results to date, of which
approximately 31% are located outside the AMI, primarily in our South
Gillette Area, and 69% are in the AMI. Approximately 70% of these
drilling locations are on fee or state leases and 30% are located on
federal leases. We currently anticipate drilling over 500 net wells
during 2000. The actual number of wells we drill will depend on our
future operating results, availability of capital and our ability to
obtain the requisite regulatory approvals from state and federal
agencies.
23
<PAGE>
. Maintain low cost drilling program. Our 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 $45,000. In comparison to conventional oil and gas
wells, Powder River Basin coal bed methane wells can be characterized by
their low cost and short drilling time frame. Based on our proved
reserves as of September 1, 1999, and total drilling and completion
costs of $9.8 million incurred from inception through that date, our
drilling and completion costs have averaged $0.17 per Mcf making us one
of the lowest cost finders and developers among U.S. publicly traded
exploration and production companies.
. Concentrate on lower risk development and exploration. We plan to
allocate at least 70% of our drilling expenditure budget over time to
development wells near existing coal bed methane reserves. Approximately
380, or 83%, of the 460 net wells in our 1999 drilling expenditure
budget are development wells. We believe this allocation reduces our
risk of drilling wells that will not produce natural gas in commercial
quantities. Prior to making a significant capital investment in
development drilling outside of our proved reserves, we typically drill
a five to ten-well pilot project. We expect to complete approximately 20
pilot projects or exploratory projects during 1999, of which 13 have
been either completed or were in progress as of October 14, 1999.
. Acquire additional property interests that add to near term drilling
inventory. From our inception through September 15, 1999, we acquired
leasehold interests covering approximately 596,000 net acres in the
Powder River Basin for $35.0 million, with an average acquisition cost
of $59 per acre. We have sold a total of 261,000 net acres of this
acreage to CMS. We believe that ownership of coal bed methane properties
in the Powder River Basin will continue to be consolidated by the larger
leaseholders in the basin resulting in more efficient development and
production operations. We intend to continue to be one of the leaders in
this consolidation. While the costs to acquire leasehold interests in
the Powder River Basin have increased, we believe that attractive lease
acquisition opportunities are still available.
. Lower capital costs through outsourcing. We intend to focus our 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. We believe this will be a more efficient
use of our funds and allow us to maintain a rapid rate of development of
our properties.
. Maintain control of operations. We had an average 84% working interest
in our wells drilled as of October 14, 1999. Our objective is to
maintain a minimum 50% working interest in our Powder River Basin leases
and wells. We operate all of our 312 wells drilled in our South Gillette
Area and, in accordance with our agreement with CMS, approximately one-
half of the 71 wells drilled in the AMI. By operating a majority of our
producing properties, we believe we have greater control over our
expenses and the timing of our exploration and development operations.
CMS Transaction
On October 23, 1998, we 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 our leasehold position in the Powder River
Basin for approximately $28 million. We acquired that portion of the leasehold
position for approximately $7 million in 1998. Since the announcement of our
agreement with CMS, the jointly owned leasehold contained in the AMI has
increased from 492,000 net acres to approximately 562,000 net acres through
additional leasehold 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.
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
24
<PAGE>
acquisitions made by the other party in the area of mutual interest defined in
the agreement. As of October 14, 1999, approximately $0.3 million of the
proceeds of the CMS transaction remained in escrow pending resolution of
possible title defects. Under the terms of the agreement, we will also receive
approximately $0.5 million from CMS in exchange for the transfer of 15,500 net
acres in the AMI since the announcement of the transaction. The acreage data
used throughout the prospectus 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.
Drilling Activities
The following table summarizes our drilling activities, all of which were
natural gas wells located in the Powder River Basin, during the six months
ended June 30, 1999, and during 1998:
<TABLE>
<CAPTION>
Wells Drilled in Period
-----------------------------
Period From
Inception
(January 26,
Six Months 1998) to
Ended December 31,
June 30, 1999 1998
-------------- --------------
Gross Net Gross Net
------- ------ ------- ------
<S> <C> <C> <C> <C>
Development Natural Gas Wells: (1)
Productive (2).............................. 93 84 30 26
Non-productive.............................. -- -- -- --
------ ------ ------ ------
Total..................................... 93 84 30 26
====== ====== ====== ======
Exploratory Natural Gas Wells: (1)(3)
Productive (2).............................. 1 1 2 2
Non-productive.............................. -- -- -- --
------ ------ ------ ------
Total..................................... 1 1 2 2
====== ====== ====== ======
</TABLE>
- --------
(1) At June 30, 1999, we were drilling, completing or testing 101 gross (87
net) development natural gas wells and 5 gross (3 net) exploratory natural
gas wells.
(2) Productive wells are producing wells and wells capable of production,
including shut-in wells.
(3) Exploratory wells are generally wells drilled in our pilot projects before
confirmation of commercial production.
We plan to spend $18 million in 1999 to drill 460 net wells of which 294 had
been drilled as of October 14, 1999. The wells we have drilled to date have
each taken an average of two to three days to drill. The estimated total cost
per well is approximately $30,000 to $45,000 to drill and complete. The
estimated drilling portion of the total per well cost is approximately $10,000
per well. We have contracted with Bear Paw Energy in our South Gillette Area
for well connection and construction in return for a per Mcf fee to be paid to
Bear Paw Energy.
We contract with various parties for the provision of drilling services and
are therefore not dependent on any one party for drilling services.
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
25
<PAGE>
to be processed. However, the natural gas produced from coal 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 absorbed
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 September 15, 1999, we owned oil and gas leases covering approximately
335,000 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 private or fee land. Our 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.
Our Powder River Basin leasehold can generally be divided into four separate
project areas as follows:
South Gillette Area--We hold approximately 42,000 net acres of leases in
this project area located near the town of Gillette, Wyoming and outside the
AMI. We began our initial drilling program in this area and 312 of our 383
gross wells drilled as of October 14, 1999, are located here. We operate 100%
of our South Gillette Area wells where we have an average working interest of
92%. Approximately 97 gross wells in our South Gillette Area are producing,
while 215 wells were either shut-in awaiting pipeline connection or were in
various stages of being tested, dewatered and connected to gas gathering and
compression systems.
26
<PAGE>
Additionally, we recently acquired 22 shut-in wells as part of several
leasehold acquisitions. Most of our 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. Our gross working interest production was approximately 21 MMcf per
day (14 MMcf per day net to Pennaco) from approximately 97 gross producing
wells as of October 14, 1999. All of our proved developed reserves as of
September 1, 1999, are included in 191 of the 312 wells which we have drilled
since we began our drilling program in November 1998. We have identified an
additional 440 net drilling locations of which 57 net locations are included in
our proved reserve base as of September 1, 1999. All of our development
drilling to date has targeted a coal bed known as the Wyodak Anderson, which is
generally 60 to 75 feet thick and is approximately 350 to 700 feet deep.
Further, we are currently drilling and testing a five-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 is below the
Wyodak Anderson coal and approximately 20 to 35 feet thick. If the pilot
project is successful, we will have approximately 400 drilling locations for
the Wildcat-Moyer coal bed which would adjoin our Wyodak Anderson wells. These
prospective drilling locations are not included in our 440 net drilling
locations identified in the South Gillette Area.
Northern Fairway Area--We hold approximately 147,000 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 135,000 net acres are
included in the AMI and approximately 12,000 net acres are excluded from the
AMI. We have drilled 67 wells comprised of five to ten-well pilot projects in
eight different pilot areas. Four of the pilot projects are operated by Pennaco
and four are operated by CMS. The eight pilot projects are currently in the
process of being drilled, completed and tested. Many of the pilot 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, we believe that we have identified an additional 970 net drilling
locations in the Northern Fairway Area.
We are planning to drill four additional five to ten-well pilot projects in
the Northern Fairway in the remainder of 1999. Pennaco will operate one of
these pilot projects and CMS will operate the other three projects.
Most of the pilot projects are drilled adjacent to the CMS Northern Header
gathering pipeline which is under construction and scheduled for completion in
November 1999. Development of areas adjacent to the Northern Header gathering
pipeline will allow us to connect producing wells to the pipeline quickly and
move the natural gas production to market.
Border Area--We hold approximately 93,000 net acres in this project area
located in Montana adjoining the Wyoming border north of the Northern Fairway
Area and the Sheridan Area. Virtually all of our leasehold in this area is
included in the AMI. We recently drilled one exploratory well in this area and
we plan to drill two five-well pilot projects in this area in late 1999, both
of which will be operated by Pennaco. 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 Northern Header gathering
pipeline into this area contingent on successful drilling results.
Sheridan Area--We hold approximately 53,000 net acres in this project area
located primarily east of the town of Sheridan, Wyoming on the west side of the
basin. Virtually all of our leasehold in this area is included in the AMI. We
have drilled three exploratory wells in this area and we plan to drill four
additional wells adjoining each of these exploratory wells as well as two
additional five-well pilot projects in this area before year-end 1999. Pennaco
will operate one of the pilot projects and CMS will operate the remaining three
projects. CMS plans to eventually extend the Northern Header gathering pipeline
into this area contingent on successful drilling results.
27
<PAGE>
Natural Gas Reserves
The table below sets forth our quantities of proved reserves as of September
1, 1999, July 1, 1999 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 estimates were prepared for Pennaco by the
independent petroleum consulting firm of Ryder Scott Company.
<TABLE>
<CAPTION>
As of As of As of
September 1, 1999 July 1, 1999 January 1, 1999
----------------- ------------ ----------------
<S> <C> <C> <C>
Proved Reserves:
Natural gas (Bcf)......... 56.1 42.7 18.1
Oil and condensate
(MMbls).................. -- -- --
------- ------- ------
Total (Bcfe)............ 56.1 42.7 18.1
======= ======= ======
Proved developed reserves
(Bcfe)..................... 42.9 29.5 5.5
======= ======= ======
Present value of estimated
future net revenues, before
income taxes (1)(2) (in
thousands)................. $50,600 $28,300 $8,500
======= ======= ======
</TABLE>
- --------
(1) Weighted average Rocky Mountain CIG natural gas price used in the
estimation of net proved reserves and the calculation of present value was
$2.49 per MMBtu at August 31, 1999, $2.00 per MMBtu at June 30, 1999, and
$1.80 per MMBtu at December 31, 1998.
(2) Standardized measure of discounted future net cash flows at January 1,
1999, was $6,142,000.
In accordance with SEC requirements, estimates of our 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, estimates of different engineers,
including those used by Pennaco, 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 we own
declines as reserves are depleted. Except to the extent we acquire additional
leasehold interests containing proved reserves or conduct successful
exploration and development activities, or both, our proved reserves will
decline as reserves are produced. Volumes generated from our future activities
are therefore highly dependent upon our level of success in acquiring or
finding additional reserves and the costs incurred in doing so.
Production
We had no natural gas production in 1998. We commenced natural gas
production in late April 1999. Our gross working interest production was
approximately 21 MMcf per day (14 MMcf per day net to Pennaco) from 97 gross
producing wells as of October 14, 1999.
28
<PAGE>
Productive Wells
As of June 30, 1999, we owned an interest in 126 gross and 113 net
productive natural gas wells. Productive wells are producing wells and wells
capable of production, including shut-in wells.
Developed and Undeveloped Acreage
The gross and net acres of developed and undeveloped oil and gas leases we
held as of June 30, 1999, are summarized in the following table:
<TABLE>
<CAPTION>
Actual Pro Forma (1)
--------------------------- ---------------------------
Developed Undeveloped Developed Undeveloped
Acreage Acreage (2) Acreage Acreage (2)
----------- --------------- ----------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- ----- ------- ------- ----- ----- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Wyoming................. 5,000 4,700 492,100 217,200 7,600 6,900 510,300 234,300
Montana................. -- -- 206,800 93,500 -- -- 206,800 93,500
----- ----- ------- ------- ----- ----- ------- -------
Total................... 5,000 4,700 698,900 310,700 7,600 6,900 717,100 327,800
===== ===== ======= ======= ===== ===== ======= =======
</TABLE>
- --------
(1) Pro forma to give effect to the closing of various lease acquisitions and
drilling activity that occurred since June 30, 1999.
(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.
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>
Actual Pro Forma (1)
------------------- -------------------
Undeveloped Acreage Undeveloped Acreage
Acres Expiring ------------------- -------------------
Twelve Months Ending Gross Net Gross Net
-------------------- ------------------- -------------------
<S> <C> <C> <C> <C>
December 31, 1999...................... 4,400 3,200 4,400 3,300
December 31, 2000...................... 8,000 5,100 8,300 5,400
December 31, 2001...................... 9,100 7,500 9,100 7,400
December 31, 2002...................... 56,000 19,400 59,800 22,300
December 31, 2003 and thereafter....... 587,400 260,000 593,200 266,200
--------- --------- --------- ---------
Primary Term Acreage................... 664,900 295,200 674,800 304,600
Held by Production Acreage (2)......... 34,000 15,500 42,300 23,200
--------- --------- --------- ---------
Total Undeveloped Acreage.............. 698,900 310,700 717,100 327,800
========= ========= ========= =========
</TABLE>
- --------
(1) Pro forma to give effect to the closing of various lease acquisitions and
drilling activity that occurred since June 30, 1999.
(2) Held by production acreage is leasehold interest in oil and gas properties,
which is beyond its primary term and is being kept in force by virtue of
production of oil and gas in commercial quantities.
Gas Gathering, Compression and Transportation
We plan to continue to focus our capital spending and management resources
on leasehold acquisitions, drilling, well completion and production activities
rather than gas gathering and compression operations. Accordingly, we are
utilizing third party gathering services to gather, compress and transport our
natural gas from the wellhead to market in return for gathering and compression
fees.
29
<PAGE>
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 our South Gillette Area. Under the terms of a 20-year
contract, we will be charged a fixed fee per Mcf for the gathering, compression
and transportation of our natural gas production from each central metering
facility located adjacent to each pod, typically 15 to 20 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, we have the right to connect the
well or wells at our own cost and adjust the fixed fee accordingly or allow a
third party to do so.
