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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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COMMISSION FILE NUMBER: 000-23185
PETROGLYPH ENERGY, INC.
(Exact name of Registrant as Specified in its Charter)
DELAWARE 74-2826234
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1302 NORTH GRAND
HUTCHINSON, KANSAS 67501
(Address of principal executive offices) (Zip Code)
(316) 665-8500
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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None None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
(Title of Class)
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 31, 2000, the Registrant had outstanding 6,458,333 shares of
Common Stock. The aggregate market value of the Common Stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
Common Stock on March 31, 2000, as reported on the Nasdaq National Market, was
approximately $5,134,348.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2000 Annual
Meeting of Stockholders to be held on May 31, 2000 are incorporated by reference
in Part III of this Form 10-K. Such definitive proxy statement will be filed
with the Securities and Exchange Commission not later than 120 days subsequent
to December 31, 1999.
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TABLE OF CONTENTS
PAGE
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PART I
ITEM 1. Business.................................................................................................1
ITEM 2. Properties...............................................................................................7
ITEM 3. Legal Proceedings.......................................................................................12
ITEM 4. Submission of Matters to a Vote of Security Holders.....................................................13
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters...................................14
ITEM 6. Selected Financial Data.................................................................................15
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................16
ITEM 7A. Quantitative and Qualitative Disclosure about Market Risk...............................................27
ITEM 8. Consolidated Financial Statements and Supplementary Data................................................28
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................28
PART III
ITEM 10. Directors and Executive Officers of the Registrant......................................................28
ITEM 11. Executive Compensation..................................................................................28
ITEM 12. Security Ownership of Certain Beneficial Owners and Management..........................................28
ITEM 13. Certain Relationships and Related Party Transactions....................................................28
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 10-K........................................29
Glossary of Oil and Natural Gas Terms...................................................................32
Signatures..............................................................................................35
Index to Consolidated Financial Statements......................................................................F-1
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PETROGLYPH ENERGY, INC.
1999 ANNUAL REPORT ON FORM 10-K
PART I
As used herein, references to the Company or Petroglyph are to Petroglyph
Energy, Inc. and its predecessors and subsidiaries. Certain terms relating to
the oil and natural gas industry are defined in "Glossary of Oil and Gas Terms."
ITEM 1. BUSINESS
OVERVIEW
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas reserves. The Company
has historically grown oil and natural gas reserves and cash flows through
leasehold acquisitions and the subsequent associated development and exploratory
drilling. The Company's primary activities are focused on its 50,000 gross
(46,600 net) acres in the Uinta Basin in Utah, where it is implementing enhanced
oil recovery projects in the Lower Green River formation of the Greater Monument
Butte Region. The Company anticipates spending approximately $6.0 million in
2000 in connection with these projects. Although the Company presently intends
to focus on exploitation of the Lower Green River formation, the Company
believes that other formations in the Uinta Basin, above and below the Lower
Green River formation, have the potential to be commercially productive. In
addition to its Uinta Basin activities, the Company recently developed a pilot
coalbed methane project (the "Pilot Project") on its 94,100 gross (73,100 net)
acres in the Raton Basin in Colorado. The Pilot Project also includes one test
well associated with the 16 producing wells and six drilled but not completed
wells located outside of the current development area. The six wells can be
utilized to test water production volumes, coal quality and gas production
exclusive of the current production area. Management believes the Pilot Project
will provide sufficient information to qualify the commercial viability of the
area and estimates that approximately four to 11 additional water withdrawal
wells would be required to be drilled to completely dewater the coals included
in the Pilot Project. At year end, the Pilot Project was producing approximately
38,000 barrels of water per day from 16 wells in an attempt to significantly
reduce water levels in the coals, in order for the coal to release the
associated gas in commercial quantities. In addition, the Company has a 100%
working interest in 4,900 net acres in the Helen Gohlke field located within the
Wilcox Trend in the Gulf Coast Region of South Texas. This non-core property is
for sale. The funding of the Company's 2000 development plans will be dependent
upon its ability to realize proceeds from future asset sales, replace its
existing credit facility, raise equity capital and increase its operating cash
flow, whether as a result of successful operations in the Uinta Basin and Raton
Basin or from acquisitions.
The Company had estimated net proved reserves of approximately 18.5 MMBbls
of oil and 43.4 Bcf of natural gas, or an aggregate of 25.7 MMBOE with a PV-10
before income taxes of $151.2 million, as of December 31, 1999. The reserve
estimates utilized an average realized price of $22.37 per barrel for oil and
$1.99 per Mcf for gas. Of the Company's estimated proved reserves, 97% are
located in the Uinta Basin. The Company has not included any reserves from its
Raton Basin development in proved categories, as the Pilot Project is in the
dewatering process. At such time that commercial quantities of Raton Basin gas
are produced, the associated probable reserves will be classified in proved
categories. At December 31, 1999, the Company had a total acreage position of
approximately 149,800 gross (125,000 net) acres and estimates that it had over
1,000 potential drilling locations based on current spacing, none of which are
included in the Company's independent petroleum engineers' estimate of proved
reserves.
The Company's strategy is to increase its reserves, production and cash
flow through (i) the development of its drillsite inventory, (ii) the
exploitation of its existing reserve base, (iii) the control of operations of
its core properties, (iv) the acquisition and sale of property interests, and
(v) the maintenance of a financial position that affords the Company the
financial flexibility to execute its business strategy.
The Company was formed in 1997 for the purpose of becoming the holding
company for Petroglyph Gas Partners, L.P. ("PGP"), pursuant to the terms of an
exchange agreement dated August 22, 1997. PGP was formed in 1993, and grew
primarily through the acquisition of oil and natural gas properties and the
development of such properties. Under the exchange agreement, effective upon
consummation of the Company's initial public offering (the "Offering"), (i) the
limited
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partners of the partnership transferred all of their limited partnership
interests in PGP to the Company in exchange for an aggregate of 2,607,349 shares
of Common Stock and (ii) the stockholders of the general partner of PGP
transferred all of the issued and outstanding stock of the general partner to
the Company in exchange for an aggregate of 225,984 shares of Common Stock.
These transactions are referred to as the "Conversion." As a result of the
Conversion, Petroglyph acquired, directly or indirectly, all the partnership
interests in PGP. In November 1997, Petroglyph completed the Offering of
2,625,000 shares, including 125,000 shares subject to the underwriters'
over-allotment option, of common stock at $12.50 per share, resulting in net
proceeds to the Company of approximately $30.5 million. Approximately $10.0
million of the net proceeds were used to eliminate all outstanding amounts under
the Company's Credit Agreement. The balance of the proceeds were utilized to
develop production and reserves primarily in the Company's core Uinta Basin and
Raton Basin development properties and for other working capital needs.
Effective June 30, 1998, the Company consolidated PGP and its subsidiaries into
the parent company, Petroglyph Energy, Inc. As a result, PGP contributed 100% of
its assets to Petroglyph Energy, Inc., and the partnership was dissolved.
On August 18, 1999, III Exploration Company ("III Exploration") completed
the purchase (the "Purchase") from Robert A. Christensen, a director and
executive officer of the Company, David R. Albin, a director of the Company,
Kenneth A. Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster,
Bruce B. Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural
Gas Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of Common Stock of the Company.
According to the Schedule 13D filed with the Securities and Exchange
Commission by III Exploration on August 30, 1999, III Exploration is controlled
by Intermountain Industries, Inc., an Idaho corporation ("Intermountain"). The
Purchase was effected through a privately negotiated sale between the Sellers
and Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999, with a purchase price of $3.00 per share. The source of funds for
the Purchase came from working capital of Intermountain. As a result of the
Purchase, Intermountain, through its ownership of III Exploration, acquired
approximately 50.4% of the outstanding Common Stock of the Company, (the "Change
of Control").
In connection with the Purchase, Messrs. Albin, Hersh and Christensen
tendered their resignations from the Company's Board of Directors. Mr.
Christensen also resigned as an executive officer, but remained employed by the
Company as an engineer until December 31, 1999. After discussing the
resignations with Intermountain, the remaining members of the Company's Board of
Directors nominated William C. Glynn, Richard Hokin and Eugene C. Thomas, who
are also members of Intermountain's Board of Directors, to fill the vacancies
created on the Board of Directors by the resignations.
On December 28, 1999, the Company sold 1,000,000 shares of Common Stock to
III Exploration in a privately negotiated sale at a purchase price of $2.00 per
share, for aggregate proceeds of $2.0 million (the "Private Placement"). The
Common Stock issued in the Private Placement has not been registered under the
Securities Act of 1933, as amended (the "Securities Act"), and may not be
offered or sold in the United States absent registration or an applicable
exemption from registration requirements. The Company intends to use the
proceeds from the Private Placement for working capital, to finance existing
operations and to finance a portion of the Company's 2000 development plans for
its Uinta Basin and Raton Basin properties. As a result of the Private
Placement, III Exploration's ownership interest in the Company's Common Stock
increased to 59.07% (assuming the exercise of a warrant to purchase 150,000
shares of Common Stock issued in connection with the subordinated notes).