We have 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 our South Gillette Area.
Under the terms of the agreement, Bear Paw Energy will charge Pennaco a fixed
per Mcf fee to gather, compress and transport our 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 measures subject to penalty for underperformance. If Bear
Paw Energy elects not to connect a particular well or group of wells, we have
the right to construct the gathering system ourselves or allow a third party to
do so.
Production growth in the Powder River Basin is currently impeded by a
natural gas pipeline bottleneck which restricts the movement of natural gas out
of the basin. Until recently, 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, but has no available capacity due to increasing coal
bed methane gas production from the Powder River Basin. 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. The
Williston Basin Interstate pipeline has limited additional capacity.
Two pipelines have recently been completed and two others are under
construction. 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 pipeline is a 106-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
Fort Union line will deliver coal bed methane gas to a carbon dioxide treating
facility to be constructed near Glenrock, Wyoming and to interstate pipeline
interconnects near Glenrock.
In September 1998, KN Energy, Inc. and Devon Energy Corporation announced
the formation of Thunder Creek Gas Services LLC. The Thunder Creek pipeline is
a 126-mile, 24-inch gathering pipeline which commenced operation 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 will deliver coal bed methane to multiple
interstate pipelines near Douglas, Wyoming.
Wyoming Interstate Gas Company, a subsidiary of the Coastal Corporation, has
approval from the Federal Energy Regulatory Commission to construct a new 143-
mile, 24-inch natural gas pipeline known as the Medicine Bow Lateral from
Glenrock to Cheyenne, Wyoming where the line will interconnect 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 is
under construction and scheduled to commence operations in November 1999. The
pipeline will have initial capacity of 260 MMcf per day of natural gas and can
be
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expanded with additional compression to 440 MMcf per day. We cannot guarantee
that the system will ultimately be constructed or that it will be completed in
the time-frame currently anticipated.
CMS has begun construction on a $190 million, 110-mile high-pressure
gathering pipeline through the Pennaco/CMS jointly owned acreage in the
northern Powder River Basin coal bed methane play, connecting at its southern
terminus with the Fort Union pipeline project. The Northern Header Gathering
System is designed to gather 256 MMcf of natural gas per day and can be
expanded to 500 MMcf per day with additional compression. Operations are
scheduled to commence in November 1999.
We have entered into a ten-year firm transportation agreement with Western
Gas Resources. Under the terms of the agreement, Western Gas will compress and
transport 11 MMcf per day of our natural gas delivered by Bear Paw Energy to
the Doppelbock compressor station located southwest of our South Gillette Area
through the MIGC Pipeline to the interconnect with the Williston Basin
Interstate pipeline at Recluse, Wyoming for a fixed fee per Mcf. This firm
transportation agreement increases to 20 MMcf per day once the Medicine Bow
Lateral commences operations, which is currently scheduled for November 1999.
We have dedicated acreage in our South Gillette Area to Western Gas Resources'
transportation system as consideration for the agreement.
We have entered into a firm transportation agreement with Thunder Creek
whereby Thunder Creek will commit 10 MMcf per day of firm transportation to
Pennaco in return for an acreage dedication in our South Gillette Area. Thunder
Creek began transporting our natural gas, for a fixed fee per Mcf, on September
4, 1999, at 4.3 MMcf per day which will increase to 10 MMcf per day firm
commitment beginning November 1, 1999, and extending for five years. Thunder
Creek will take our natural gas at the Coal Seam Booster located in our South
Gillette Area and transport the natural gas down the Thunder Creek gathering
pipeline to multiple pipeline interconnects located near Glenrock, Wyoming.
We have entered into a ten-year transportation agreement with a pipeline
affiliate of CMS to transport all of our natural gas produced in the AMI on an
interruptible basis through the Fort Union Pipeline to the Medicine Bow Lateral
but we have the option to convert up to 50% of our average monthly production
from the AMI over the trailing calendar year, to up to 30 MMcf per day, to of
firm transportation.
Gas Marketing and Customers
We currently outsource the marketing of our production under a gas brokerage
and administration agreement with Mercator Energy, Inc. that will convert to a
month-to-month basis on February 29, 2000. Mercator has extensive experience in
gas marketing services in the Rocky Mountain region and specifically in the
Powder River and surrounding gas producing basins.
We are currently a party to three natural gas sales contracts. The
agreements with Interenergy Resources Corporation and Montana-Dakota Utilities
Co. are each for 5,000 MMBtu per day. Each of these contracts has a one-year
term beginning April 1, 1999. 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. These three customers purchase all
of our current production.
Competition
We compete with a number of other potential purchasers of oil and gas leases
and producing properties, many of which have greater financial resources than
we do. 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 our evaluation criteria could further limit our ability to
acquire oil and gas leases. In addition, low or uncertain prices for properties
can cause potential sellers to withhold or withdraw properties from the market.
In this environment, we cannot guarantee that there will be a sufficient number
of suitable oil and gas leases available for acquisition or that we can sell
oil and gas leases or obtain financing for or participants to join in the
development of prospects.
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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. We compete against well-established companies that have significantly
greater financial, marketing, personnel and other resources than us. This
competition could have a material adverse effect on our ability to execute our
business plan and our profitability.
Regulation
General
Our 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 our business. In view of the many
uncertainties with respect to current and future laws and regulations,
including their applicability to Pennaco, we cannot predict the overall effect
of such laws and regulations on our future operations.
We believe that our 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 our method of
operations than on other similar companies in the energy industry.
Operations Under Federal or State Leases
Our 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, we are 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 we have been able to obtain required
drilling permits to date, we cannot guarantee that permitting requirements will
not adversely effect our ability to complete our 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 our ability to drill on federal lands. Approximately 50% of
our leasehold is comprised of federal acreage. Operators are currently drilling
wells on an interim basis on federal lands with the limited number of drilling
permits allowed by the BLM until the EIS is complete. We have approximately 38
interim drilling permits on federal lands within the EIS. The EIS was
originally scheduled for completion in May 1999, but has been delayed until
November 1999. We cannot guarantee the ultimate completion date of the EIS or
that, when completed, the EIS will permit us to develop wells according to our
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 will affect the
marketing of any natural gas produced by us, as well as any revenues we receive
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
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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. We cannot predict when or if any such
proposals might become effective or their effect, if any, on our operations.
The natural gas industry historically has been closely regulated. Accordingly,
we 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 effect of these
regulations is to limit the amount of oil and natural gas that we can produce
from our wells and to limit the number of wells or the locations at which we
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 our operations and costs. In
particular, our exploration, development and production operations, our
activities in connection with storage and transportation of liquid hydrocarbons
and our use of facilities for treating, processing or otherwise handling
hydrocarbons and wastes therefrom will be subject to stringent environmental
regulation. Because coal bed methane wells typically produce significant
amounts of water, we are required to file applications with state and federal
authorities, as applicable, to enable us to dispose of water produced from our
wells. While we have been able to obtain required water disposal permits for
wells drilled to date, we cannot guarantee that permitting requirements will
not negatively affect our ability to complete our 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. We are currently seeking changes in permit requirements
that would allow us to discharge water on the surface. 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 the underground rock formations
adjacent to the coal seams or lower sandstone horizons.
As with the energy industry generally, compliance with existing regulations
will increase our 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
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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 our ordinary operations, we may generate waste that may fall within
CERCLA's definition of a "hazardous substance." We 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.
We 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 wastes were not under our control. These
properties and wastes disposed thereon may be subject to CERCLA and analogous
state laws. Under these laws, we 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.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time we acquire 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, we prepare a division order title report indicating the proper
parties and percentages for payment of production proceeds, including
royalties. Based on our preliminary title examination, we have no reason to
believe that title to our leasehold properties as a whole is not good and
defensible in accordance with standards generally acceptable in the oil and gas
industry. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which we believe do not materially interfere with the use of or affect the
value of such properties.
Office Facilities
We currently sublease office space under an agreement with Evansgroup, Inc.,
which expires on September 30, 2000. The sublease covers approximately 11,524
square feet at a yearly rent of approximately $173,000.
We also lease office and lodging space in Gillette, Wyoming. The lease
covers approximately 9,000 square feet at a yearly rent of approximately
$17,400 through December 31, 2000. Under terms of the purchase option, $1,000
per month of the rent is deemed to apply to a purchase option on the property.
The purchase option expires January 7, 2001.
Employees
As of August 31, 1999, we had 20 full-time employees and utilized the
services of approximately ten consulting geologists, engineers, and lease
acquisition professionals. We plan to hire additional employees as needed. We
have an outsourcing arrangement with Trinity Petroleum Management, LLC which
provides for a number of our administration and accounting services. The
Trinity agreement was effective until August 31, 1999, when it converted to a
month-to-month arrangement. We believe that by outsourcing some of our
administrative functions to Trinity we are able to hire fewer full-time
employees and more efficiently control our administrative expenses.
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Predecessor Entities
We were 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.
Our original predecessor 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. On March 25, 1996, the
stockholders of AKA Video agreed to exchange all AKA Video shares for shares of
International Metal Protection, Inc., our immediate predecessor. After this
exchange AKA Video became inactive and the directors and stockholders approved
the windup of AKA Video. International Metal was incorporated on March 5, 1996,
in the State of Wyoming. Following an exchange of all the International Metal
outstanding shares in a share for share exchange with Pennaco, International
Metal was dissolved in February of 1998. We are the sole surviving entity of
the reorganization.
Legal Proceedings
We may be subject from time to time to routine litigation in connection with
our oil and gas operations. We are not currently involved in litigation which
could have a material impact on us.
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MANAGEMENT
The following tables show our officers, directors, key employees and
consultants:
<TABLE>
<CAPTION>
Executive Officers and Directors 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
<CAPTION>
Other Key Employees and Consultants Age Position
- ----------------------------------- --- --------
<S> <C> <C>
William Travis Brown,
Jr..................... 53 Co-Manager, Geology
Gregory S. Hinds........ 35 Co-Manager, Geology
Dirck Tromp............. 32 Staff Geologist
John Dolloff............ 69 Senior Geological Consultant
Charles E. Brammeier.... 43 Controller
Kevin J. Kilstrom....... 44 Senior Petroleum Engineer
</TABLE>
The board of directors is divided into three separate classes. Currently
there are no Class I directors, however the board is in the process of
selecting a Class I director. 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-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.
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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.
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.
William Travis Brown, Jr., Co-Manager, Geology
Mr. Brown is a senior geologist for Pennaco with 32 years of experience in
the oil and gas industry. He began his career with Amoco in 1969 as an
operations and production geologist in the Rocky Mountain Region. He has
extensive experience in the Green River and Powder River Basins. From 1969 to
1998, Mr. Brown conducted extensive work in 3-D seismic and stratigraphic
analysis, geological mapping, well site analysis, and strategic lease
acquisition for several companies including Amoco Production, Lear Petroleum,
Davis Oil, and Coastal Oil and Gas where he initiated the coal degassification
coal bed methane project in the Powder River Basin. Mr. Brown received his
Bachelor of Science degree in Geology at Columbia University and his Master of
Science and Ph.D. in Geology at the University of New Mexico.
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Gregory S. Hinds, Co-Manager, Geology
Mr. Hinds is a senior geologist for Pennaco with nine years of experience in
the oil and gas industry. He began his career with Enserch Exploration as an
exploration geologist, primarily working the Permian Basin of West Texas and
the Austin Chalk trend of the Texas coastal plain. He then joined Barrett
Resources as an operations geologist, ultimately advancing to the position of
senior exploration geologist. Mr. Hinds has had exposure to virtually all Rocky
Mountain Basins as well as every producing region in Texas and the Mid-
continent. Throughout his career, he has utilized 3-D seismic, horizontal
drilling and numerous computer applications in the search for oil and gas. Mr.
Hinds received his Bachelor of Science degree in Geology from Louisiana State
University and his Master of Science in Geology from Texas A&M University.
Dirck Tromp, Staff Geologist
Mr. Tromp is a certified professional geologist with nine years of varied
geologic and hydrogeologic experience in the petroleum, mining, and
environmental fields. He began his career as a research geologist with the U.S.
Geological Survey. The majority of his experience has been as a hydrogeologist
and geochemist with Roy F. Weston, Inc., an international environmental
consulting firm. Mr. Tromp has extensive experience with digital mapping, 3-D
computer hydrologic conceptual modeling and groundwater flow modeling. He has
designed and installed groundwater systems and hydrocarbon recovery wells. He
has a strong working knowledge of environmental compliance requirements. Mr.
Tromp holds a Bachelor of Science degree in Geological Engineering and Master
of Science degree in Geology/Geochemistry both from the Colorado School of
Mines.
John Dolloff, Senior Geological Consultant
Mr. Dollof is a consulting senior geologist to Pennaco. Mr. Dolloff has over
40 years of exploration and production geology and management experience in the
Rocky Mountain, Mid-Continent and West Texas areas. Beginning his career with
Standard Oil of Texas, he was staff geologist with the predecessor of Champlin
Petroleum (Union Pacific Resources) where he advanced to become District
Manager. He became Regional Manager for Helmerich & Payne and for nine years he
managed an 11-state oil and gas exploration program. He has also served as
exploration manager and Senior Vice-President for several petroleum companies
in the Rocky Mountain Region. Mr. Dolloff earned his Bachelor of Science degree
in Geology from Yale University and Master of Science degree in Geology from
University of Minnesota.
Charles E. Brammeier, Controller
Mr. Brammeier has 19 years of accounting experience in the oil and gas
industry where he has been extensively involved in filings with the Securities
and Exchange Commission as well as property acquisitions. Prior to his joining
Pennaco, Mr. Brammeier worked for ten years at Presidio Oil Company where he
became Vice President of Accounting-Controller. Prior to Presidio Oil Company,
Mr. Brammeier worked for nine years in various capacities at Petro-Lewis
Corporation. Mr. Brammeier earned a Bachelor of Science degree in Accounting
from Colorado State University and is a Certified Public Accountant.