On February 15, 2000, the stockholders of the Company approved the issuance
of 250,000 shares of Series A Convertible Preferred Stock (the "Preferred
Shares") to III Exploration in exchange for certain producing oil and gas
properties primarily located in the Uinta Basin of Utah (the "III Exploration
Purchase"). The stockholders of the Company also approved the issuance of shares
of Common Stock upon the potential conversion of the Preferred Shares.
The Preferred Shares are convertible, beginning two years from the date of
issuance, into shares of Common Stock at a conversion price of $3.50 per share
of Common Stock, based on the preference amount of $10.00 per Preferred Share.
The Company has the option to redeem the Preferred Shares at any time after the
third anniversary of the transaction closing date in whole or in part at a
redemption price of $12.00 per Preferred Share. The Preferred Shares were issued
pursuant to an exemption from the registration requirement under the Securities
Act and will be subject to transfer restrictions imposed by the Securities Act.
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The Company anticipates that the III Exploration Purchase will provide cash
flow of approximately $900,000 during the first year and that proved developed
producing reserves will increase 15%, or 400,000 BOE, from December 31, 1999
levels.
The effective date of the Purchase was November 1, 1999. The
transaction was approved by a special vote of the Company's shareholders on
February 15, 2000 and was closed on February 18, 2000.
The Company is incorporated in the State of Delaware, its principal
executive offices are located at 1302 North Grand, Hutchinson, Kansas 67501 and
its telephone number is (316) 665-8500.
MARKETING ARRANGEMENTS
The price received by the Company for its oil and natural gas production
depends on numerous factors beyond the Company's control, including seasonality,
the condition of the United States economy and state and local economies, the
level and availability of foreign imports of crude oil, political conditions in
other oil-producing countries, the actions of OPEC and domestic government
regulation, legislation and policies. Decreases in the prices of oil and natural
gas could have an adverse effect on the carrying value of the Company's proved
reserves and the Company's revenues, profitability and cash flow.
The Company has historically sold its oil production under long-term
contracts calling for a purchaser posted price or NYMEX price and an adjustment
deduction. These contracts have expired and have been extended or re-negotiated
for shorter time periods. The Company currently markets its crude oil either
month-to-month or on a longer term basis up to six months. During the years
ended December 31, 1999, 1998 and 1997, Company oil sales volumes totaled
approximately 230 MBbls, 262 MBbls and 252 MBbls, respectively, at an average
sales price per Bbl, exclusive of hedging, for each year of $16.53, $9.65 and
$15.52, respectively.
The Company's natural gas produced in the Uinta Basin is sold through a
long-term contract because of the need for firm pipeline transportation. The
contract expires June 2003. The price for the natural gas is based on an Inside
FERC index. The Company's natural gas production in Texas is sold under an
annual, renewable contract. For the years ended December 31, 1999, 1998 and
1997, the Company sold 630 MMcf, 680 MMcf and 537 MMcf, respectively, at an
average price per Mcf, exclusive of hedging, of $2.14, $2.01 and $2.08,
respectively.
TRANSPORTATION COMMITMENTS
In July 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately 37
miles of 10-inch steel pipeline from near Trinidad, Colorado to the Company's
Raton Basin coalbed methane development area approximately six miles southwest
of Walsenburg, Colorado. The pipeline was placed in service in January 1999 with
a delivery capacity of approximately 50 MMcf per day and will provide the
Company primary access to mid-continent markets for its future coalbed methane
production. The Company committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity. The Company's obligations
under the commitment began February 1, 1999 and end January 31, 2009. The
commitment began at a minimum volume of 2,000 Mcf per day and increases by 1,000
Mcf per day after each three-month period, with a maximum commitment of 10,000
Mcf per day. At the end of the first two-year period, the Company has the option
to increase the minimum volume or eliminate the commitment. The cost of
eliminating the commitment is the cost of the pipeline ($6.4 million) less
credit applied for the Company's Raton Basin commercial gas sales up to 16,000
Mcf per day. If paid, the costs of eliminating the commitment could be applied
as a credit to transportation elsewhere on CIG's system. Subject to certain
restrictions, the Company can reduce the minimum monthly commitment by selling
its available pipeline capacity at market rates. For the year ended December 31,
1999, the Company paid $254,000 to CIG under this agreement.
HEDGING ACTIVITIES
The Company has historically used various financial instruments such as
collars, swaps and futures contracts to manage its price risk for a portion of
the Company's crude oil and natural gas production. Monthly settlements on these
financial instruments are typically based on differences between the fixed
prices specified in the instruments and the settlement price
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of certain futures contracts quoted on the NYMEX or certain other indices. The
instruments used by the Company for oil hedges have not contained a contractual
obligation which requires the future physical delivery of the hedged products.
While these hedging arrangements limit the downside risk of price declines, such
arrangements also limit the benefits which may be derived from price increases.
Approximately 162 MBbls of the Company's expected oil production through
December 31, 2000 was subject to collars at December 31, 1999 with NYMEX floor
prices between $17.00 and $20.00 and ceiling prices between $20.00 and $23.00
based on 2000 NYMEX pricing. Additionally, 72 Mbbls of the Company's expected
oil production through June 30, 2000 was subject to a swap at $20.05 based on
2000 NYMEX pricing. Expected 2000 natural gas production totaling 556,000 MMBtu
was hedged at swap prices from $2.01 to $2.2425 per MMBtu. During March 2000,
the Company hedged 42 MBbls of 2000 oil production with NYMEX floor prices
between $22.00 and $23.00 and ceiling prices between $27.00 and $31.70.
The Company monitors oil and gas market activity and compares its actual
performance to the estimates used when entering into hedging arrangements. If
material variations occur from those anticipated when a hedging arrangement is
made, the Company takes actions intended to minimize any risk through
appropriate market actions. The Company attempts to manage its exposure to
counterparty nonperformance risk through the selection of financially
responsible counterparties.
ACQUISITIONS
The Company expects that it will evaluate and may pursue from time to time
acquisitions of oil and gas properties in the Uinta Basin, the Raton Basin and
in other areas that provide investment opportunities for the addition of
production and reserves that meet the Company's selection criteria. The
successful acquisition of producing properties and undeveloped acreage requires
an assessment of recoverable reserves, future oil and natural gas prices,
capital and operating costs, potential environmental and other liabilities and
other factors beyond the Company's control. This assessment is necessarily
inexact and its accuracy is inherently uncertain. In connection with such an
assessment, the Company performs a review of the subject properties it believes
to be generally consistent with industry practices. This review, however, will
not reveal all existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and capabilities. Inspections may not be performed on every well,
and operational and environmental problems are not necessarily observable even
when an inspection is undertaken. The Company may be required to assume
preclosing liabilities, including environmental liabilities, and generally
acquires interests in the properties on an "as is" basis.
COMPETITION
The Company operates in the highly competitive areas of oil and natural gas
exploration, exploitation, acquisition and production with other companies, many
of which have substantially larger financial resources, operations, staffs and
facilities. In seeking to acquire desirable producing properties or new leases
for future exploration and in marketing its oil and natural gas production, the
Company faces competition from other oil and natural gas companies. Such
companies may be able to pay more for productive oil and natural gas properties
and exploratory prospects and to define, evaluate, bid for and purchase a
greater number of properties and prospects than the Company's financial or human
resources permit.
DRILLING AND OPERATING RISKS
Oil and natural gas drilling activities are subject to many risks,
including the risk that no commercially productive reservoirs will be
encountered. There can be no assurance that new wells drilled by the Company
will be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry holes, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, completion, operating
and other costs, including the costs of improved recovery and gathering
facilities. The cost of drilling, completing and operating production and
injection wells is often uncertain. In addition, the Company's use of enhanced
oil recovery techniques requires greater development expenditures than
alternative primary production strategies. In order to accomplish enhanced oil
recovery, the Company expects to drill a number of injection wells to utilize
waterflood technology in the future. The Company's coalbed methane recovery
project may involve significantly more time and capital to achieve commercial
gas production than is currently estimated. Dewatering of the gas producing
coals can take place over a period from three months to several years and
depends heavily on the amount and rates of produced water. Complete dewatering
can occur up to two years after commercial volumes of gas are initially
produced; therefore, the
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ultimate effect of the dewatering operations will not be known for several
years. The Company's waterflood program involves greater risk of mechanical
problems than conventional development programs. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including economic
conditions, title problems, water shortages, weather conditions, compliance with
governmental and tribal requirements and shortages or delays in the delivery of
equipment and services. The Company's future drilling activities may not be
successful and, if unsuccessful, may have a material adverse effect on the
Company's future results of operations and financial condition.