Kevin J. Kilstrom, Senior Petroleum Engineer
Mr. Kilstrom is a certified petroleum engineer with over 23 years experience
in the oil and gas industry. Mr. Kilstrom spent his entire career prior to
Pennaco with Amoco Production Company and BP Amoco. Mr. Kilstrom has a broad
background in oil and gas exploration and production with significant coal bed
methane experience including reservoir engineering, reserve analysis and
acquisition evaluation. Mr. Kilstrom received a Bachelor of Science degree in
Civil Engineering from Iowa State University and a Master of Business
Administration degree from DePaul University.
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<PAGE>
Executive Compensation
We have entered into four-year employment agreements with Paul M. Rady, who
was hired in June 1998, and Glen C. Warren, Jr., who was hired in July 1998.
The employment agreement with Mr. Rady provides for a salary of $180,000 per
year, bonus compensation equal to 2% of Pennaco's net cash flow, participation
in our standard insurance plans for our executives, and participation in our
other incentive compensation programs at the discretion of the Board of
Directors. The employment agreement also provides that all stock options held
by Mr. Rady are subject to accelerated vesting in the event of his termination
without cause or in the event of a change of control. Under his employment
agreement, Mr. Rady is entitled to receive stock options to purchase that
number of shares of common stock equal to 1% of the number of shares of common
stock issued by Pennaco during the term of the employment agreement in any
capital-raising, merger or acquisition activities of Pennaco involving the
issuance of equity securities. These options will be granted as of the closing
of the transaction, vest 18 months from the date of grant and expire 48 months
from the date of grant. If Mr. Rady's employment is terminated without cause
after June 1, 1999, Mr. Rady is entitled to termination compensation of
$3,000,000. Mr. Rady's employment agreement automatically renews on each
anniversary of the effective date after June 1, 2001, for an additional two
years unless we notify Mr. Rady in writing 90 days prior to such anniversary
that we will not be renewing his employment agreement.
The employment agreement with Mr. Warren provides for a salary of $150,000
per year, bonus compensation of $150,000 for 1999 and equal to 1% of Pennaco's
net cash flow thereafter, participation in our standard insurance plans for our
executives, and participation in our other incentive compensation programs at
the discretion of the Board of Directors. The employment agreement also
provides that all stock options held by Mr. Warren are subject to accelerated
vesting in the event of his termination without cause or in the event of a
change of control. Under his employment agreement, Mr. Warren is entitled to
receive stock options to purchase that number of shares of common stock equal
to 1% of the number of shares of common stock issued by Pennaco during the term
of the employment agreement in any capital-raising, merger or acquisition
activities of Pennaco involving the issuance of equity securities. These
options will be granted as of the closing of the transaction, vest 18 months
from the date of grant and expire 48 months from the date of grant. If
Mr. Warren's employment is terminated without cause after July 1, 1999, but
before July 1, 2000, Mr. Warren is entitled to termination compensation of
$750,000. If Mr. Warren's employment is terminated without cause after July 1,
2000, Mr. Warren is entitled to termination compensation of $1,250,000. Mr.
Warren's employment agreement automatically renews on each anniversary of the
effective date after June 1, 2002, for an additional year, unless we notify Mr.
Warren in writing 90 days prior to such anniversary that we will not be
renewing his employment agreement.
39
<PAGE>
The following table provides summary information concerning compensation
earned by our Chief Executive Officer and our three most highly compensated
officers for the year ended December 31, 1998:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Long-Term
Annual Compensation Compensation Awards
------------------------- Other Annual Securities Underlying All Other
Name and Principal Position Year Salary Bonus Compensation (1) Options Compensation
- --------------------------- ----- -------- ------ ---------------- --------------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Paul M. Rady............... 1998 $ 65,077 (2) -- -- 800,000 --
President and Chief
Executive Officer
Glen C. Warren, Jr......... 1998 49,680 (3) -- -- 513,228 --
Chief Financial Officer
and Executive
Vice President
Terrell A. Dobkins......... 1998 46,465 (4) -- -- 250,000 --
Vice President--
Production
Brian A. Kuhn.............. 1998 41,548 (5) -- -- 150,000 --
Vice President--Land
</TABLE>
- --------
(1) We recognized non-cash compensation expense relating to restricted common
stock and warrants purchased by Mr. Warren, and stock options issued to Mr.
Dobkins and Mr. Kuhn in the third quarter of 1998. This non-cash expense
was recognized in accordance with APB No. 25, "Accounting for Stock Issued
to Employees." See 5(c) to our audited financial statements included in
this prospectus.
(2) Mr. Rady became an executive officer on June 16, 1998, compensated at an
annual salary of $120,000. Mr. Rady's annual salary was increased to
$180,000 effective January 15, 1999. On January 21, 1999, Mr. Rady received
options to purchase 400,000 shares of common stock.
(3) Mr. Warren became an executive officer on July 2, 1998, compensated at an
annual salary of $100,000. Mr. Warren's annual salary was increased to
$150,000 effective January 15, 1999. On January 21, 1999, Mr. Warren
received options to purchase 250,000 shares of common stock.
(4) Mr. Dobkins became an officer on July 6, 1998, compensated at an annual
salary of $95,000. Mr. Dobkins annual salary was increased to $120,000
effective January 15, 1999. On January 21, 1999, Mr. Dobkins received
options to purchase 125,000 shares of common stock.
(5) Mr. Kuhn became an officer on July 9, 1998, compensated at an annual salary
of $87,000. Mr. Kuhn's annual salary was increased to $110,000 effective
January 15, 1999. On January 21, 1999, Mr. Kuhn received options to
purchase 75,000 shares of common stock.
1998 Stock Option and Incentive Plan
On March 24, 1998, our board of directors adopted the 1998 Stock Option and
Incentive Plan which was subsequently approved by our stockholders. Our
stockholders approved an amendment to the plan on June 29, 1998. The plan is
intended to provide incentive to key employees and directors of, and key
consultants, vendors, customers, and others expected to provide significant
services to Pennaco. The goals of the plan are to:
. encourage proprietary interest in Pennaco;
. encourage our key employees to remain in our employ;
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<PAGE>
. attract new employees with outstanding qualifications; and
. provide additional incentive to consultants, vendors, customers and
others to increase their efforts in providing significant services to
Pennaco.
The plan is administered by our board of directors or can be administered by
a committee appointed by the board, which committee shall consist of not less
than two members and shall be constituted to permit the plan to comply with
Rule 16b-3 of the Securities Exchange Act of 1934. The board of directors, or
the committee if there is one, at its discretion, can select the eligible
employees and consultants to be granted awards, determine the number of shares
to be applicable to such award, and designate any options as incentive stock
options or nonstatutory stock options, except that no incentive stock option
may be granted to a non-employee director or a non-employee consultant. The
stock subject to awards granted under the plan are shares of our authorized but
unissued or reacquired common stock. The aggregate number of shares which may
be issued as awards or upon exercise of awards under the plan is 4,500,000
shares. As of October 14, 1999, non-statutory stock options to purchase
3,893,353 have been granted to key employees and directors for exercise prices
ranging from $1.25 to $12.19 per share pursuant to the vesting schedules of the
respective agreements. As of October 14, 1999, 126,250 of these options have
been exercised. Unexercised options in the amount of 1,273,125 are vested as of
October 14, 1999, while 2,493,978 of the options either vest over the next four
years or are tied to certain benchmarks being achieved with regards to the
drilling of wells or obtaining certain annual gross production revenues. The
shares that may be issued pursuant to the exercise of an option awarded by the
plan have been registered under the Securities Act of 1933.
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<PAGE>
The following table reflects certain information regarding stock options
granted to the Named Executive Officers for the period from inception to
December 31, 1998:
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
Individual Grants
--------------------------------
Percentage of
Number of Total Options
Securities Granted to
Underlying Employees as of
Options the Period Ended Exercise Price
Granted December 31, 1998 Per Share Expiration Date
---------- ----------------- -------------- --------------------
<S> <C> <C> <C> <C>
Paul M. Rady (1)........ 400,000 13.5% $2.50 June 15, 2008
400,000 13.5% 5.00 June 15, 2008
Glen C. Warren, Jr. (2). 200,000 6.8% 2.50 July 1, 2008
100,000 3.4% 3.25 July 1, 2008
200,000 6.8% 5.00 July 1, 2008
13,228 0.4% 3.25 September 3, 2008
Terrell A. Dobkins (3).. 175,000 5.9% 3.25 July 6, 2004 through
July 6, 2007 (4)
75,000 2.5% 2.50 July 6, 2004 through
July 6, 2007 (4)
Brian A. Kuhn (5)....... 100,000 3.4% 3.25 July 9, 2004 through
July 9, 2007 (4)
50,000 1.7% 2.50 July 9, 2004 through
July 9, 2007 (4)
</TABLE>
- --------
(1) On January 21, 1999, Mr. Rady received options to purchase 400,000 shares
of common stock with an exercise price of $3.19 per share. The expiration
date for these options is five years subsequent to vesting which occurs
ratably over a four-year period from the date of grant.
(2) On January 21, 1999, Mr. Warren received options to purchase 250,000 shares
of common stock with an exercise price of $3.19 per share. The expiration
date for these options is five years subsequent to vesting which occurs
ratably over a four-year period from the date of grant.
(3) On January 21, 1999, Mr. Dobkins received options to purchase 125,000
shares of common stock with an exercise price of $3.19 per share. The
expiration date for these options is five years subsequent to vesting which
occurs ratably over a four-year period from the date of grant.
(4) Option expiration date is five years subsequent to vesting which occurs
ratably over a four-year period from the date of grant.
(5) On January 21, 1999, Mr. Kuhn received options to purchase 75,000 shares of
common stock with an exercise price of $3.19 per share. The expiration date
for these options is five years subsequent to vesting which occurs ratably
over a four-year period from the date of grant.
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<PAGE>
The following table reflects certain information concerning the number of
unexercised options held by the Named Executive Officers and the value of such
officers' unexercised options as of December 31, 1998. No options were
exercised by the Named Executive Officers during the period ended December 31,
1998.
OPTION VALUES AS OF THE PERIOD ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
Number of Securities Value of Unexercised
Underlying in the Money
Unexercised Options Held at Options Held at
December 31, 1998 December 31, 1998 (1)
------------------------------- -------------------------
Exercisable Unexercisable Exercisable Unexercisable
------------ --------------- ----------- -------------
<S> <C> <C> <C> <C>
Paul M. Rady............ -- 800,000 -- $450,000
Glen C. Warren, Jr...... -- 513,228 -- 267,460
Terrell A. Dobkins...... -- 250,000 -- 150,000
Brian A. Kuhn........... -- 150,000 -- 93,750
</TABLE>
- --------
(1) Options are "in-the-money" if the closing market price of our common stock
exceeds the exercise price of the options. The exercise price of the
options granted to the Named Executive Officers is $1.25 to $3.25 per
share. The value of unexercised options for each of the Named Executive
Officers represents the difference between the exercise price of such
options and the closing price of our common stock on December 31, 1998
($3.63 per share).
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<PAGE>
PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth information concerning the beneficial
ownership of our common stock as of August 31, 1999, for:
. each current director;
. each of the Named Executive Officers;
. all persons that we know beneficially own more than 5% of the
outstanding shares of our common stock;
. all current directors and executive officers as a group; and
. the security holder offering stock for sale pursuant to this prospectus.
All persons listed, unless otherwise noted, have an address in care of
Pennaco's principal executive offices and have sole voting and investment power
with respect to their shares unless otherwise indicated. The information
presented under "Shares Beneficially Owned After Offering" assumes that all of
the shares offered by the selling stockholder will be sold. Unless otherwise
noted, each of the stockholders listed below has an address c/o Pennaco Energy,
Inc., 1050 17th Street, Suite 700, Denver, Colorado 80265.
<TABLE>
<CAPTION>
Shares Beneficially Shares Beneficially
Owned Prior to Offering (1) Owned After Offering
-------------------------------------Shares Being ------------------------
Name Number Percent (2) Offered Number Percent
---- ---------------- ---------------------------- ------------- ----------
<S> <C> <C> <C> <C> <C>
Paul M. Rady................................ 1,057,144 (3) 6.7% -- 1,057,144 5.8%
Glen C. Warren, Jr.......................... 387,500 (4) 2.5% -- 387,500 2.2%
Terrell A. Dobkins.......................... 62,500 (5) * -- 62,500 *
Brian A. Kuhn............................... 37,500 (6) * -- 37,500 *
Gregory V. Gibson........................... 100,000 (7) * -- 100,000 *
David W. Lanza.............................. 66,000 (8) * -- 66,000 *
RIS Resources International Corp............ 2,500,000 (9) 16.0% 1,250,000 1,250,000 7.0%
State Street Research & Management Company.. 1,663,000 (10) 10.7% -- 1,663,000 9.3%
Joseph H. Reich............................. 1,022,400 (11) 6.6% -- 1,022,400 5.7%
Peter K. Seldin............................. 1,022,400 (12) 6.6% -- 1,022,400 5.7%
Centennial Energy Partners, L.L.C........... 977,400 6.3% -- 977,400 5.5%
All directors and executive officers as a
group (six persons)........................ 1,710,644 10.5% -- 1,710,644 9.3%
</TABLE>
- --------
* Represents less than 1% of the common stock outstanding.
(1) A person is deemed to be the beneficial owner of securities that can be
acquired by such person within 60 days from the date hereof. Each
beneficial owner's percentage ownership is determined by assuming that
rights held by such person to acquire shares (but not those held by any
other person) and which are exercisable within 60 days from the date
hereof have been exercised.
(2) Assumes 15,586,129 shares outstanding plus, for each individual, any
securities that specific person has the right to acquire within 60 days.
Options and warrants held by persons other than the specific individual
for whom an ownership interest percentage is being calculated are not
considered in calculating that specific individual's ownership interest
percentage.
(3) Includes 285,715 shares issuable upon the exercise of stock purchase
warrants and 200,000 shares issuable upon the exercise of stock options.
(4) Includes 125,000 shares issuable upon the exercise of stock options.
(5) Includes 38,750 shares issuable upon the exercise of stock options.
(6) Shares issuable upon the exercise of stock options.
44
<PAGE>
(7) Represents 100,000 shares issuable upon the exercise of stock options. Mr.
Gibson's address is 2 Park Plaza, Suite 450, Irvine, California 92614.
(8) Includes 50,000 shares issuable upon the exercise of stock options. Mr.
Lanza's address is 2 Park Plaza, Suite 450, Irvine, California 92614.
(9) RIS Resources International Corp. is a holding company that specializes in
natural gas development in the western United States. The address of RIS
is 609 West Hastings Street, 11th Floor, Vancouver, British Columbia V6B
4W4, Canada. According to the directors and officers of RIS, the only
person who owns more than 10% of the outstanding voting rights of RIS is
John Hislop, who owns 10.22% of the outstanding RIS common stock.
(10) State Street Research and Management Company has sole voting and
dispositive power with respect to 1,663,000 shares of common stock. State
Street Research and Management is an Investment Adviser registered under
Section 203 of the Investment Advisors Act of 1940. The shares attributed
to State Street are owned by State Street's clients. The address of State
Street is One Financial Center, 30th Floor, Boston, MA 02111-2690.
(11) Mr. Reich: (1) as the Managing Member of Centennial Management, L.L.C.,
has the power to vote and dispose of the 20,000 shares of common stock it
beneficially owns; (2) as the Managing Member of Centennial Energy
Partners, L.L.C., has the power to vote and dispose of the 977,400 shares
of common stock it beneficially owns; and (3) as President of Joseph H.
Reich & Co., Inc., has the power to vote and dispose of the 25,000 shares
of common stock it beneficially owns. The address for Centennial and
Messrs. Seldin and Reich is 900 Third Avenue, Suite 1801, New York, New
York 10022.
(12) Mr. Seldin: (1) as a non-managing member of Centennial Management, L.L.C.,
has been delegated the authority to vote and dispose of the 20,000 shares
of common stock it beneficially owns; (2) as a non-managing member of
Centennial Energy Partners, L.L.C., has been delegated the authority to
vote and dispose of the 977,400 shares of common stock it beneficially
owns; and (3) as Vice President of Joseph H. Reich & Co., Inc., has the
power to vote dispose and dispose of the 25,000 shares it beneficially
owns.
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<PAGE>
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During 1998, we paid approximately $192,000 to the law firm Gibson, Haglund
& Paulsen for legal services it provided to Pennaco. Gregory V. Gibson, Vice
President--Legal, Secretary a director of Pennaco, is also a partner of this
firm.
During 1998, we paid approximately $150,000 to Jeffrey Taylor, a director in
1998, for advisory services he provided to Pennaco.
During 1998, the selling stockholder, RIS Resources International Corp.,
loaned $500,000 to Pennaco. This loan has been fully re-paid.
46
<PAGE>
DESCRIPTION OF CAPITAL STOCK
As of June 30, 1999, our authorized capital stock consisted of 50,000,000
shares of $.001 par value common stock and 10,000,000 shares of $.001 par value
preferred stock. The following summary of the terms and provisions of our
capital stock does not purport to be complete and is qualified in its entirety
by reference to our articles of incorporation and by-laws, which have been
filed as exhibits to our registration statement, of which this prospectus is a
part, and applicable law.
Common Stock
Listing
Our outstanding shares of common stock are listed on the American Stock
Exchange under the symbol "PN." The additional common stock issued in
connection with this offering will also be listed on the American Stock
Exchange.
Dividends
We have never paid cash dividends on our capital stock and we do not
anticipate paying cash dividends in the foreseeable future. Any future
determination to pay cash dividends will be at the discretion of our board of
directors and will be dependent upon our financial condition, results of
operation, capital requirements and other factors that the board of directors
deems to be relevant. In addition, our credit facility contains restrictions on
our ability to pay cash dividends.
Voting Rights
Subject to any special voting rights of any series of preferred stock that
we may issue in the future, the holders of our common stock may vote one vote
for each share held in the election of directors and on all other matters voted
upon by our stockholders. Holders of common stock may not cumulate their votes
in the election of directors.
Other Rights
We will notify our stockholders of any stockholders' meetings according to
our bylaws and applicable law. If we liquidate, dissolve or wind-up our
business, either voluntarily or not, our stockholders will share equally in the
assets remaining after we pay our creditors and preferred stockholders, if we
have outstanding preferred stock at such time. The holders of common stock have
no statutory preemptive rights to purchase our shares of stock. Shares of
common stock are not subject to any redemption provisions and are not
convertible into any of our other securities.
Preferred Stock
Subject to the provisions of our articles of incorporation, the board of
directors has the authority to issue up to 10,000,000 shares of preferred stock
without the approval of our stockholders. The following description of the
terms of the preferred stock sets forth the general terms and provisions of our
authorized preferred stock. If we offer preferred stock, a description will be
filed with the SEC and with the Secretary of State of Nevada and the specific
designations and rights will be described in a prospectus relating to the
preferred stock, including the following terms:
. the series, the number of shares offered and the liquidation value of
the preferred stock;
. the price at which the preferred stock will be issued;
. whether the preferred stock is entitled to dividends, and if so, the
dividend rate, the dates on which the dividends will be payable and
other terms relating to the payment of dividends on the preferred stock;
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<PAGE>
. whether there is a liquidation preference for the preferred stock;
. whether the preferred stock has voting rights;
. whether the preferred stock is redeemable or subject to a sinking fund,
and the terms of any redemption or sinking fund;
. whether the preferred stock is convertible or exchangeable for any other
securities, and the terms of any conversion; and
. any additional rights, preferences, qualifications, limitations and
restrictions of the preferred stock.
Our board of directors can, without the approval of the stockholders, issue
one or more series of preferred stock. Subject to the provisions of our
articles of incorporation and limitations prescribed by law, our board of
directors may adopt resolutions to determine the number of shares of each
series and the rights, preferences and limitations of each series including the
dividend rights, voting rights, conversion rights, redemption rights and any
liquidation preferences of any wholly unissued series of preferred stock, the
number of shares constituting each series and the terms and conditions of
issue. Under some circumstances, preferred stock could restrict dividend
payments to the holders of our common stock.
Undesignated preferred stock may enable our board of directors to render
more difficult or to discourage a third party's attempt to obtain control of
Pennaco by means of a tender offer, proxy contest, merger or otherwise, and to
thereby protect the continuity of our management. The issuance of shares of
preferred stock may adversely affect the rights of the holders of our common
stock. For example, any preferred stock issued may rank prior to our common
stock as to dividend rights, liquidation preference or both, may have full or
limited voting rights and may be convertible into shares of common stock. As a
result, this issuance of shares of preferred stock may discourage bids for our
common stock or may otherwise adversely affect the market price of our common
stock or any existing preferred stock.
Anti-Takeover Provisions
Certain provisions in our articles of incorporation, by-laws and our
stockholders' rights plan 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.
Classified Board of Directors and Limitations of Removal of Directors
Our board of directors is divided into three classes. The directors of each
class are elected for three-year terms, and the terms of office of the three
classes are staggered so that directors from a single class are elected at each
annual meeting of stockholders. Directors can only be removed for cause. A
staggered board makes it more difficult for stockholders to change the majority
of the directors and instead promotes a continuity of existing management.
No Stockholder Action Without a Meeting
Under Nevada General Corporation Law, unless the articles of incorporation
specifies otherwise, any action that could be taken by stockholders at an
annual or special meeting may be taken, instead, without a meeting and without
notice to or a vote of other stockholders if a consent in writing is signed by
holders of outstanding stock having voting power that would be sufficient to
take such action at a meeting at which all outstanding shares were present and
voted. Our articles of incorporation provide that stockholder action may be
taken only at an annual or special meeting of stockholders. As a result,
stockholders may not act upon any matter except at a duly called meeting.
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<PAGE>
Blank Check Preferred Stock
Our articles of incorporation authorize the issuance of blank check
preferred stock. The board of directors can set the voting rights, redemption
rights, conversion rights and other rights relating to the preferred stock and
could issue the preferred stock in either a private or public transaction
without the approval of our stockholders. In some circumstances, the blank
check preferred stock could be issued and have the effect of preventing a
merger, tender offer or other takeover attempt which the board of directors
opposes.
Business Combinations Under Nevada Law
Nevada's "Business Combinations" statute, Nevada Revised Statutes Sections
78.411-78.444, which applies to Nevada corporations having at least 200
stockholders which have not opted-out of the statute, prohibits an "interested
stockholder" from entering into a "combination" with the corporation, unless
certain conditions are met. An "interested stockholder" is a person who (1)
directly or indirectly beneficially owns 10% or more of the voting power of the
outstanding voting shares of the corporation or (2) an affiliate or associate
of the corporation which at any time within three years before the date in
question was the beneficial owner, directly or indirectly, of 10% or more of
the voting power of the then outstanding shares of the corporation. A
"combination" includes:
(a) any merger or consolidation with an "interested stockholder," or any
other corporation which is or after the merger or consolidation would
be, an affiliate or associate of the interested stockholder;
(b) any sale, lease, exchange, mortgage, pledge, transfer or other
disposition of assets, in one transaction or a series of transactions,
to or with an "interested stockholder," having (1) an aggregate market
value equal to 5% or more of the aggregate market value of the
corporation's assets determined on a consolidated basis, (2) an
aggregate market value equal to 5% or more of the aggregate market
value of all outstanding shares of the corporation or (3) representing
10% or more of the earning power or net income of the corporation
determined on a consolidated basis;
(c) any issuance or transfer of shares of the corporation or its
subsidiaries, to the stockholders, having an aggregate market value
equal to 5% or more of the aggregate market value of all the
outstanding shares of the corporation, except under the exercise of
warrants or rights to purchase shares offered, or a dividend or
distribution paid or made pro rata to all stockholders of the
corporation;
(d) the adoption of any plan or proposal for the liquidation or dissolution
of the corporation proposed by or under any agreement, arrangement or
understanding, whether or not in writing, with the "interested
stockholder;"
(e) certain transactions which would have the effect of increasing the
proportionate share of outstanding shares of the corporation owned by
the "interested stockholder;" or
(f) the receipt of benefits, except proportionately as a stockholder, of
any loans, advances or other financial benefits by an "interested
stockholder."
A corporation to which the statute applies may not engage in a "combination"
within three years after the interested stockholder acquired its shares, unless
the combination or the interested stockholder's acquisition of shares was
approved by the board of directors before the interested stockholder acquired
the shares. If this approval was not obtained, then after the three-year period
expires, the combination may be consummated if all the requirements in the
corporation's articles of incorporation are met and either:
(a) the board of directors of the corporation approves, prior to the
"interested stockholder's" date of acquiring shares, or as to which the
purchase of shares by the "interested stockholder" has been approved by
the corporation's board of directors before that date; or
(b) the combination is approved by the affirmative vote of holders of a
majority of voting power not beneficially owned by the "interested
stockholder" at a meeting called no earlier than three years after the
date the "interested stockholder" became such or the aggregate amount
of cash and the
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<PAGE>
market value of consideration other than cash to be received by holders
of common shares and holders of any other class or series of shares
meets the minimum requirements set forth in Sections 78.411 through
78.443 of the Nevada Revised Statutes and prior to the consummation of
the combination, except in limited circumstances, the "interested
stockholder" will not have become the beneficial owner of additional
voting shares of the corporation.
Rights Plan
Our board of directors has adopted a stockholders' rights plan. In
connection with the adoption of the rights plan, our board of directors
declared a dividend distribution of one common stock purchase right for each
outstanding share of our common stock. The distribution was payable to the
stockholders of record at the close of business on the record date, March 9,
1999. Each right entitles its registered holder to purchase from Pennaco one-
half of a share of common stock, at a price of $20, which price is subject to
adjustment. The following is only a summary of the rights; the full description
and terms of the rights are set forth in a rights agreement between Pennaco and
Harris Trust and Savings Bank, as rights agent. The rights plan is filed as an
exhibit to a Form 8-A filed by Pennaco with the SEC on April 16, 1999. This
summary description of the rights is not complete. You should refer to the
Rights Agreement for a complete discussion of the rights.
Initially, the rights will attach to all certificates representing shares of
our outstanding common stock, and no separate rights certificates will be
distributed. The rights will separate from our common stock and the
distribution date of the rights will occur upon the earlier of:
(1) ten days following the date of public announcement that a person or
group of persons has become an acquiring person, which is defined
below; or
(2) ten business days, or a later date as may be determined by action of
our board of directors prior to the time a person becomes an acquiring
person, following the commencement of, or the announcement of an
intention to make, a tender offer or exchange offer upon consummation
of which the offeror would, if successful, become an acquiring person.
The date that is first to occur is the "distribution date."
The term "acquiring person" means any person who or which, together with all
of its affiliates and associates, is the beneficial owner of 15% or more of our
outstanding common stock, but shall not include:
(1) Pennaco or any of our subsidiaries or any of our employee benefit
plans; or
(2) RIS Resources International Corp. and its subsidiaries or any other
person or entity in which RIS is at the time of determination the
direct record and beneficial of all outstanding voting securities.