The Company's operations are subject to hazards and risks inherent in
drilling for, producing and transporting oil and natural gas, such as fires,
natural disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others. As protection against
operating hazards, the Company maintains insurance coverage against some, but
not all, potential losses. The Company may elect to self-insure in circumstances
in which 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 third-party insurance could have a
material adverse effect on the Company's business, financial condition and
results of operations.
REGULATION
Regulation of Oil and Natural Gas Production. The Company's oil and natural
gas exploration, production and related operations are subject to extensive
rules and regulations promulgated by federal, state, tribal and local
authorities and agencies. For example, the States of Utah, Colorado, Texas and
others in which the Company may operate require permits for drilling operations,
drilling bonds and reports concerning operations and impose other requirements
relating to the exploration and production of oil and natural gas. Such states
also have statutes or regulations addressing conservation matters, including
provisions for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from wells, and the regulation of
spacing, plugging and abandonment of such wells. Failure to comply with any such
rules and regulations can result in substantial penalties. The regulatory burden
on the oil and gas industry increases the Company's cost of doing business and
affects its profitability. Although the Company believes it is in substantial
compliance with all applicable laws and regulations, because such rules and
regulations are frequently amended or reinterpreted, the Company is unable to
predict the future cost or impact of complying with such laws. Significant
expenditures may be required to comply with governmental laws and regulations
and may have a material adverse effect on the Company's financial condition and
results of operations.
Such regulation requires permits for drilling operations, drilling bonds
and reports concerning operations and imposes other requirements relating to the
exploration and the production of oil and gas. Such state and federal agencies
have statutes or regulations addressing conversation matters, including
provisions for the unitization or pooling of oil and gas properties, the
establishment of maximum rates of production from wells, and the regulation of
spacing, plugging and abandonment of such wells.
Federal Regulation of Natural Gas. The Federal Energy Regulatory Commission
("FERC") regulates interstate natural gas transportation rates and service
conditions, which affect the marketing of natural gas produced by the Company,
as well as the revenues received by the Company for sales of such production.
Since the mid-1980's, FERC has issued a series of orders, culminating in Order
Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the
marketing and transportation of natural gas. Order 636 mandated a fundamental
restructuring of interstate pipeline sales and transportation service, including
the unbundling by interstate pipelines of the sale, transportation, storage and
other components of the city-gate sales services such pipelines previously
performed. One of FERC's purposes in issuing the order was to increase
competition within all phases of the natural gas industry. The United States
Court of Appeals for the District of Columbia Circuit largely upheld Order 636
and the Supreme Court has declined to hear the appeal from that decision.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation service, and has substantially increased
competition and volatility in natural gas markets.
The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to markets. Effective January
1, 1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rates
to inflation, subject to certain conditions and
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limitations. The Company is not able to predict with certainty the effect, if
any, of these regulations on its operations. However, the regulations may
increase transportation costs or reduce well head prices for oil and natural gas
liquids.
Bureau of Indian Affairs. A substantial part of the Company's producing
properties in the Uinta Basin are operated under oil and natural gas leases
issued by the Ute Indian Tribe, which is under the supervision of the Bureau of
Indian Affairs. These activities must comply with rules and orders that regulate
aspects of the oil and natural gas industry, including drilling and operating on
leased land and the calculation and payment of royalties to the federal
government or the Ute Indian Tribe. Operations on Ute Indian tribal lands must
also comply with significant restrictive requirements of the governing body of
the Ute Indians. For example, such leases typically require the operator to
obtain at least an environmental assessment based on planned drilling activity.
To the extent an operator wishes to drill additional wells, it will be required
to obtain a new assessment. In addition, leases with the Ute Indian Tribe
require that the operator agree to protect certain archeological and ancestral
ruins located on the acreage.
Environmental Matters. The Company's operations and properties are subject
to extensive and changing federal, state and local laws and regulations relating
to environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to safety and health. The recent trend in environmental legislation and
regulation generally is toward stricter standards, and this trend will likely
continue. These laws and regulations may (i) require the acquisition of a permit
or other authorization before construction or drilling commences and for certain
other activities; (ii) limit or prohibit construction, drilling and other
activities on certain lands lying within wilderness and other protected areas;
and (iii) impose substantial liabilities for pollution resulting from the
Company's operations. The permits required for various of the Company's
operations are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce their
regulations, and violations are subject to fines or injunctions, or both. In the
opinion of management, the Company is in substantial compliance with current
applicable environmental laws and regulations, and the Company has no material
commitments for capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws and
regulations or in interpretations thereof could have a significant impact on the
Company, as well as the oil and natural gas industry in general.
The Comprehensive Environmental, Response, Compensation, and Liability Act
("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. It is
not uncommon for the neighboring land owners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. The Federal Resource Conservation and
Recovery Act ("RCRA") and comparable state statutes govern the disposal of
"solid waste" and "hazardous waste" and authorize the imposition of substantial
fines and penalties for noncompliance. Although CERCLA currently excludes
petroleum from its definition of "hazardous substance," state laws affecting the
Company's operations impose clean-up liability relating to petroleum and
petroleum related products. In addition, although RCRA classifies certain oil
field wastes as "non-hazardous," such exploration and production wastes could be
reclassified as hazardous wastes thereby making such wastes subject to more
stringent handling and disposal requirements.
The Company has acquired leasehold interests in numerous properties that
for many years have produced oil and natural gas. Although the previous owners
of these interests may have used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties. In addition, some of the
Company's properties may be operated in the future by third parties over whom
the Company has no control. Notwithstanding the Company's lack of control over
properties operated by others, the failure of the operator to comply with
applicable environmental regulations may, in certain circumstances, adversely
impact the Company.
NEPA. The National Environmental Policy Act ("NEPA") is applicable to many
of the Company's activities and operations. NEPA is a broad procedural statute
intended to ensure that federal agencies consider the environmental impact of
their actions by requiring such agencies to prepare environmental impact
statements ("EIS") in connection with all federal activities that significantly
affect the environment. Although NEPA is a procedural statute only applicable to
the federal government, a large portion of the Company's Uinta Basin acreage is
located either on federal land or Ute tribal land jointly administered with the
federal government. The Bureau of Land Management's issuance of drilling permits
and the Secretary of the Interior's approval of plans of operation and lease
agreements all constitute federal action within the scope of NEPA. Consequently,
unless the responsible agency determines that the Company's drilling activities
will not materially impact the
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environment, the responsible agency will be required to prepare an EIS in
conjunction with the issuance of any permit or approval.
ESA. The Endangered Species Act ("ESA") seeks to ensure that activities do
not jeopardize endangered or threatened animal, fish and plant species, nor
destroy or modify the critical habitat of such species. Under ESA, exploration
and production operations, as well as actions by federal agencies, may not
significantly impair or jeopardize the species or its habitat. ESA provides for
criminal penalties for willful violations of the Act. Other statutes that
provide protection to animal and plant species and that may apply to the
Company's operations include, but are not necessarily limited to, the Fish and
Wildlife Coordination Act, the Fishery Conservation and Management Act, the
Migratory Bird Treaty Act and the National Historic Preservation Act. Although
the Company believes that its operations are in substantial compliance with such
statutes, any change in these statutes or any reclassification of a species as
endangered could subject the Company to significant expense to modify its
operations or could force the Company to discontinue certain operations
altogether.
ABANDONMENT COSTS
The Company is responsible for payment of its working interest share of
plugging and abandonment costs on its oil and natural gas properties. Based on
its experience, the Company anticipates that the ultimate aggregate salvage
value of lease and well equipment located on its properties will exceed the
costs of abandoning such properties. There can be no assurance, however, that
the Company will be successful in avoiding additional expenses in connection
with the abandonment of any of its properties. In addition, abandonment costs
and their timing may change due to many factors including actual production
results, inflation rates and changes in environmental laws and regulations.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. The Company's Credit Agreement is
secured by substantially all the Company's oil and natural gas properties.
Presently, the Company keeps in force its leaseholds for 20% of its net acreage
by virtue of production on that acreage in paying quantities. The remaining
acreage is held by lease rentals and similar provisions and requires established
production in paying quantities prior to expiration of various time periods to
avoid lease termination.
OTHER FACILITIES
The Company currently leases approximately 8,000 square feet of office
space in Hutchinson, Kansas, where its principal offices are located. The lease
has a remaining term of approximately one year, expiring May 2001, at which time
the Company has the option to renew the lease or acquire the property. The
Company also leases a 3,300 square foot office building through Hutch Realty
LLC, an affiliate of the Company.
EMPLOYEES
As of December 31, 1999, the Company had 37 full-time employees, none of
whom is represented by any labor union. Included in the total were 13 corporate
employees located in the Company's office in Hutchinson, Kansas. The Company
considers its relations with its employees to be good.
ITEM 2. PROPERTIES
GENERAL
The Company's primary producing properties are located in the Uinta Basin
in Utah, where it is implementing enhanced oil recovery projects in the Lower
Green River formation of the Greater Monument Butte Region. The Company's
enhanced oil recovery development strategy utilizes waterflood techniques
designed to rebuild and maintain reservoir pressure. Waterflooding involves the
injection of water into a reservoir forcing oil through the formation toward
producing wells within
7
10
the development area and driving free natural gas in the reservoir back into oil
solution, creating greater pressure within the reservoir and making oil more
mobile.
Since July 1997, the Company has acquired 73,100 net acres in the Raton
Basin in Colorado where it has developed a pilot area consisting of 17 completed
wells for the production of coalbed methane gas. Coalbed methane gas production
is similar to traditional natural gas production in terms of the physical
producing facilities and the product produced. Coalbed methane wells are drilled
and completed in a manner similar to traditional natural gas wells, but
development relies upon the release of coalbed methane as pressure is reduced in
the reservoir due to water removal. During drilling and completion operations in
of the Pilot Project, the Company determined that significant volumes of water
would be required to be removed to reduce reservoir pressures to a level
conducive to methane gas production.
During 1999, the Company produced a total of approximately 12 million
barrels of water and continuously produced measurable volumes of natural gas
along with the water from the wells in the Pilot Project. These measurable gas
volumes are supplying a portion of the fuel gas required for dewatering
operations in the pilot area, but gas volumes are not currently large enough to
be sold to markets via the gas pipelines connected to the pilot area.
The Company initially estimated that it would take approximately six to 12
months to sufficiently dewater the coal gas reservoirs and bring about
commercial volumes of gas production from the Pilot Project. However, greater
than anticipated water production from wells in the pilot area has significantly
extended the estimated amount of time and capital necessary to achieve gas
production in commercial quantities. As a result of the higher than anticipated
water volumes, the Company conducted a series of specialized reservoir tests
during December 1999. These tests were designed, among other things, to further
estimate additional time required to dewater the coal gas reservoirs in the
pilot area at the current water withdrawal rate. As a result of this engineering
evaluation, the Company determined that approximately four to 11 additional
water withdrawal wells would be required to be drilled at a cost ranging from
$1.0 million to $3.0 million in the pilot area to remove additional water to
enable the coal formations to begin to produce natural gas in commercial
quantities.
Based on its experience to date, the Company believes that the coal gas
resources within the pilot area, and more generally within the majority of its
entire acreage position in the Raton Basin, contain commercial quantities of
coalbed methane gas. During 2000, and subject to securing the necessary
financing, the Company plans to continue developing its Raton Basin coal gas
resource. However, due to the uncertainties inherent in estimating quantities of
natural gas reserves and the timing of the dewatering process, the Company is
unable to predict whether its development activities will meet its expectations.
The Company has an operating working interest and owns 4,900 net acres in
the Helen Gohlke field located within the Wilcox Trend in the Gulf Coast Region
of South Texas. The Company is making this non-core property available for sale.
8
11
OIL AND NATURAL GAS RESERVES
The following table summarizes the estimates of the Company's estimated
historical net proved reserves of oil and natural gas as of December 31, 1999,
1998 and 1997:
AS OF DECEMBER 31,
--------------------------------------------------------------
1999 1998 1997
------------------ ----------------- -----------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------ ------- ------ ------- ------
Proved developed:
Utah .................. 10,366 21,309 5,260 10,686 4,620 9,202
Other ................. 93 3,011 60 1,984 122 1,637
------ ------ ----- ------ ----- ------
Total ............ 10,459 24,320 5,320 12,670 4,742 10,839
------ ------ ----- ------ ----- ------
Proved undeveloped:
Utah .................. 8,030 17,743 1,107 2,822 4,714 9,856
Other ................. -- 1,369 -- -- -- --
------ ------ ----- ------ ----- ------
Total ............ 8,030 19,112 1,107 2,822 4,714 9,856
------ ------ ----- ------ ----- ------
Total proved ..... 18,489 43,432 6,427 15,492 9,456 20,695
====== ====== ===== ====== ===== ======
The following table sets forth the future net cash flows from the Company's
estimated proved reserves:
AS OF DECEMBER 31,
----------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
Future net cash flow before income taxes:
Utah ................................................ $338,179 $ 49,992 $ 96,768
Other ............................................... 8,205 2,368 2,469
-------- -------- --------
Total .......................................... $346,384 $ 52,360 $ 99,237
======== ======== ========
Future net cash flow before income taxes, discounted at 10%:
Utah ................................................ $146,971 $ 26,581 $ 41,631
Other ............................................... 4,312 1,727 1,798
-------- -------- --------
Total .......................................... $151,283 $ 28,308 $ 43,429
======== ======== ========
The reserve estimates for 1999, 1998 and 1997 were prepared by Lee Keeling
and Associates Inc., the Company's independent petroleum engineers.
The Company has not included any reserves from its Raton Basin development
in proved categories, as the pilot area is in the dewatering process. At such
time that commercial quantities of Raton Basin gas are realized, the associated
probable reserves will be classified in proved categories.
In accordance with applicable requirements of the Commission, estimates of
the Company's proved reserves and future net revenues are made using sales
prices in effect as of the date of such reserve estimates and are held constant
throughout the life of the properties (except to the extent a contract
specifically provides for escalation). Estimated quantities of proved reserves
and future net revenues therefrom are affected by oil and natural gas prices,
which have fluctuated widely in recent years. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond the control of the producer. The reserve data set
forth in this report are only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and natural gas 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. In addition, the Company's use of enhanced oil
recovery techniques requires greater development expenditures than traditional
development strategies. The Company expects to drill a number of wells and
employ waterflood technology to produce them in the future. The Company's
waterflood program involves greater risk of mechanical problems than
conventional development programs. As a result, estimates of different
engineers, including those used by the Company, may vary. In addition, estimates
of reserves are subject to revision based upon actual production, results of
future development and exploration activities, prevailing natural gas and oil
prices, operating costs
9
12
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.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1999 1998 1997
------------ ----------- ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Exploratory:
Oil ............................ -- -- 1 1.0 2 2.0
Natural gas .................... -- -- 5 5.0 2 1.0
Nonproductive .................. 1 1.0 -- -- -- --
-- --- --- --- -- ----
Total ................... 1 1.0 6 6.0 4 3.0
== === == ==== == ====
Development:
Oil ............................ -- -- 26 13.0 52 26.0
Natural gas .................... 2 1.0 20 19.0 -- --
Nonproductive .................. -- -- 2 2.0 -- --
-- --- -- ---- -- ----
Total ................... 2 1.0 48 34.0 52 26.0
== === == ==== == ====
Total:
Productive ..................... 2 1.0 52 38.0 56 29.0
Nonproductive .................. 1 1.0 2 2.0 -- --
-- --- -- ---- -- ----
Total ................... 3 2.0 54 40.0 56 29.0
== === == ==== == ====
Based on the Company's drilling results to date, the Company believes that
the nature of the geology in the Lower Green River formation in the Greater
Monument Butte Region is characterized by the presence of hydrocarbons
throughout the region and, as a consequence, the distinction between exploratory
and development wells in this region is not as important as it is in other oil
and natural gas producing areas.
The Company does not own any drilling rigs; therefore, all of its drilling
activities are conducted by independent contractors under standard drilling
contracts.
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership interest as of
December 31, 1999 in productive oil and natural gas wells in the development
areas indicated.
OIL NATURAL GAS TOTAL
--------------- --------------- ---------------
AREA GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Utah:
Antelope Creek Field ........ 107 107.0 -- -- 107 107.0
Duchesne Field .............. 5 5.0 1 1.0 6 6.0
Natural Buttes Extension .... -- -- 2 1.5 2 1.5
----- ----- ----- ----- ----- -----
Total .................. 112 112.0 3 2.5 115 114.5
Colorado* ..................... -- -- 17 17.0 17 17.0
Other ......................... 3 3.0 5 3.0 8 6.0
----- ----- ----- ----- ----- -----
Total .................. 115 115.0 25 22.5 140 137.5
===== ===== ===== ===== ===== =====
* In dewatering phase of operation.