The rights agreement provides that, until the distribution date, the rights
will be transferred with and only with our common stock. Until the distribution
date, or an earlier redemption or expiration of the rights, new common stock
certificates issued after the record date, upon transfer or new issuance of
common stock, which will contain a notation incorporating the rights agreement
by reference. Until the distribution date, or an earlier redemption or
expiration of the rights, the surrender for transfer of any certificates for
our common stock, outstanding as of the record date, even without the notation
or a copy of the summary of rights being attached, will also constitute the
transfer of the rights associated with our common stock represented by such
certificate. As soon as possible following the distribution date, separate
certificates evidencing the rights will be mailed to holders of record of our
common stock as of the close of business on the distribution date and such
separate rights certificates alone will evidence the rights.
The rights are not exercisable until the distribution date and will expire
on March 9, 2009.
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<PAGE>
The purchase price payable, and the number of one-half of a share of our
common stock or other securities or property issuable, upon exercise of the
rights are subject to adjustment from time to time to prevent dilution:
(1) in the event of a stock dividend on, or a subdivision, combination or
reclassification of, our common stock;
(2) upon the grant to holders of our common stock of rights or warrants to
subscribe for or purchase shares of our common stock at a price, or
securities convertible into our common stock with a conversion price,
less than the then current market price of our common stock; or
(3) upon the distribution to holders of our common stock of evidences of
indebtedness or assets, excluding regular periodic cash dividends paid
or dividends payable in our common stock, or of subscription rights or
warrants, other than those referred to in (2) above.
The number of outstanding rights and the number of one-half of a share of
common stock issuable upon exercise of each right are also subject to
adjustment in the event of a stock split of the common stock or a stock
dividend on the common stock payable in the common stock or subdivisions,
consolidations or combinations of the common stock occurring, in any such case,
before the distribution date.
In the event that following a stock acquisition date, which is the date of
public announcement that a person has become an acquiring person, we are
acquired in a merger or other business combination transaction or more than 50%
of our consolidated assets or earning power are sold, proper provision will be
made so that each holder of a right will thereafter have the right to receive,
upon the exercise thereof at the then current exercise price of the right, that
number of shares of common stock of the acquiring company which at the time of
such transaction will have a market value of two times the exercise price of
the right, which is known as the flip-over right.
In the event that a person other than an exempt person becomes an acquiring
person, proper provision shall be made so that each holder of a right, other
than the acquiring person and its affiliates and associates, will thereafter
have the right to receive upon exercise that number of shares of common stock,
or, under certain circumstances, cash, other equity securities or property of
Pennaco having a market value equal to two times the purchase price of the
rights, which is known as the flip-in right. Upon the occurrence of the
foregoing event giving rise to the exercisability of the rights, any rights
that are or were at any time owned by an acquiring person will become void.
With certain exceptions, no adjustment in the purchase price will be
required until cumulative adjustments require an adjustment of at least 1% in
the purchase price. Upon exercise of the rights, no fractional shares of common
stock will be issued and cash will be paid in the place of fractional shares of
common stock.
At any time prior to the earlier to occur of (1) 5:00 p.m., Houston, Texas
time, on the 10th day after the stock acquisition date or (2) the expiration of
the rights, we may redeem the rights in whole, but not in part, at a price of
$0.01 per right, which is known as the redemption price; provided, that (a) if
the board of directors authorizes redemption on or after the time a person
becomes an acquiring person, then that authorization must be by board approval
and (b) the period for redemption may, upon board approval, be extended by
amending the rights agreement. The term "board approval" means the approval of
a majority of our directors. Immediately upon any redemption of the rights
described in this paragraph, the right to exercise the rights will terminate
and the only right of the holders of rights will be to receive the redemption
price.
The terms of the rights may be amended by the board of directors without the
consent of the holders of the rights at any time and from time to time provided
that such amendment does not adversely affect the interests of the holders of
the rights. In addition, during any time that the rights are subject to
redemption, the terms of the rights may be amended by board approval, including
an amendment that adversely affects the interests of the holders of the rights,
without the consent of the holders of rights.
51
<PAGE>
Until a right is exercised, the holder of the rights, as such, will have no
rights as a stockholder of Pennaco, including, without limitation, the right to
vote or to receive dividends. While the distribution of the rights will not be
taxable to our stockholders or to Pennaco, stockholders may, depending upon the
circumstances, recognize taxable income in the event that the rights become
exercisable for common stock or other consideration.
Limitation of Liability of Officers and Directors
We believe that certain provisions of our articles and by-laws will be
useful to attract and retain qualified persons as directors and officers. Our
articles limit the liability of directors to the fullest extent permitted by
Nevada law. This is intended to allow our directors the benefit of Nevada
General Corporation Law which provides that directors of Nevada corporations
may be relieved of monetary liabilities for breach of their fiduciary duties as
directors, except under certain circumstances, including:
(1) acts or omissions which involve intentional misconduct, fraud or a
knowing violation of law; or
(2) the willful or grossly negligent payment of unlawful distributions.
Our articles of incorporation and by-laws generally require us to indemnify
our directors and officers to the fullest extent permitted by Nevada law. Our
articles of incorporation and by-laws also require us to advance expenses to
our directors and officers to the fullest extent permitted by Nevada law upon
the receipt of an undertaking by or on behalf of such director or officer to
repay such amount if it should be ultimately determined that they are not
entitled to indemnification by Pennaco. We intend to enter into indemnification
agreements with our officers and directors prior to the consummation of this
offering that provide for the indemnification and advancement of expenses by
Pennaco. Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers or persons controlling
Pennaco pursuant to the foregoing provisions, we have been informed, in the
opinion of the SEC, this indemnification is against public policy as expressed
in the Securities Act and is, therefore, unenforceable. We intend to obtain,
prior to the completion of this offering, officer and director liability
insurance with respect to liabilities arising out of certain matters, including
matters arising under the Securities Act. There is no pending litigation or
proceeding involving a director, officer, associate or other agent of Pennaco
as to which indemnification is being sought, nor are we aware of any threatened
litigation that may result in claims for indemnification by any director,
officer, associate or other agent.
Transfer Agent
Our transfer agent and registrar for our common stock is Harris Trust and
Savings Bank, P.O. Box A3504, Chicago, Illinois 60690-3504.
52
<PAGE>
UNDERWRITING
Subject to the terms and conditions of the underwriting agreement dated
October 14, 1999, among the underwriters and Pennaco, the underwriters named
below, who are represented by Bear, Stearns & Co. Inc., A.G. Edwards & Sons,
Inc., Howard, Weil, Labouisse, Friedrichs Incorporated, and Hanifen, Imhoff
Inc., have severally agreed to purchase from Pennaco and the selling
stockholder the respective numbers of shares of common stock at the public
offering price less the underwriting discounts and commissions set forth on the
cover page of this prospectus.
<TABLE>
<CAPTION>
Underwriters Number of Shares
------------ ----------------
<S> <C>
Bear, Stearns & Co. Inc. ................................... 1,610,000
A.G. Edwards & Sons, Inc. .................................. 644,000
Howard, Weil, Labouisse, Friedrichs Incorporated............ 644,000
Hanifen, Imhoff Inc. ....................................... 322,000
Ladenburg Thalmann & Co. Inc................................ 70,000
Morgan Keegan & Company, Inc................................ 70,000
Petrie Parkman & Co......................................... 70,000
Sanders Morris Mundy........................................ 70,000
---------
Total..................................................... 3,500,000
=========
</TABLE>
The underwriting agreement provides that the obligations of the several
underwriters to purchase and accept delivery of the shares included in this
offering are subject to approval of legal matters by their counsel and to
customary conditions, including the effectiveness of the registration
statement, the continuing correctness of our representations to them, the
receipt of a "comfort letter" from our accountants and no occurrence of an
event that would have a material adverse effect on our business. The
underwriters are obligated to purchase and accept delivery of all the shares,
other than those covered by the over-allotment option described below, if they
purchase any of the shares.
The Company has granted to the underwriters an option, exercisable for 30
days from the date of the underwriting agreement, to purchase up to 525,000
additional shares of common stock at the public offering price less the
underwriting discounts and commissions. The underwriters may exercise such
option solely to cover over-allotments, if any, made in connection with this
offering. To the extent that the underwriters exercise such option, each
underwriter will become obligated, subject to conditions, to purchase a number
of additional shares approximately proportionate to such underwriter's initial
purchase commitment.
The underwriters propose to initially offer some of the shares directly to
the public at the public offering price set forth on the cover page of this
prospectus and some of the shares to dealers at the public offering price less
a concession not in excess of $0.40 per share. The underwriters may allow, and
such dealers may re-allow, a concession not in excess of $0.10 per share on
sales to other dealers. After the initial offering of the shares to the public,
the representatives of the underwriters may change the public offering price
and such concessions.
Our officers, directors and certain other stockholders have agreed pursuant
to lock-up agreements not to sell or offer to sell or otherwise dispose of
shares of common stock, subject to certain exceptions, for a period of 180 days
after the date of this prospectus without the prior written consent of Bear,
Stearns & Co. Inc. Additionally, one stockholder has entered into a lock-up
agreement related to 200,000 of his shares under which he has agreed not to
offer or sell these shares for a period of 120 days.
In addition, we have agreed with the underwriters not to dispose of or hedge
any shares of common stock or securities convertible into or exchangeable for
shares of common stock during the period from the date of this prospectus and
continuing through the date 180 days after the date of this prospectus, except
with the prior written consent of Bear, Stearns & Co. Inc. These agreements do
not apply to issuances or sales of common stock by us pursuant to any existing
employee benefit plans or upon exercise, conversion or exchange of any
currently outstanding securities.
53
<PAGE>
In order to facilitate the offering, the underwriters may engage in
transactions that stabilize, maintain or otherwise affect the market price of
our common stock. Specifically, the underwriters may over-allot shares of our
common stock in connection with this offering, thereby creating a short
position in our common stock for their own account. Additionally, to cover such
over-allotments or to stabilize the market price of our common stock, the
underwriters may bid for, and purchase, shares of our common stock in the open
market. Finally, the representatives, on behalf of the underwriters, also may
reclaim selling concessions allowed to an underwriter or dealer if the
underwriting syndicate repurchases shares distributed by that underwriter or
dealer. Any of these activities may maintain the market price of our common
stock at a level above that which might otherwise prevail in the open market.
These transactions may be effected on the American Stock Exchange, in the over-
the-counter market or otherwise. The underwriters are not required to engage in
these activities and, if commenced, may end any of these activities at any
time.
We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act, or to contribute to payments
the underwriters may be required to make in respect thereof.
The representatives of the underwriters have advised us that the
underwriters do not intend to confirm sales to any account over which they
exercise discretionary authority.
A.G. Edwards & Sons, Inc., one of the representatives, provided services to
the selling stockholder in connection with a proposed private placement by the
selling stockholder of our common stock which did not occur but for which the
selling stockholder has agreed to reimburse A.G. Edwards & Sons, Inc. expenses
in the approximate amount of $10,000.
Hanifen, Imhoff Inc., one of the representatives, issued a fairness opinion
to Pennaco in connection with our sale to CMS Oil and Gas Company on October
23, 1998, of an undivided 50% working interest in certain leasehold interests
for which we paid Hanifen, Imhoff Inc. $129,000 in fees and expenses.
54
<PAGE>
EXPERTS
Some of the information that appears in this registration statement
regarding the January 1, 1999, July 1, 1999, and September 1, 1999, estimated
quantities of reserves of the underlying properties we own, the future net
revenues from those reserves and their present value is based on estimates of
the reserves and present values prepared by or derived from estimates prepared
by Ryder Scott Company, independent petroleum engineers.
The financial statements of Pennaco Energy, Inc. as of December 31, 1998,
and for the period from January 26, 1998, (inception) to December 31, 1998,
have been included in this prospectus and in the registration statement in
reliance upon the report of KPMG LLP, independent certified public
accountants, appearing elsewhere in this prospectus, and upon the authority of
that firm as experts in accounting and auditing.
LEGAL MATTERS
Certain legal matters in connection with the shares of common stock offered
by this prospectus will be passed upon for us by Andrews & Kurth L.L.P.,
Houston, Texas. Certain legal matters in connection with the offering will be
passed upon for the underwriters by Latham & Watkins, New York, New York.
Certain matters of Nevada law, including validity of the shares offered by
this prospectus, will be passed upon by Kummer Kaempfer Bonner and Renshaw,
Las Vegas, Nevada.
WHERE TO FIND MORE INFORMATION
We have filed a registration statement on Form S-1 to register with the SEC
the common stock offered by this prospectus. This prospectus is a part of that
registration statement. As allowed by SEC rules, this prospectus does not
contain all of the information contained in the registration statement or the
exhibits to the registration statement.
We are subject to the informational requirements of the Securities Exchange
Act of 1934. Accordingly, we file annual, quarterly and current reports, proxy
statements, and other information with the SEC. The public may read and copy
any reports, statements, or other information that we file at the SEC's public
reference room at Judiciary Plaza, 450 Fifth Street N.W., Washington, D.C.
20549. The public may obtain information on the operation of the public
reference room by calling the SEC at 1-800-SEC-0330. Our SEC filings are also
available to the public from commercial document retrieval services and at the
web site maintained by the SEC at "http://www.sec.gov".
You may request a copy of these filings at no cost, by writing or
telephoning us at the following address:
Pennaco Energy, Inc.
Attention: Glen C. Warren, Jr.
1050 17th Street, Suite 700
Denver, Colorado 80265
(303) 629-6700
You should rely on the information contained in this prospectus and any
prospectus supplement. We have not authorized anyone to provide you with
information that is different from what is contained in this prospectus.
You should not assume that the information contained in this prospectus or
any prospectus supplement is accurate as of any date other than the date on
the front of those documents, and neither the delivery of this prospectus or
any prospectus supplement to you nor the issuance of stock under them will
create any implication to the contrary.
55
<PAGE>
PENNACO ENERGY, INC.
INDEX TO FINANCIAL STATEMENTS
Annual Financial Statements:
<TABLE>
<S> <C>
Independent Accountants' Report........................................ F-2
Balance Sheet at December 31, 1998..................................... F-3
Statement of Operations for the period from January 26, 1998
(inception) to December 31, 1998...................................... F-4
Statement of Stockholders' Equity for the period from January 26, 1998
(inception) to December 31, 1998...................................... F-5
Statement of Cash Flows for the period from January 26, 1998
(inception) to December 31, 1998...................................... F-6
Notes to Financial Statements.......................................... F-7
Interim Financial Statements:
Balance Sheets at June 30, 1999 and December 31, 1998 (unaudited)...... F-16
Statements of Operations for the six months ended June 30, 1999 and the
period from January 26, 1998 (inception) to June 30, 1998
(unaudited)........................................................... F-17
Statement of Stockholders' Equity for the six months ended June 30,
1999 (unaudited)...................................................... F-18
Statements of Cash Flows for the six months ended June 30, 1999 and the
period from January 26, 1998 (inception) to June 30, 1998
(unaudited)........................................................... F-19
Notes to Financial Statements (unaudited).............................. F-20
</TABLE>
F-1
<PAGE>
INDEPENDENT ACCOUNTANTS' REPORT
The Board of Directors
Pennaco Energy, Inc.:
We have audited the accompanying balance sheet of Pennaco Energy, Inc. (a
development stage company) as of December 31, 1998, and the related statements
of operations, stockholders' equity and cash flows 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 on our audit.
We conducted our audit 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 audit provides 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, 1998, and the results of its operations and its cash flows for the
period from January 26, 1998 (inception) to December 31, 1998, in conformity
with generally accepted accounting principles.
KPMG LLP
Denver, Colorado
March 12, 1999
F-2
<PAGE>
PENNACO ENERGY, INC.
(A Development Stage Company)
BALANCE SHEET
<TABLE>
<CAPTION>
For the Year Ended
December 31, 1998
--------------------
Pro Forma
Historical (Note 2)
---------- ---------
(in thousands)
<S> <C> <C>
Current Assets:
Cash.................................................... $ 5,623 $19,804
Accounts receivable..................................... 375 375
Unit subscriptions receivable........................... 764 764
Assets held for sale.................................... 6,932 --
Drilling deposit........................................ 333 333
Inventory............................................... 231 231
Prepaid expenses and other current assets............... 152 152
------- -------
Total current assets.................................. 14,410 21,659
------- -------
Property and equipment, at cost:
Oil and gas properties, using the successful efforts
method of
accounting (note 8):
Unproved.............................................. 4,657 4,657
Proved................................................ 1,359 1,359
Other property and equipment............................ 296 296
------- -------
6,312 6,312
Less accumulated depreciation........................... (62) (62)
------- -------
Net property and equipment............................ 6,250 6,250
------- -------
Deferred income tax asset............................... 1,266 1,806
Other assets............................................ 100 100
------- -------
$22,026 $29,815
======= =======
Current liabilities:
Bridge loan payable (notes 2 and 3)..................... $ 5,600 $ --
Lease acquisitions payable.............................. 619 --
Accounts payable and accrued liabilities................ 1,964 1,964
Income taxes payable.................................... -- 5,389
------- -------
Total current liabilities............................. 8,183 7,353
------- -------
Stockholders' equity (note 5):
Common stock, $.001 par value. Authorized 50,000,000
shares; 14,795,179 shares issued and outstanding....... 15 15
Additional paid-in capital.............................. 17,641 17,641
Retained earnings (deficit) accumulated during the
development stage...................................... (3,813) 4,806
------- -------
Total stockholders' equity.............................. 13,843 22,462
------- -------
Commitments (note 7)
$22,026 $29,815
======= =======
</TABLE>
See accompanying notes to financial statements.
F-3
<PAGE>
PENNACO ENERGY, INC.
(A Development Stage Company)
STATEMENT OF OPERATIONS
Period from January 26, 1998 (inception) to December 31, 1998
(in thousands, except per share amounts)
<TABLE>
<S> <C>
Revenue:
Gain on sale of property........................................ $ 1,413
Interest income................................................. 55
-------
Total revenue................................................. 1,468
-------
Expenses:
Exploration..................................................... 1,826
Depreciation and amortization................................... 62
General and administrative...................................... 3,977
Interest expense................................................ 682
-------
Total expenses................................................ 6,547
-------
Loss before income taxes...................................... (5,079)
Income tax benefit.............................................. 1,266
-------
Net loss and deficit accumulated during the development
stage........................................................ $(3,813)
=======
Loss per share.................................................. $ (0.34)
=======
Weighted average common shares outstanding...................... 11,245
=======
</TABLE>
See accompanying notes to financial statements.
F-4
<PAGE>
PENNACO ENERGY, INC.
(A Development Stage Company)
STATEMENT OF STOCKHOLDERS' EQUITY
Period from January 26, 1998 (inception) to December 31, 1998
<TABLE>
<CAPTION>
Common Stock Units Additional
------------- to be Paid-in Accumulated
Shares Amount Issued Capital Deficit Total
------ ------ ------ ---------- ----------- -------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances at 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 $178,014
(note 5)................ 12,030 12 -- 10,608 -- 10,620
Compensation relating to
common stock and
warrants (note 5)....... -- -- -- 1,340 -- 1,340
Stock option compensation
(note 5)................ -- -- -- 450 -- 450
Units issued for cash,
net of offering costs of
$324,675 (note 5)....... 1,770 1 -- 4,232 -- 4,233
Warrants issued for
properties and services
(note 5)................ -- -- -- 249 -- 249
Units to be issued from
escrow (note 5)......... 357 -- 1 763 -- 764
Net loss for the period.. -- -- -- -- (3,813) (3,813)
------ ---- --- ------- ------- -------
Balances at December 31,
1998.................... 15,152 $ 14 1 $17,641 $(3,813) $13,843
====== ==== === ======= ======= =======
</TABLE>
See accompanying notes to financial statements.
F-5
<PAGE>
PENNACO ENERGY, INC.
(A Development Stage Company)
STATEMENT OF CASH FLOWS
Period from January 26, 1998 (inception) to December 31, 1998
(in thousands)
<TABLE>
<S> <C>
Cash flows from operating activities:
Net loss........................................................... $ (3,813)
Adjustments to reconcile net loss to net cash used in operating
activities:
Gain on the sale of property..................................... (1,413)
Depreciation and amortization.................................... 62
Compensation relating to common stock and warrants issued........ 1,340
Stock option compensation........................................ 450
Warrants issued for services..................................... 17
Deferred income tax benefit...................................... (1,266)
Increases in operating assets and liabilities:
Accounts receivable............................................ (375)
Prepaid expenses and other current assets...................... (152)
Inventory...................................................... (231)
Other assets................................................... (100)
Accounts payable and accrued liabilities....................... 1,964
--------
Net cash used by operating activities........................ (3,517)
--------
Cash flows from investing activities:
Capital expenditures............................................... (19,199)
Proceeds from sale of properties................................... 7,600
Drilling deposit................................................... (333)
Increase in lease acquisitions payable............................. 619
--------
Net cash used by investing activities........................ (11,313)
--------
Cash flows from financing activities:
Proceeds from issuance of bridge loans............................. 8,800
Repayment of bridge loan........................................... (3,200)
Proceeds from issuance of note payable............................. 500
Repayment of note payable.......................................... (500)
Proceeds from issuance of common stock, net of offering costs...... 14,853
--------
Net cash provided by financing activities.................... 20,453
--------
Net increase in cash................................................. 5,623
Cash at beginning of period.......................................... --
--------
Cash at end of period................................................ $ 5,623
========
Supplemental disclosures of cash flow information:
Cash paid for interest............................................. $ 682
========
Cash paid for income taxes......................................... $ --
========
</TABLE>
See accompanying notes to financial statements.
F-6
<PAGE>
PENNACO ENERGY, INC.
(A Development Stage Company)
December 31, 1998
NOTES TO FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Organization and Basis of Presentation
Pennaco Energy, Inc. (the "Company") is an independent energy Company
primarily engaged in the acquisition and development of natural gas production
from coal bed methane properties in the Rocky Mountain region of the United
States. The Company was incorporated on January 26, 1998 under the laws of the
state of Nevada and its headquarters are in Denver, Colorado.
The Company's activities to date have been limited to organizational
activities, prospect development activities, acquisition of leases and option
rights, and commencement of its drilling program. The Company currently has oil
and gas lease rights in the Powder River Basin in northeastern Wyoming and
southeastern Montana. Currently the Company has no revenue producing
operations. Accordingly, the Company is considered to be in the development
stage.
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 two years ended December 31, 1997 and prior thereto.
(b) 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.
Actual results could differ from those estimates.
(c) 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 many 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, if any. 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.
(d) 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-7
<PAGE>
(e) Oil and Gas Activities
The Company follows the successful efforts method of accounting for its oil
and gas activities. Accordingly, costs associated with the acquisition,
drilling and equipping of successful exploratory wells are capitalized.
Geological and geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells are charged to expense as incurred. 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 credited or charged 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.
Proved oil and gas properties are assessed for impairment on a field-by-
field basis. If the net capitalized costs of proved oil and gas 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.
(f) 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 15 years.
(g) 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.
(h) Stock-based Compensation
Statement of Financial Accounting Standards No. 123, Accounting for Stock-
Based Compensation (SAS 123), defines a fair value method of accounting for
stock compensation plans. SAS 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 of net loss and loss per share required by SAS 123 are
included in note 5.
(i) Loss Per Share
Loss per share is based on the weighted average number of common shares
outstanding during the period. Outstanding stock options and warrants were
excluded from the computation as their effect was antidilutive.
F-8
<PAGE>
(2) CMS TRANSACTION
On October 23, 1998, the Company and CMS Oil and Gas Company 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 Oil and Gas Company will acquire an undivided
50% working interest in approximately 492,000 net acres of Pennaco's leasehold
position in the Powder River Basin for $28,000,000. The Company acquired the
leasehold position which is being conveyed to CMS in the CMS Transaction for
approximately $7,000,000. The purchase price provided for in the CMS Agreement
was the result of arm's length negotiations between the Company and CMS. The
joint operating agreement between the parties will be 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. 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 affiliates of CMS Oil and Gas Company, for gathering, compression and
transportation.
Pursuant to the terms of the CMS Agreement, CMS agreed to pay Pennaco
$5,600,000 of earnest money in the form of a non-interest bearing bridge loan
(the "CMS Bridge Loan") which was secured by substantially all of the Company's
oil and as leases. Approximately $3,200,000 of such amount was paid directly to
existing creditors of the Company. The CMS Transaction is structured such that
the conveyance of the working interests was to occur 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
received $14,800,000 at the second closing, less approximately $1,800,000 which
is held in escrow subject to customary closing adjustments. As of March 12,
1999, approximately $1,200,000 was held in escrow pending CMS closing
adjustments. The CMS Bridge Loan was canceled at the second closing.
The unaudited pro forma balance sheet of the Company as of December 31, 1998
gives effect to the sale of the interest in the properties and the use of a
portion of the proceeds to repay the bridge loan and the lease acquisitions
payable, all as if the transactions had occurred on that date.
(3) 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.
(4) INCOME TAXES
The income tax benefit of $1,266,000 includes a deferred federal income tax
benefit of $1,196,000 and a deferred state income tax benefit of $70,000. The
income tax benefit recorded for the period from inception to December 31, 1998
differs from the expected income tax benefit (based on the 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.
F-9
<PAGE>
At December 31, 1998, the Company has a net operating loss carryforward for
federal income tax purposes of approximately $431,000 which is available to
offset future federal taxable income, if any, through 2018. The tax effects of
temporary differences that give rise to the deferred tax assets at December 31,
1998, relate to the net operating loss carryforward.
(5) STOCKHOLDERS' EQUITY
(a) Common Stock
Since its formation in January 1998, the Company completed four private
placement offerings of common stock. In February 1998, 500,000 shares were
issued at $.10 per share. Proceeds to the Company were approximately $50,000.
Also in February 1998, 4,530,000 shares were issued at $.22 per share. Proceeds
to the Company were approximately $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
$178,014 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) 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. 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 and are exercisable at
any time. Proceeds to the Company were approximately $1,394,000.
In September 1998, the Company issued 980,000 units at $3.25 per unit. Each
unit consists of one share of common stock and one warrant for each two shares
issued. The warrants with an exercise price of $5.00 per share expire on March
4, 1999. Proceeds to the Company were approximately $3,165,000. Offering costs
of $324,675 were charged to additional paid in capital.
Under the terms of the stock subscription agreement, one of the subscribers
to the offering subscribed for an additional 235,000 units. An additional
$763,750 was deposited into an escrow account representing the aggregate
purchase price of the additional 235,000 units. Under the terms of the escrow
agreement the shares and the shares of common stock underlying the warrants
were to be registered for resale under the Securities Act of 1993 (the "Act")
with the U.S. 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.
The escrow proceeds of $763,750 were deposited into an interest bearing
escrow account together with certificates representing the units to be
purchased. Under the terms of the subscription agreement, the registration
statement was required to be declared effective and the Canadian exemption
order was to be obtained on or before December 31, 1998. The registration
statement has not been declared effective. Accordingly as of December 31, 1998,
the subscriber may elect to either purchase the escrow units or receive a
refund from the escrow account paid with their subscription, plus interest
thereon, and an additional unit for
F-10
<PAGE>
each 10 units purchased in the offering. On February 28, 1999 all the
subscribers elected to receive an additional unit for each 10 units purchased
in the offering and, as a result, an additional 121,500 units are to be issued.
The additional units to be issued have been reflected in the accompanying
financial statements as units to be issued from escrow and the $763,750 to be
received from escrow has been reflected as unit subscriptions receivable. The
subscriber is also entitled to receive an additional unit for each 10 units
previously acquired in the offering in the event that the Company does not
maintain an effective registration statement until such time as the registered
securities may be resold pursuant to Rule 144 promulgated under the Act.
(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.