10
13
In addition, as of December 31, 1999, the Company had 37 gross (37 net)
active water injection wells on its acreage in the Uinta Basin.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth the production volumes, average sales prices
and average production costs associated with the Company's sale of oil and
natural gas for the period indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
Net production:
Oil (Bbls) .......................................................... 261,817 251,631 229,651
Natural gas (Mcf) ................................................... 679,992 537,466 630,186
Oil equivalent (BOE) ................................................ 375,149 341,209 334,682
Average sales price (1):
Oil (per Bbl):
Utah (2) .......................................................... $ 15.85 $ 11.01 $ 14.37
Other ............................................................. 17.43 12.95 18.94
Weighted average (3) .............................................. 15.90 11.12 14.84
Natural gas (per Mcf) (4):
Utah .............................................................. $ 1.84 $ 2.12 $ 1.91
Other ............................................................. 1.84 1.75 2.37
Weighted average .................................................. 1.84 2.01 1.99
Average lease operating expenses including production and property
taxes (per BOE):
Utah .............................................................. $ 9.58 $ 5.06 $ 3.67
Other ............................................................. 11.25 10.02 15.08
Weighted average .................................................. 9.90 5.72 5.09
- ----------------
(1) Before deduction of property taxes.
(2) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average Uinta Basin sales price per Bbl of
oil received by the Company was $16.50, $9.44 and $15.12 for the years
ended December 31, 1999, 1998 and 1997, respectively.
(3) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average sales price per Bbl of oil was
$16.53, $9.65 and $15.52 for the years ended December 31, 1999, 1998 and
1997, respectively.
(4) Excluding the effects of hedging transactions, the weighted average sales
price per Mcf of natural gas was $2.14, $2.01 and $2.08 for the years ended
December 1999, 1998 and 1997, respectively.
11
14
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth the costs incurred by the Company in its
development, exploration and acquisition activities during the periods
indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
Acquisition costs:
Unproved properties ....... $ 1,320,105 $ 7,141,142 $ 1,721,636
Proved properties ......... 7,120,952 42,533 147,387
Development costs ........... 1,038,257 10,123,616 10,003,468
Exploration costs ........... 38,640 192,526 --
Improved recovery costs ..... -- -- 895,317
----------- ----------- -----------
Total ................... $ 9,517,954 $17,499,817 $12,767,808
=========== =========== ===========
ACREAGE
The following table sets forth, as of December 31, 1999, the gross and net
acres of developed and undeveloped oil and natural gas leases which the Company
holds or has the right to acquire. Undeveloped acreage includes leased acres on
which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and natural gas, regardless of
whether or not such acreage contains proved reserves.
DEVELOPED UNDEVELOPED TOTAL
------------------- ------------------- -------------------
AREA GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -------
Utah:
Antelope Creek Field ......... 6,560 6,560 14,457 12,892 21,017 19,452
Duchesne Field ............... 1,400 1,067 11,935 10,565 13,335 11,632
Natural Buttes Extension ..... 360 360 15,336 15,132 15,696 15,492
------- ------- ------- ------- ------- -------
Total ...................... 8,320 7,987 41,728 38,589 50,048 46,576
------- ------- ------- ------- ------- -------
Colorado ....................... 3,072 3,072 90,988 70,025 94,060 73,097
Other .......................... 5,210 4,900 441 441 5,651 5,341
------- ------- ------- ------- ------- -------
Total ...................... 16,602 15,959 133,157 109,055 149,759 125,014
======= ======= ======= ======= ======= =======
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in certain litigation and
governmental proceedings arising in the normal course of business. Company
management and legal counsel do not believe that ultimate resolution of these
claims will have a material adverse effect on the Company's financial position
or results of operations.
Mark Lively v. Petroglyph Operating Company, Inc.
The Company is a defendant in a lawsuit filed on or about December 22,
1999, by Mark Lively ("Lively"), wherein Lively seeks an order from the court
evicting the Company from a portion of Lively's property that contains four of
the Company's Raton Basin coalbed methane gas wells. Lively also seeks to
recover attorney fees and costs incurred in connection with the lawsuit. The
Company is vigorously defending itself and has requested that its costs incurred
in connection with the lawsuit be paid by Lively. The Company does not believe
that the resolution of this matter would have a material adverse effect on
the Company's financial position or results of operations.
12
15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the Company's security holders during
the fourth quarter of 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this report.
The following table sets forth certain information concerning the executive
officers of the Company as of December 31, 1999:
NAME AGE POSITION
- ---- --- --------
Robert C. Murdock ............................ 42 President, Chief Executive Officer and Chairman of
the Board
S. "Ken" Smith ............................... 57 Executive Vice President, Chief Operating Officer and Secretary
Tim A. Lucas ................................. 35 Vice President, Chief Financial Officer and Treasurer
Set forth below is a description of the backgrounds of each executive
officer of the Company, including employment history for at least the last five
years.
Robert C. Murdock has served as President, Chief Executive Officer and
Chairman of the Board of the Company since its inception in April 1993. From
1985 until the formation of the Company, Mr. Murdock was President of GasTrak
Holdings, Inc., a natural gas gathering and marketing company. From 1982 to
1985, Mr. Murdock held various staff and management positions with Panhandle
Eastern Pipe Line Company, where he was responsible for the development and
implementation of special marketing programs, natural gas supply acquisitions,
natural gas supply planning and forecasting, and for developing computer
management systems for natural gas contract administration.
S. "Ken" Smith has served as Executive Vice President and Chief Operating
Officer of the Company since January 1994 and Secretary of the Company since
April 1997, and was responsible for accounting, financial planning and budgeting
through December 1995. Currently Mr. Smith serves as President of Petroglyph
Operating Company. From June 1992 through 1993, Mr. Smith was a principal and
treasurer of TKS Consulting, where he performed economic and financial analysis,
as well as served as an expert witness in state and federal court and regulatory
agency hearings. From February 1986 to May 1992, Mr. Smith served as Vice
President of Finance for Gage Corporation, a natural gas development and
processing company. From August 1982 to July 1985, Mr. Smith was Treasurer and
Controller for Sparkman Energy Corporation. Mr. Smith is a Certified Public
Accountant and is a member of the American Institute of Certified Public
Accountants and the Texas and Oklahoma Societies of Certified Public
Accountants.
Tim A. Lucas has served as Vice President, Chief Financial Officer and
Treasurer of the Company since July 1997. From August 1994 until joining the
Company in 1997, Mr. Lucas served as Senior Financial Manager for Cross Oil
Refining & Marketing, Inc., where he was responsible for all financial matters
of the Company. From June 1989 to July 1994, Mr. Lucas worked in the audit
division of Arthur Andersen LLP. Mr. Lucas received his BBA in Accounting from
the University of Oklahoma and is a Certified Public Accountant and a member of
the American Institute of Certified Public Accountants and the Oklahoma Society
of Certified Public Accountants.
13
16
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock has been publicly traded on the Nasdaq National
Market (Nasdaq) under the symbol "PGEI" since the Company's initial public
offering effective October 20, 1997.
The following table sets forth the high and low closing sales prices for
Petroglyph common stock as reported by Nasdaq for the periods indicated.
High Low
------- -------
1998:
Quarter Ended March 31 $ 9.75 $ 7.375
Quarter Ended June 30 8.625 7.00
Quarter Ended September 30 7.75 5.125
Quarter Ended December 31 6.125 2.875
1999:
Quarter Ended March 31 4.00 1.563
Quarter Ended June 30 3.25 1.625
Quarter Ended September 30 3.988 2.125
Quarter Ended December 31 3.50 1.406
2000:
Quarter Ended March 31 2.688 1.50
As of March 31, 2000, the Company estimates that there were more than 1,000
stockholders (including brokerage firms and other nominees) of the Company's
common stock.
No dividends have been declared or paid on the Company's common stock to
date. For the foreseeable future, the Company intends to retain any earnings for
the development of its business.
14
17
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's consolidated financial
statements and related notes included in "Item 8. Consolidated Financial
Statements and Supplementary Data."