At December 31, 1998 the Company also has outstanding 398,215 warrants with
an exercise price of $1.75 per share for the first year and $1.96 per share for
the second year. 310,715 of these warrants were issued July 1, 1998 and 87,500
were issued September 4, 1998. The warrants expire two years from the date of
issuance.
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 are exercisable at $1.25 per share anytime after
April 15, 1999 and expire April 15, 2000. The estimated fair value of the
warrants issued of $16,500 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 are exercisable at a price of $3.58 per share
and expire September 4, 2000.
The Company issued warrants to purchase 90,000 shares of common stock to SMS
Operating, LLC as partial consideration for a lease acquisition. 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 $232,202
was capitalized as lease acquisition cost.
(c) Stock Option and Incentive Plan
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. As of December 31, 1998, options to
purchase common stock have been granted to key employees and directors at
exercise prices ranging from $1.25 to $5.00 per share.
Stock option activity for the Plan for the period from inception to December
31, 1998 is as follows:
<TABLE>
<CAPTION>
Weighted
Average
Exercise
Number of Price
Options Per Share
--------- ---------
<S> <C> <C>
BALANCE, JANUARY 26, 1998 (INCEPTION)...................... -- $ --
Granted.................................................. 2,969,365 2.71
Canceled................................................. (204,000) 1.27
---------
BALANCE, DECEMBER 31, 1998................................. 2,765,365 2.82
=========
</TABLE>
F-11
<PAGE>
A summary of the range of exercise prices and the weighted-average
contractual life of outstanding stock options at December 31, 1998, is as
follows:
<TABLE>
<CAPTION>
Number Weighted Weighted Number Weighted
Outstanding Average Average Exercisable Average
Range of December 31, Exercise Remaining December 31, Exercise
Exercise Prices 1998 Price Life (Years) 1998 Price
- --------------- ------------ -------- ------------ ------------ --------
<S> <C> <C> <C> <C> <C>
$ 1.25 800,000 $1.25 9.3 612,500 $1.25
2.50 914,000 2.50 8.4 4,000 2.50
3.25 430,000 3.25 4.6 -- --
3.63 1,215 3.63 4.0 -- --
4.56 12,150 4.56 3.8 -- --
5.00 608,000 5.00 4.2 -- --
--------- -------
1.25 -- 5.00 2,765,365 2.81 7.1 616,500 1.24
========= =======
</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.
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 loss and loss per
share for the period from January 26, 1998 (inception) to December 31, 1998
would have been $6,447,183 and $.57, respectively.
The weighted average fair value of options granted during 1998 was $1.34 per
share. The weighted average remaining contractual life of all options
outstanding at December 31, 1998 was approximately 7.1 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 72%, and a risk-
free interest rate of 5.5%.
(6) 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 member of the
Board of Directors of the Company also serves as a consultant to RIS
International. From April 1, 1998 through June 22, 1998 he served as an officer
of the Company. Since that time he has consulted with the Company and has
received approximately $5,700 as compensation for his services.
During the period from inception to December 31, 1998, a Company for which
the Company's Chairman serves as a director provided administrative services
for the Company for which it received compensation of approximately $16,000. In
addition the Chairman was paid approximately $150,000 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 inception to December 31, 1998. The Director's firm was paid
approximately $192,000 and the Director was paid approximately $22,500 for the
period from inception to December 31, 1998.
F-12
<PAGE>
(7) COMMITMENTS
(a) Employment Agreements
The Company has entered into four-year employment agreements with two
officers, its President and its Chief Financial Officer and Executive Vice
President. Under the terms of the agreement with the President, if employment
is terminated without cause prior to June 1, 1999, the President is entitled to
termination compensation of $2,000,000, or $3,000,000 if he is terminated
without cause after June 1, 1999 but before the expiration of his employment
agreement in June 2002. Under terms of the agreement with the Executive Vice
President and Chief Financial Officer, if employment is terminated without
cause prior to July 1, 1999, the Chief Financial Officer and Executive Vice
President is entitled to termination compensation of $400,000, $750,000 if he
is terminated without cause after July 1, 1999 but before July 1, 2000 and
$1,250,000 if he is terminated without cause thereafter but prior to the
expiration of his employment agreement.
(b) Lease Commitments
The Company entered into an amendment to its office lease agreement in
Denver, Colorado effective June 1, 1998. The amended lease covers 11,524 square
feet for a term of two years and four months. During the term of the lease,
rent is payable in the amount of $172,860 base rent per year. During the seven
months of the lease from June 1, 1998 through December 31, 1998, the Company
paid $100,835 in rent.
The Company also leases office and lodging space in Gillette, Wyoming. The
term of the lease commenced on October 5, 1998 and expires on April 4, 1999.
The lease concerns approximately 9,000 square feet at a yearly rent of
approximately $17,400. In February 1999 a new lease/purchase agreement was
entered into. The term of the lease/purchase agreement commences on April 4,
1999 and expires December 31, 2000. The yearly rent during that term is
approximately $17,400. Under the terms of the purchase option, $1,000 per month
of the rent is deemed to apply to a purchase option on the property. The
purchase option expires January 7, 2001.
(8) SUPPLEMENTAL FINANCIAL DATA-OIL AND GAS ACTIVITIES
Capitalized costs related to oil and gas activities are as follows:
<TABLE>
<CAPTION>
December 31,
1998
--------------
(in thousands)
<S> <C>
Unproved oil and gas properties, at cost................... $4,657
Proved oil and gas properties.............................. 1,359
------
Capitalized costs.......................................... $6,016
======
</TABLE>
Costs incurred in oil and gas activities are as follows:
<TABLE>
<CAPTION>
Period from
January 26, 1998
(inception)
to December 31, 1998
--------------------
(in thousands)
<S> <C>
Unproved property acquisition costs........................ $18,132
Development costs.......................................... 735
Exploration costs.......................................... 1,861
-------
Total costs incurred....................................... $20,728
=======
</TABLE>
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.
F-13
<PAGE>
(9) INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)
Proved Oil and Gas Reserves. 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 historical 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. The estimates were prepared by the independent petroleum engineering
firm of Ryder Scott Company. 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
(inception)
Gas Reserves (Bcf) to December 31, 1998
- ------------------ --------------------
<S> <C>
Proved developed and undeveloped gas reserves:
Beginning of period reserves............................. --
Extensions and discoveries............................... 18.1
----
End of period reserves................................. 18.1
====
Proved developed gas reserves, end of period............... 5.5
====
</TABLE>
Standardize Measure of Discounted Future Net Cash Flows
Future net cash flows presented below are computed using year-end prices and
costs. Future corporate overhead expenses and interest expense have not been
included.
<TABLE>
<CAPTION>
December 31, 1998
--------------------
(in thousands)
<S> <C>
Future cash inflows, net
of production taxes.... $20,250
Future production
costs.................. (6,831)
Future development
costs.................. (1,422)
Future income tax
expenses............... (3,468)
-------
Future net cash flows... 8,529
10% annual discount for
estimated timing of
cash flows............. (2,387)
-------
Standardized measure of
discounted future net
cash flows............. $ 6,142
=======
The principal sources of changes in the standardized measure of discounted
future net cash flows, are as follows:
<CAPTION>
Period from
January 26, 1998
(inception)
to December 31, 1998
--------------------
(in thousands)
<S> <C>
Net change due to
extensions and
discoveries............ $ 8,529
Net change in income
taxes.................. (2,387)
-------
Net changes............. 6,142
Balance at January 26,
1998 (inception)....... --
-------
Balance at December 31,
1998................... $ 6,142
=======
</TABLE>
F-14
<PAGE>
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.
F-15
<PAGE>
PENNACO ENERGY, INC.
BALANCE SHEETS
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
----------- ------------
(unaudited)
(in thousands)
<S> <C> <C>
Current assets:
Cash................................................ $ 4,714 $ 5,623
Accounts receivable................................. 1,628 375
Subscriptions receivable............................ -- 764
Assets held for sale................................ 187 6,932
Drilling deposit.................................... 395 333
Inventory........................................... 691 231
Prepaid expenses and other current assets........... 92 152
------- -------
Total current assets............................ 7,707 14,410
------- -------
Property and equipment, at cost:
Natural gas properties, using the successful efforts
method of accounting............................... 16,533 6,016
Other property and equipment........................ 443 296
------- -------
16,976 6,312
Less accumulated depletion, depreciation and
amortization....................................... (210) (62)
------- -------
Net property and equipment........................ 16,766 6,250
------- -------
Other assets:
Deferred income taxes............................... -- 1,266
Other............................................... 100 100
------- -------
Total other assets.............................. 100 1,366
------- -------
$24,573 $22,026
======= =======
Current liabilities:
Bridge loan payable................................. $ -- $ 5,600
Lease acquisitions payable.......................... -- 619
Accounts payable and accrued liabilities............ 2,431 1,964
Income taxes payable................................ 1,211 --
------- -------
Total current liabilities....................... 3,642 8,183
------- -------
Deferred income taxes................................. 608 --
------- -------
Stockholders' equity:
Common stock, $.001 par value (Authorized 50,000,000
shares; issued and outstanding 15,169,000 at June
30, 1999 and 14,795,000 shares at December 31,
1998).............................................. 15 15
Additional paid-in capital.......................... 18,014 17,641
Retained earnings (deficit)......................... 2,294 (3,813)
------- -------
Total stockholders' equity...................... 20,323 13,843
------- -------
Commitments
$24,573 $22,026
======= =======
</TABLE>
See accompanying notes to financial statements.
F-16
<PAGE>
PENNACO ENERGY, INC.
STATEMENTS OF OPERATIONS
(unaudited)
<TABLE>
<CAPTION>
Period From
Six Months January 26, 1998
ended (inception) to
June 30, 1999 June 30, 1998
------------- ----------------
(in thousands, except per
share amounts)
<S> <C> <C>
Revenue:
Natural gas revenue............................ $ 628 $ --
------- -------
Total revenue................................ 628 --
------- -------
Operating expenses:
Production and lease operating................. 486 --
Production taxes............................... 52 --
Exploration.................................... 108 860
Depletion, depreciation and amortization....... 148 8
General and administrative..................... 2,425 401
------- -------
Total expenses............................... 3,219 1,269
------- -------
Loss from operations............................. (2,591) (1,269)
Interest income................................ 239 20
Interest expense............................... -- (475)
Gain on sale of properties..................... 12,431 --
------- -------
Income (loss) before income taxes................ 10,079 (1,724)
Income tax expense............................... (3,612) --
------- -------
Net income (loss)................................ $ 6,467 $(1,724)
======= =======
Basic earnings (loss) per share.................. $ .43 $ (.19)
======= =======
Diluted earnings (loss) per share................ $ .37 $ (.19)
======= =======
Weighted average common shares outstanding:
Basic.......................................... 15,048 9,133
======= =======
Diluted........................................ 17,369 9,133
======= =======
</TABLE>
See accompanying notes to financial statements.
F-17
<PAGE>
PENNACO ENERGY, INC.
STATEMENT OF STOCKHOLDERS' EQUITY
(unaudited)
Six Months ended June 30, 1999
<TABLE>
<CAPTION>
Common Stock Additional Retained
-------------- Paid-in Earnings
Shares Amount Capital (Deficit) Total
------ ------ ---------- --------- -------
(in thousands)
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1998..... 15,152 $15 $17,641 $(3,813) $13,843
Exercise of warrants............. 25 -- 44 -- 44
Issuance of additional units..... -- -- 360 (360) --
Stock option compensation........ -- -- 11 -- 11
Refund of subscriptions
receivable...................... (14) -- (41) -- (41)
Issuance of units................ 6 -- 20 -- 20
Additional offering costs........ -- -- (21) -- (21)
Net income....................... -- -- -- 6,467 6,467
------ --- ------- ------- -------
Balance at June 30, 1999......... 15,169 $15 $18,014 $ 2,294 $20,323
====== === ======= ======= =======
</TABLE>
F-18
<PAGE>
PENNACO ENERGY, INC.
STATEMENTS OF CASH FLOWS
(unaudited)
<TABLE>
<CAPTION>
Period from
Six Months January 26, 1998
ended (Inception) to
June 30, 1999 June 30, 1998
------------- ----------------
(in thousands)
<S> <C> <C>
Cash flows from operating activities:
Net income (loss)............................. $ 6,467 $(1,724)
Adjustments to reconcile net income (loss) to
net cash used in operating activities:
Gain on sale of properties.................. (12,431) --
Depletion, depreciation and amortization.... 148 8
Compensation relating to common stock and
warrants issued............................ 11 --
Deferred income tax expense................. 1,874 --
Changes in operating assets and liabilities:
Increase in accounts receivable........... (1,253) --
Increase in inventory..................... (460) --
(Increase) decrease in prepaid expenses
and other current assets................. 60 (51)
Increase in other assets.................. -- (67)
Increase in accounts payable and accrued
liabilities.............................. 467 736
Increase in income taxes payable.......... 1,211 --
------- -------
Net cash used in operating activities... (3,906) (1,098)
------- -------
Cash flows from investing activities:
Capital expenditures.......................... (11,546) (12,856)
Proceeds from sale of properties.............. 20,058 --
Drilling deposit, net......................... (62) (250)
Increase (decrease) in lease acquisitions
payable...................................... (619) 55
------- -------
Net cash provided by (used in) investing
activities............................. 7,831 (13,051)
------- -------
Cash flows from financing activities:
Proceeds from issuance of bridge loan......... -- 4,075
Repayment of bridge loan...................... (5,600) --
Proceeds from issuance of common stock, net of
offering costs............................... 723 10,609
Proceeds from exercise of warrants............ 44 --
Proceeds from issuance of units............... 20 --
Additional offering costs..................... (21) --
------- -------
Net cash provided by (used in) financing
activities............................. (4,834) 14,684
------- -------
Net increase (decrease) in cash................. (909) 535
Cash at beginning of period..................... 5,623 --
------- -------
Cash at end of period........................... $ 4,714 $ 535
======= =======
Supplemental disclosures of cash flow
information:
Cash paid for interest........................ $ -- $ --
======= =======
Cash paid for income taxes.................... $ 528 $ --
======= =======
</TABLE>
See accompanying notes to financial statements.