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
(in thousands, except per share amounts and operating data)
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil sales ...................................... $ 3,652 $ 2,912 $ 3,735 $ 4,459 $ 3,217
Natural gas sales .............................. 1,160 1,366 1,070 999 1,016
Other .......................................... 230 190 61 -- 36
-------- -------- -------- -------- --------
Total operating revenues .................. 5,042 4,468 4,866 5,458 4,269
-------- -------- -------- -------- --------
Operating expenses:
Lease operating ................................ 2,953 1,927 1,560 2,369 2,260
Production taxes ............................... 359 218 179 249 188
Exploration costs .............................. 39 193 -- 69 376
Depreciation, depletion and amortization ....... 1,673 1,866 1,852 2,806 2,302
Impairments .................................... -- 4,848 -- -- 109
General and administrative ..................... 2,024 2,129 1,300 902 1,064
-------- -------- -------- -------- --------
Total operating expenses .................. 7,048 11,181 4,891 6,395 6,299
-------- -------- -------- -------- --------
Operating loss ................................... (2,006) (6,713) (25) (937) (2,030)
Other income (expenses):
Interest income (expense), net ................. (679) 407 114 40 (216)
Gain (loss) on sales of property and
equipment, net ............................ 840 59 12 1,384 (138)
-------- -------- -------- -------- --------
Net income (loss) before income taxes ............ (1,845) (6,247) 101 487 (2,384)
Income tax benefit (expense) (1) ................. 390 2,062 (2,514) (190) --
-------- -------- -------- -------- --------
Net income (loss) before change in accounting
principle ...................................... $ (1,455) $ (4,185) $ (2,413) $ 297 $ (2,384)
======== ======== ======== ======== ========
Supplemental earnings (loss) per
common share (2) before change in accounting
principles ..................................... $ (.27) $ (.77) $ (.73) $ .11 $ (.84)
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in):
Operating activities ........................... $ (2,069) $ (1,467) $ 1,633 $ 4,129 $ 347
Investing activities ........................... (8,610) (20,535) (15,514) 303 (9,580)
Financing activities ........................... 10,414 7,331 28,982 (3,930) 10,049
OTHER FINANCIAL DATA:
Capital expenditures ............................. $ 10,109 $ 20,623 $ 16,260 $ 8,665 $ 10,443
Adjusted EBITDA (3) .............................. 546 253 1,839 3,322 619
Operating cash flow (4) .......................... (770) 601 1,896 2,024 608
BALANCE SHEET DATA:
Cash and cash equivalents ........................ $ 1,742 $ 2,008 $ 16,679 $ 1,578 $ 1,075
Working capital .................................. 1,968 1,952 14,873 (541) 1,133
Total assets ..................................... 52,947 46,035 46,714 17,470 17,598
Total long-term debt ............................. 14,953 7,500 -- 52 3,900
Total stockholders' equity ....................... 35,816 35,312 39,498 12,695 12,207
- -----------------
(1) Tax information for 1996 is shown as pro forma to reflect income tax
expense as if Partnership income were subject to federal income tax.
15
18
(2) Weighted average common shares outstanding used in the calculation of
earnings (loss) per common share for each of the five years ended December
31, 1999 were 5,469,292 for 1999, 5,458,333 for 1998, 3,326,826 for 1997
and 2,833,333 (pro forma) shares for 1996 and 1995.
(3) Adjusted EBITDA (as used herein) is calculated by adding interest, income
taxes, depreciation, depletion and amortization, impairments and
exploration costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. The Company did not
incur impairment expense for any period reported except for $4,848,000 for
the year ended December 31, 1998 and $109,000 for the year ended December
31, 1995. Exploration costs were $39,000, $193,000, zero, $69,000 and
$376,000 for each of the years ended December 31, 1999, 1998, 1997, 1996,
and 1995, respectively. Adjusted EBITDA is presented not as a measure of
operating results, but rather as a measure of the Company's operating
performance and ability to service debt. Adjusted EBITDA is not intended to
represent cash flows for the period; nor has it been presented as an
alternative to net income (loss) or operating income (loss); nor as an
indicator of the Company's financial or operating performance. Management
believes that Adjusted EBITDA provides supplemental information about the
Company's ability to meet its future requirements for debt service, capital
expenditures and working capital. Management monitors trends in Adjusted
EBITDA, as well as the trends in revenues and net income (loss), to aid it
in managing its business. Adjusted EBITDA should not be considered in
isolation, as a substitute for measures of performance prepared in
accordance with generally accepted accounting principles or as being
comparable to other similarly titled measures of other companies, which are
not necessarily calculated in the same manner.
(4) Operating cash flow is defined as net income plus adjustments to net income
to arrive at net cash provided by operating activities before changes in
working capital.
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following table sets forth certain operating data of the Company for
the periods presented:
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
PRODUCTION DATA:
Oil (Bbls) .................................. 229,651 261,817 251,631
Natural Gas (Mcf) ........................... 630,186 679,992 537,466
Total (BOE) ............................... 334,682 375,149 341,209
AVERAGE SALES PRICE PER UNIT(1):
Oil (per Bbl)(2) ............................ $ 15.90 $ 11.12 $ 14.84
Natural Gas (per Mcf) (3) ................... 1.84 2.01 1.99
BOE ......................................... 14.38 11.40 14.08
COSTS PER BOE:
Lease operating expense ..................... $ 8.82 $ 5.14 $ 4.57
Production and property taxes ............... 1.07 0.58 .52
General and administrative .................. 6.05 5.67 3.81
Depreciation, depletion and amortization .... 5.00 4.97 5.43
Average finding costs(4) .................... 3.08 0.85 3.00
- ---------------
(1) Before deduction of production taxes.
(2) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average sales price per Bbl of oil was
$16.53, $9.65 and $15.52 for the years ended December 31, 1999, 1998 and
1997, respectively.
(3) Excluding the effects of hedging transactions, the weighted average sales
prices per Mcf of natural gas was $2.14, $2.01 and $2.08 for the years
ended December 31, 1999, 1998 and 1997, respectively.
(4) The calculation of average finding cost for the year ended December 31,
1999 includes a change in future development costs of $38.6 million.
Average finding cost excluding this amount was $0.54 for 1999. The
calculation of average finding cost for the year ended December 31, 1998
includes a reduction in future development costs of $13.3 million as a
result of a decline in the Company's proved undeveloped reserves due to low
year-end oil prices. 1998 average finding cost excluding future development
cost is not meaningful. The calculation of average finding cost for the
year ended December 31, 1997 includes a change in future development costs
of
16
19
$2.7 million. Average finding cost excluding this amount was $2.37 for the
year ended December 31, 1997.
The Company uses the successful efforts method of accounting for its oil
and natural gas activities. Costs to acquire mineral interests in oil and
natural gas properties, to drill and equip exploratory wells that result in
proved reserves, and to drill and equip development wells are capitalized. Costs
to drill exploratory wells that do not result in proved reserves, geological,
geophysical and seismic costs, and costs of carrying and retaining properties
that do not contain proved reserves are expensed. Costs of significant
nonproducing properties, wells in the process of being drilled and development
projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined.
The Company's predecessor was classified as a partnership for federal
income tax purposes. Therefore, no income taxes were paid or provided for by the
Company prior to the Conversion. Future tax amounts, if any, will be dependent
upon several factors, including but not limited to the Company's results of
operations.
RESULTS OF OPERATIONS
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
OPERATING REVENUES
Oil revenues increased by $740,000 (25%) to $3,652,000 for the year ended
December 31, 1999 as compared to $2,912,000 for 1998 as a result of a $4.73
(43%) increase in average realized oil sales prices from $11.12 per Bbl in 1998
to $15.90 in 1999. The average oil sales price of $15.90 per Bbl includes the
effects of crude oil hedge losses of $144,000 in 1999 compared to crude oil
hedge gains of $386,000 in the prior year. The Company's average oil sales price
for the year ended December 31, 1999, excluding the effects of the hedge loss,
was $16.53 per Bbl.
Natural gas revenues decreased by $206,000 (15%) to $1,160,000 for the year
ended December 31, 1999 as compared to $1,366,000 for 1998. The average realized
gas price for 1999 was $1.84 per Mcf, including a hedge loss of $0.30 per Mcf,
compared to $2.01 per Mcf in 1998. Gas sales volumes for 1999 declined 49,800
Mcf (7%) to 630,200 Mcf, compared to 1998 sales volumes of 680,000 Mcf.
OPERATING EXPENSES
Lease operating expenses increased $1,026,000 (53%) to $2,953,000 for the
year ended December 31, 1999 as compared to $1,927,000 for the year ended
December 31, 1998. Lease operating costs incurred in 1999 which were not
comparable to the previous year included $863,000 attributable to that portion
of the Antelope Creek property purchased in 1999, $206,000 for compressor
rentals and $254,000 in commitment charges to CIG. Absent these three cost
items, lease operating expenses declined $297,000 (15%) between periods.
Depreciation, depletion and amortization expense declined $193,000 (10%) to
$1,673,000 for the year ended December 31, 1999 as compared to $1,866,000 for
1998. This expense, which is based on production volumes, reflects an 11%
decline in production between the two periods.
Exploration costs decreased to $39,000 for the year ended December 31, 1999
compared to $193,000 for the year ended December 31, 1998. One exploratory well
was plugged and abandoned on the Company's Texas acreage in 1999, while two
wells, one in Texas and one in the Raton Basin were unsuccessful in 1998.
General and administrative expenses decreased by $105,000 (5%) to
$2,024,000 for the year ended December 31, 1999. This amount included a
one-time, non-cash charge of $176,000 associated with the resignation of an
executive officer of the Company. Additionally, the Company incurred
approximately $108,000 in severance charges associated with a planned reduction
in general and administrative expenses. Absent these items, general and
administrative costs decreased
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$389,000 (18%) to $1,635,000 in 1999 as compared to $2,129,000 in 1998, as a
result of cost reduction measures implemented in the first quarter of 1999.
OTHER INCOME (EXPENSES)
Net interest expense for the year ended December 31, 1999 was $679,000
compared to net interest income of $407,000 for 1998. This represents the
decline in invested cash after the Offering to a net debt position at the end of
1998, that continued through 1999.
During the year ended December 31, 1999, the Company received $1,498,000 in
cash from the sale of Utah and Texas compression assets and surplus inventory.
Net book cost and selling expenses resulted in recognized gains totaling
$840,000 for 1999 as compared to $59,000 for the year ended December 31, 1998.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
OPERATING REVENUES
Oil revenues decreased by $823,000 (22%) to $2,912,000 for the year ended
December 31, 1998 as compared to $3,735,000 for 1997 primarily as a result of a
$3.72 (25%) decline in average oil sales prices from $14.84 per Bbl in 1997 to
$11.12 in 1998. The average oil sales price of $11.12 per Bbl includes the
effects of a crude oil hedge gain of $386,000. The Company's average oil sales
price for the year ended December 31, 1998, excluding the effects of the hedge
gain, was $9.65 per Bbl.
Natural gas revenues increased by $296,000 (28%) to $1,366,000 for the year
ended December 31, 1998 as compared to $1,070,000 for 1997 primarily as a result
of an increase in the gas sales volumes of 143,000 Mcf (27%). The increase in
gas sales volumes is attributable to successful drilling activities in Utah and
Texas during the year, offset by normal production declines on existing wells.
OPERATING EXPENSES
Lease operating expenses increased $367,000 (24%) to $1,927,000 for the
year ended December 31, 1998 as compared to $1,560,000 for the year ended
December 31, 1997. This increase is a result of an increase in the average
number of operated wells and facilities between 1997 and 1998, a 10% increase in
allowable overhead charges per well, and an increase in expensed remediation
charges from unsuccessful workovers on the Company's Texas properties. In
addition, the Company's lease operating expenses on a per BOE basis increased by
$0.57 (12%) to $5.14 per BOE during 1998 as compared to $4.57 per BOE for 1997
as a result of the overhead increases and remediation charges mentioned above.
Depreciation, depletion and amortization expense declined $0.46 (8%) on a
per BOE basis to $4.97 for the year ended December 31, 1998, as compared to
$5.43 for the year ended December 31, 1997. The decline is a result of
increasing reserves in proved developed categories between periods.
Exploration costs increased to $193,000 for the year ended December 31,
1998 from zero for the year ended December 31, 1997, as two exploratory wells
drilled during the year, one in the Raton Basin and one on the Company's Texas
acreage, were plugged and abandoned. This compares to 1997, when all of the
Company's exploratory drilling activities were successful and no geological and
geophysical work was performed.
General and administrative expenses increased by $829,000 (64%) to
$2,129,000 for the year ended December 31, 1998, as compared to $1,300,000 for
the year ended December 31, 1997. This increase was the result of an increase in
engineering, geological and administrative staff as the Company prepared for
increased development activity and increased accounting staff necessary to meet
the reporting requirements associated with being a public company. The increase
was enhanced by severance and related items incurred in the fourth quarter of
1998 as the Company implemented staff reductions brought on by reduced drilling
activity and low commodity prices.
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OTHER INCOME (EXPENSES)
Interest income (expense) net, for the year ended December 31, 1998,
increased $293,000 to $407,000 as compared to $114,000 for the year ended
December 31, 1997, primarily as a result of increased interest earned on the
invested proceeds from the Offering.
CHANGE IN ACCOUNTING PRINCIPLE
The Company adopted Statement of Position ("SOP") 98-5, Reporting on the
Costs of Start-Up Activities, for fiscal years beginning after December 15,
1998. This SOP requires start-up and organizational costs to be expensed as
incurred. It also requires start-up and organizational costs previously
capitalized be expensed and that the resulting one-time expense be accounted for
as a change in accounting principle. Accordingly, the Company has shown as a
change in accounting principle a charge of $111,000, which represents the
writeoff of net capitalized organizational costs of $173,000, net of the
associated income tax benefit of $62,000.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
The Company requires capital primarily for the exploration, development and
acquisition of oil and natural gas properties, the repayment of indebtedness and
general working capital purposes.
The following table sets forth costs incurred by the Company in its
exploration, development and acquisition activities during the periods
indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
Acquisition costs:
Unproved properties ...... $ 1,320,105 $ 7,141,142 $ 1,721,636
Proved properties ........ 7,120,952 42,533 147,387
Development costs .......... 1,038,257 10,123,616 10,003,468
Exploration costs .......... 38,640 192,526 --
Improved recovery costs .... -- -- 895,317
----------- ----------- -----------
Total .................... $ 9,517,954 $17,499,817 $12,767,808
=========== =========== ===========
The Company initially estimated that it would take approximately six to 12
months to sufficiently dewater the coal gas reservoirs and bring about
commercial volumes of gas production from the Raton Basin Pilot Project.
However, greater than anticipated water production from wells in the pilot area
has significantly extended the estimated amount of time and capital necessary to
achieve gas production in commercial quantities. As a result of the higher than
anticipated water volumes, the Company conducted a series of specialized
reservoir tests during December 1999. These tests were designed, among other
things, to further estimate the additional time required to dewater the coal gas
reservoirs in the Pilot Project at the current water withdrawal rate. As a
result of this engineering evaluation, the Company determined that approximately
four to 11 additional water withdrawal wells would be required to be drilled at
a cost ranging from a total of $1.0 million to $3.0 million in the Pilot Project
to remove additional water to enable the coal formations to begin to produce
natural gas in commercial quantities.
During 2000, the Company also plans to spend approximately $8.5 million
developing its oil and gas reserves in Utah, including $2.5 million in preferred
stock for the acquisition of proved developed producing oil and gas properties
from III Exploration. The Company plans to spend, subject to available
financing, approximately $6.0 million on continued waterflood development
activities in the Antelope Creek Field. The Company expects the waterflood
development to result in enhanced cash flow and believes that it will exit 2000
with a 50% increase in its Antelope Creek daily oil production compared to
December 1999 levels.
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The funding of the Company's 2000 development plans will be dependent upon
its ability to realize proceeds from future asset sales, replace its existing
credit facility, raise equity capital and increase its operating cash flow,
whether as a result of successful operations in the Uinta Basin and Raton Basin
or from acquisitions. While the Company anticipates receiving funds from these
sources during 2000, to the extent such funds are not available in the amounts
or at the times needed, additional 2000 capital expenditures will likely be
curtailed and the Company may be required to take further measures to reduce the
size and scope of its business.
Cash Flow and Working Capital
Cash used in operating activities was $2,069,000 for the year ended
December 31, 1999. The Company used cash on hand, proceeds from sales of
property and equipment of $1,498,000, draws on its revolving line of credit of
$3,500,000, proceeds from the issuance of the Notes (defined below) to III
Exploration of $5,000,000 and a portion of the proceeds from the Private
Placement to finance $10,109,000 of capital spending to acquire the 50%
non-operated interest in the Antelope Creek Field, drill three and complete 1.5
net wells in Texas, convert two gross and net wells to injector status, acquire
additional undeveloped acreage and develop the water distribution system in the
Raton Basin.
Cash used in operating activities was $1,467,000 for the year ended
December 31, 1998. The Company used cash on hand, proceeds from sales of
property and equipment of $88,000, draws on its revolving line of credit of
$7,500,000 and the remaining Offering proceeds to finance $20,623,000 of capital
spending to drill 40 and complete 36.5 net wells, convert 15 gross (7.5 net)
wells to injector status, acquire additional undeveloped acreage and build a gas
gathering and water distribution system in the Raton Basin.
The Company currently has no borrowing capacity on its existing credit
agreement which converts in December 2000, to a term loan requiring quarterly
principal payments of approximately $916,000. The Company intends to refinance
its existing credit facility and replace it with a new credit agreement with an
initial revolving period of at least two years. The anticipated facility,
together with a planned sale of certain Texas oil and gas properties, is
expected to provide a portion of the capital resources required to fund the
Company's 2000 development program and support its ongoing operations. If the
Company is successful in replacing its existing credit facility, additional
capital resources will still be required to completely fund the Company's 2000
development plan. The Company does not currently have any other committed
sources of debt or equity capital, but anticipates these sources will become
available. However, if the Company is unable to replace its existing credit
facility, additional capital resources will be required to fund maturities of
debt as they become due. There can be no assurance that any additional financing
will be available to the Company on acceptable terms or at all. In the event
sufficient capital is not available, the Company may be unable to develop its
Uinta Basin and Raton Basin properties in accordance with its planned schedule,
pay its maturities of debt as they become due, maintain compliance with existing
debt covenants and may be required to take further measures to reduce the size
and scope of its business.