F-19
<PAGE>
PENNACO ENERGY, INC.
June 30, 1999
NOTES TO FINANCIAL STATEMENTS
(unaudited)
(1) 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 Rocky Mountain region of the United States. 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. The Company has oil and gas lease rights in the Powder River Basin in
northeastern Wyoming and southeastern Montana. In April 1999 the Company began
gas production from certain of its gas properties in the South Gillette Area.
As a result, the Company is no longer considered a development stage company.
The accompanying financial statements are unaudited; however, in the opinion
of management, the accompanying financial statements reflect all adjustments,
consisting of normal recurring adjustments, necessary to present fairly the
Company's financial position as of June 30, 1999, and the results of its
operations for the three-month periods ended June 30, 1999 and 1998, the six-
month period ended June 30, 1999 and the period from January 26, 1998
(inception) to June 30, 1998. The results of operations for interim periods are
not indicative of the results of operations for the full fiscal year. The
accounting policies followed by the Company are included in Note 1 to the
Financial Statements for the period from January 26, 1998 (inception) to
December 31, 1998 included elsewhere in this prospectus.
(2) OIL AND GAS ACTIVITIES
The Company follows the successful efforts method of accounting for its
natural gas activities. Accordingly, costs associated with the acquisition,
drilling and equipping of successful exploratory wells are capitalized.
Geological and geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells which would include uneconomical pilot
projects are charged to expense as incurred. Costs of drilling development
wells, both successful and unsuccessful, are capitalized. Upon the sale or
retirement of 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. 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.
Proved gas properties are assessed for impairment on a field-by-field basis.
If the net capitalized costs of proved gas 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 the
value of its estimated undiscounted future net cash flows.
F-20
<PAGE>
(3) 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 $28,000,000. The Company acquired the 50%
leasehold position which was conveyed to CMS in the CMS Transaction for
approximately $7,000,000. The purchase price provided for in the CMS Agreement
was the result of arm's length negotiations between the Company and CMS. The
joint operating agreement between the parties will be 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 affiliates of CMS, for gathering, compression and transportation.
Pursuant to the terms of the CMS Agreement 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") which 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 received $18,600,000 at
the second closing. The remaining $1,800,000 was held in escrow subject to
customary closing adjustments. The CMS Bridge Loan was canceled at the second
closing. Subsequent to the second closing, the Company has received
approximately $1,458,000 from the escrow account leaving approximately $342,000
as of June 30, 1999, pending closing adjustments.
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 580,000 net acres as of June 30, 1999.
(4) STOCKHOLDERS' EQUITY
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 relating
to 6,250 of such units. The units consists of i) 980,000 shares of common stock
and ii) warrants to acquired 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.
Under the terms of the Company's September 1998 Stock Subscription
Agreement, 235,000 additional units were issued under the same terms as above
and placed in an escrow account. Subscription payments of $763,750 were
deposited into an escrow account, together with certificates representing the
units to be
F-21
<PAGE>
purchased, representing the aggregate purchase price of the 235,000 units.
Under the terms of the escrow agreement, the common stock shares and the shares
of common stock underlying the warrants were to be registered under the
Securities Act of 1933 ("the Act") 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 subscription agreement, if the registration statement
was not declared effective and the Canadian exemption order was not obtained on
or before December 31, 1998, the subscriber was entitled to additional rights.
The registration statement was not declared effective by this date.
Accordingly, as of December 31, 1998, the 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.
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. Each Right entitles the registered holder to purchase
from the Company one half of a share of Common Stock at an exercise price of
$20, subject to adjustment. The description and terms of the Rights are set
forth in a Rights Agreement, dated as of February 24, 1999, between the Company
and Harris Trust and Savings Bank, as rights agent, a copy of which has been
filed with the Securities and Exchange Commission as an exhibit to a
Registration Statement on Form 8-A.
During the six months ended June 30, 1999 warrants for the purchase of
25,000 shares of common stock were exercised for $44,000.
F-22
<PAGE>
(5) EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted
earnings per share:
<TABLE>
<CAPTION>
Period From
Six Months January 26, 1998
Ended (inception) to
June 30, 1999 June 30, 1998
------------- ----------------
(in thousands, except per
share amounts)
<S> <C> <C> <C> <C>
Numerator for basic and diluted income
(loss) per share--
Income (loss) available to common
stockholders........................ $ 6,467 $(1,724)
======= =======
Denominator:
Denominator for basic income (loss)
per share --
Weighted average shares.............. 15,048 9,133
Effect of dilutive securities:
Stock warrants..................... 443 --
Stock options...................... 1,878 --
------- -------
Denominator for diluted income (loss)
per share --
Adjusted weighted average shares
diluted............................. 17,369 9,133
======= =======
Basic income (loss) per share.......... $ .43 $ (.19)
======= =======
Diluted income (loss) per share........ $ .37 $ (.19)
======= =======
</TABLE>
Potentially dilutive common shares attributable to outstanding options and
warrants to purchase common shares of 4,501,000, 2,121,000, 97,000 and
2,121,000 were excluded from the calculation of diluted earnings (loss) per
share for the three month periods ended June 30, 1999 and 1998, the six month
period ended June 30, 1999 and the period from January 26, 1998 (inception) to
June 30, 1998, respectively, as their effect was antidilutive.
(6) EVENTS SUBSEQUENT TO JUNE 30, 1999
Bank Facility
On July 23, 1999 the Company entered into a revolving line of credit with
US Bank National Association ("USB"). The Credit Agreement provides for loans
of up to $25,000,000 based upon a borrowing base determined by USB. The
borrowing base has been determined to be $10,000,000 through September 30,
1999. The Credit Agreement includes the following provisions: i) is secured by
mortgages on all of the Company's properties; ii) provides for a revolving
period generally ending on June 30, 2001 after which the loan is to be repaid
based upon a 48 month amortization period; iii) provides that, on a quarterly
basis, the Company's working capital (including unused commitment amount,
minus outstanding letters of credit) not to be less than $0; the Company's
tangible net worth, beginning on or after December 31, 1999, not to be less
than (a) $20,000,000, plus (b) 50% of the Company's cumulative net income for
all periods ending after July 23, 1999, plus (c) 50% of all equity proceeds;
and that, beginning on or after December 31, 1999, the Company will not permit
its fixed charge coverage ratio to be less than 1.0:1.0; and iv) provides for
an interest at either a Libor or prime base rate.
As of August 10, 1999 the Company had no borrowings outstanding under the
revolving credit agreement.
F-23
<PAGE>
Pennaco Energy, Inc.
Report of Independent Petroleum Engineers
A-1
<PAGE>
[LETTERHEAD OF RYDER SCOTT COMPANY PETROLEM ENGINEERS]
September 22, 1999
Pennaco Energy, Inc.
1050 17th Street, Suite 700
Denver, Colorado 80265
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Pennaco Energy, Inc. as of September 1, 1999. The subject properties are
located in the State of Wyoming. The income data were estimated using the
Securities and Exchange Commission (SEC) guidelines-for future price and cost
parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. August 31, 1999 hydrocarbon prices were used
in the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from August 31, 1999 prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated, quantities presented in this
report. The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserve and Income Data
Certain Leasehold and Royalty Interests of
Pennaeo Energy, Inc.
As of September 1, 1999
-----------------------------------------------------
<TABLE>
<CAPTION>
Proved
-------------------------------------------------------------
Developed
----------------------------
Total
Producing Non-Producing Undeveloped Proved
----------- ------------- ----------- -----------
<S> <C> <C> <C> <C>
Net Remaining Reserves
- ----------------------
Gas - MMCF 21,151 21,745 13,191 56,087
Income Data
- -----------
Future Gross Revenue $32,864,617 $34,000,889 $20,683,087 $87,548,593
Deductions $ 7,658,328 $ 8,559,326 $ 6,667,221 $22,884,875
----------- ----------- ----------- -----------
Future Net Income (FNI) $25,206,289 $25,441,563 $14,015,866 $64,663,718
Discounted FNI @ 10% $20,391,923 $19,815,940 $10,404,954 $50,612,817
</TABLE>
<PAGE>
Pennaco Energy, Inc.
September 22, 1999
Page 2
All gas volumes are sales gas expressed in millions of cubic feet (MMCF)
at the official temperature and pressure bases of the areas in which the gas
reserves are located.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs and development costs. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any accumulated
gas production imbalances that may exist. Gas reserves account for 100 percent
of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown in summary form as follows:
Discounted Future Net Income
As of September 1,1999
----------------------------
Discount Rate Total
Percent Proved
------------- ----------
15 $45,250,516
18 $42,436,990
20 $40,706,929
25 $36,826,038
The results shown above are presented for your information and should not be
construed as our estimate of fair market value.
Reserves Included in This Report
- --------------------------------
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. We have evaluated
probable and possible reserves and income for this report. However, at the
request of Pennaco Energy, Inc., the probable and possible tables are not
included in this letter. These data are for Pennaco Energy, Inc.'s information
only and should not be included in reports to the SEC according to the SEC
guidelines.
<PAGE>
Pennaco Energy, Inc.
September 22, 1999
Page 3
Estimates of Reserves
- ---------------------
In general, the reserves included herein were based on a type curve of
472 Coalbed Methane wells in the Powder River Basin in Townships 46, 47, 48 and
49 North, and Ranges 71, 72 and 73 West. The type curve was used to forecast
future production rates for these wells. In some cases, forecast future
production rates varied from the type curve. Because of the limited amount of
performance data currently available for the Pennaco Energy, Inc. wells, the
potential for future reserve revisions, either upward or downward, is
significantly greater than normal.
The reserves included in this report are estimates only and should not
be construed as being exact quantities. They may or may not be actually
recovered, and if recovered, the revenues therefrom and the actual costs related
thereto could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
Future Production Rates
- -----------------------
Initial production rates are based on the current producing rates for
those wells now on production. Test data and other related information were used
to estimate the anticipated initial production rates for those wells or
locations which are not currently producing. If no production decline trend has
been established, future production rates were held constant, or adjusted for
market conditions where appropriate, until a decline in ability to produce was
anticipated. An estimated rate of decline was then applied to depletion of the
reserves. If a decline trend has been established, this trend was used as the
basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Pennaco Energy, Inc.
The future production rates from wells now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
Hydrocardon Prices
- ------------------
Pennaco Energy, Inc. furnished us with a CIG index gas price in effect
at August 31, 1999 of $2.49 per MMBTU. In accordance with SEC guidelines, the
future gas prices used in this report make no allowances for future gas price
increases which may occur as a result of inflation nor do they make any
allowance for seasonal variations in gas prices which may cause future yearly
average gas prices to be somewhat different than August 1, 1999 gas prices. For
gas sold under contract, the contract gas price including fixed and determinable
escalations, exclusive of inflation adjustments, was used until the contract
expires and then was adjusted to the current market price for the area and held
at this adjusted price to
<PAGE>
Pennaco Energy, Inc.
September 22, 1999
Page 4
depletion of the reserves. Product prices which were actually used for each
property reflect adjustment for gravity, quality, local conditions, and/or
distance from market.
Costs
- -----
Operating costs for the leases and wells in this report were supplied
by Pennaco Energy, Inc. and are based on their operating expense reports and
include only those costs directly applicable to the leases or wells. When
applicable, the operating costs include a portion of general and administrative
costs allocated directly to the leases and wells under terms of operating
agreements. Development costs were finished to us by Pennaco Energy, Inc. and
are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The current operating and development costs were
held constant throughout the life of the properties. At the request of Pennaco
Energy, Inc., their estimate of zero abandonment costs after salvage value for
the other onshore properties was used in this report. Ryder Scott has not
performed a detailed study of the abandonment costs nor the salvage value and
makes no warranty for Pennaco Energy, Inc.'s estimate. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
General
- -------
The estimates of reserves presented herein were based upon a detailed
study of the properties in which Pennaco Energy, Inc. owns an interest; however,
we have not made any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which may exist nor
were any costs included for potential liability to restore and clean up damages,
if any, caused by past operating practices. Pennaco Energy, Inc. has informed us
that they have furnished us all of the accounts, records, geological and
engineering data, and reports and other data required for this investigation.
The ownership interests, prices, and other factual data furnished by Pennaco
Energy, Inc. were accepted without independent verification. The estimates
presented in this report were based on data available through September 15,
1999.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
<PAGE>
Pennaco Energy, Inc.
September 22, 1999
Page 5
This report was prepared for the exclusive use of Pennaco Energy, Inc.
The data, work papers, and maps used in this report are available for
examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ J. Stephen Bausch
J. Stephen Bausch, P.E.
Petroleum Engineer
APPROVED:
/s/ Gary Krieger [SEAL OF
Gary Krieger, P.E. J. STEPHEN BAUSCH
Vice President 28010
JSB:ph COLORADO REGISTERED
PROFESSIONAL ENGINEER]
<PAGE>
Pennaco Energy Operations
[PICTURE HERE]
Drilling a Pennaco coal bed methane well in the South Gillette Area with a
mobile truck-mounted rig.
[PICTURE HERE]
This skid-mounted compressor house contains two screw compressors capable of
moving 5 MMcf of gas per day.
[PICTURE HERE]
The low-profile wellhead is connected by buried gathering lines to a central
meter house and compressor.
[PICTURE HERE]
A 250 horsepower screw compressor is designed to move 2.5 MMcf of gas per day.
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
3,500,000 Shares
[Logo of Pennaco Energy, Inc. appears here]
Common Stock
----------------
PROSPECTUS
----------------
Bear, Stearns & Co. Inc.
A.G. Edwards & Sons, Inc.
Howard, Weil, Labouisse, Friedrichs
Incorporated
Hanifen, Imhoff Inc.
October 14, 1999
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