Financing
Effective September 30, 1998, the Company entered into the Credit Agreement
with the Chase Manhattan Bank, ("Chase"). The Credit Agreement established a
credit facility for the Company of up to $50.0 million with a two-year revolving
line and a borrowing base to be redetermined quarterly. The revolving credit
facility expires on September 30, 2000, at which time all outstanding balances
will convert to a term loan expiring on September 30, 2003. The Credit Agreement
contains certain financial covenants including a minimum fixed charge coverage
ratio, a minimum current ratio and others. Interest on outstanding borrowings is
calculated, at the Company's option, at either Chase's prime rate or the London
Interbank Offer Rate plus a margin determined by the amount outstanding under
the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition, the
borrowing base was increased to $11.0 million and the quarterly redetermination
scheduled for September 30, 1999 was waived. The redetermination scheduled for
December 31, 1999 resulted in no change to the borrowing base. The next
redetermination was scheduled to occur on or before March 31, 2000, however, the
Company is in the process of replacing the Credit Agreement and requested that
the redetermination be postponed.
In order to finance the Antelope Creek Acquisition, the Company and Chase
entered into Amendment No. 1 to the Credit Agreement dated as of August 20,
1999, pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III Exploration. The Notes required the Company to
deliver to III Exploration a stock purchase warrant to acquire 150,000 shares of
Common Stock of the Company at an exercise price of $3.00 per share and the
ability for III Exploration to obtain additional
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stock purchase warrants over the life of the Notes. The number of future stock
purchase warrants will be based on the future stock price performance and the
amount and duration of the Notes outstanding. The maximum number of shares of
Common Stock issuable under the stock purchase warrants for any given period is
limited to 250,000 shares in any one year, 400,000 over the first three years
and 750,000 over the five-year life of the Notes. The Company may redeem the
Notes at par without penalty at any time. Upon redemption of the Notes, any
remaining unissued and unearned stock purchase warrants will expire. The Company
utilized proceeds from the Notes to finance the remaining purchase price of the
Antelope Creek Acquisition and for working capital needs.
SUBSEQUENT EVENTS
On February 15, 2000, the stockholders of the Company approved the sale of
the Preferred Shares to III Exploration in exchange for certain producing oil
and gas properties primarily located in the Uinta Basin of Utah. The
stockholders of the Company also approved the issuance of shares of Common Stock
upon the potential conversion of the Preferred Shares.
The Preferred Shares will be convertible, beginning two years from the date
of issuance, into shares of Common Stock at a conversion price of $3.50 per
share of Common Stock, based on the preference amount of $10.00 per Preferred
Share. The Company has the option to redeem the Preferred Shares at any time
after the third anniversary of the transaction closing date in whole or in part
at a redemption price of $12.00 per Preferred Share. The Preferred Shares are
being issued pursuant to an exemption from the registration requirement under
the Securities Act and will be subject to transfer restrictions imposed by the
Securities Act.
The Company anticipates that the III Exploration Purchase will provide cash
flow of approximately $900,000 during the first year and that proved developed
producing reserves will increase 15%, or 400,000 BOE, from December 31, 1999
levels.
The effective date of the Purchase was November 1, 1999. The
transaction was closed on February 18, 2000.
INFLATION AND CHANGES IN PRICES
The Company's revenue and the value of its oil and natural gas properties
have been, and will continue to be, affected by levels of and changes in oil and
natural gas prices. The Company's ability to obtain capital through borrowings
and other means is also substantially dependent on prevailing and anticipated
oil and natural gas prices. Oil and natural gas prices are subject to
significant seasonal and other fluctuations that are beyond the Company's
ability to control or predict. In an attempt to manage this price risk, the
Company periodically engages in hedging transactions.
Currently, annual inflation in terms of the decrease in the general
purchasing power of the dollar is running much below the general annual
inflation rates experienced in the past. While the Company, like other
companies, continues to be affected by fluctuations in the purchasing power of
the dollar, such effect is not currently considered significant.
HEDGING TRANSACTIONS
The Company has historically entered into hedging contracts of various
types in an attempt to manage price risk with regard to a portion of the
Company's crude and natural gas production. While use of these hedging
arrangements limits the downside risk of price declines, such arrangements may
also limit the benefits which may be derived from price increases.
The Company has used various financial instruments such as collars, swaps
and futures contracts in an attempt to manage its price risk. Monthly
settlements on these financial instruments are typically based on differences
between the fixed prices specified in the instruments and the settlement price
of certain future contracts quoted on the NYMEX or certain other indices. The
instruments used by the Company for oil hedges have not contained a contractual
obligation which requires or allows the future physical delivery of the hedged
products.
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At December 31, 1999, the following hedge positions were in place.
Type Floor Cap Price From To Volume
- --------------------- -------- -------- -------- ------- -------- ----------------
Crude Oil Collar $ 17.00 $ 20.00 NA 1/1/00 12/31/00 12,000 Bbl/Month
Crude Oil Swap NA NA $ 20.05 1/1/00 6/30/00 12,000 Bbl/Month
Crude Oil Collar $ 20.00 $ 23.00 NA 7/1/00 09/30/00 6,000 Bbl/Mo
Natural Gas Swap NA NA $ 2.010 10/1/99 9/30/00 700 MMBtu/Day
(Questar Index)
Natural Gas Swap NA NA $ 2.2275 8/1/99 3/31/00 1,000 MMBtu/Day
(Houston Ship Channel
Index)
Natural Gas Swap NA NA $ 2.2425 4/1/00 3/31/01 1,000 MMBtu/Day
Additional hedge positions were contracted subsequent to December 31, 1999.
Type Floor Cap Price From To Volume
- --------------------- -------- -------- ----- ------- -------- -------------
Crude Oil Collar $ 23.00 $ 31.70 NA 7/1/00 9/30/00 4,000 Bbl/Mo
Crude Oil Collar $ 22.00 $ 27.00 NA 10/1/00 12/31/00 10,000 Bbl/Mo
YEAR 2000 ISSUES
The Company experienced no failure or material negative impact as a result
of the "Year 2000 issue", defined as the failure of computer systems to properly
recognize "00" in date sensitive information when the year changed to 2000.
However, the Company continues to monitor its reporting and information systems
for potential problems, including Year 2000 issue problems, and tests all newly
acquired hardware and software to assure Y2K compliance.
CAUTIONARY STATEMENTS FOR PURPOSE OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
Petroglyph or its representatives may make forward looking statements, oral
or written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells the Company anticipates drilling in specified periods and the Company's
financial position, business strategy and other plans and objectives for future
operations. Although the Company believes that the expectations reflected in
these forward looking statements are reasonable, there can be no assurance that
the actual results or developments anticipated by the Company will be realized
or, even if substantially realized, that they will have the expected effects on
its business or operations. Among the factors that could cause actual results to
differ materially from the Company's expectations are risks inherent in drilling
and other development activities, the timing and event of changes in commodity
prices, unforeseen engineering and mechanical or technological difficulties in
drilling wells and implementing enhanced oil recovery programs, the
availability, proximity and capacity of refineries, pipelines and processing
facilities, shortages or delays in the delivery of equipment and services, land
issues, federal and state regulatory developments and other factors set forth
among the risk factors noted below or in the description of the Company's
business in Item 1 of this report. All subsequent oral and written forward
looking statements attributable to the Company or persons acting on its behalf
are expressly qualified in their entirety by these factors. The Company assumes
no obligation to update any of these statements.
VOLATILITY OF OIL AND NATURAL GAS PRICES.
The Company's revenues, operating results, profitability and future growth and
the carrying value of its oil and natural gas properties are substantially
dependent upon the prices received for the Company's oil and natural gas.
Historically, the markets for oil and natural gas have been volatile and such
volatility may continue or recur in the future. Various factors beyond the
control of the Company will affect prices of oil and natural gas, including the
worldwide and domestic supplies of oil and natural gas, the ability of the
members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls, political instability or armed
conflict in oil or natural gas producing regions, the price and level of foreign
imports, the level of consumer demand, the price, availability and acceptance of
alternative fuels, the availability of pipeline capacity, weather conditions,
domestic and foreign governmental regulations and taxes and the overall economic
environment.
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Any significant decline in the price of oil or natural gas would adversely
affect the Company's revenues, operating income (loss) and cash flow and could
require an impairment in the carrying value of the Company's oil and natural gas
properties.
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves and their values, including many factors beyond the
Company's control. Estimates of proved undeveloped reserves and reserves
recoverable through enhanced oil recovery techniques, which comprise a
significant portion of the Company's reserves, are by their nature uncertain.
The reserve information set forth in this report represents estimates only.
Although the Company believes such estimates to be reasonable, reserve estimates
are imprecise and should be expected to change as additional information becomes
available.
Estimates of oil and natural gas reserves, by necessity, are projections
based on engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. In particular, given the early stage of the
Company's development programs, the ultimate effect of such programs is
difficult to ascertain. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
improved recovery techniques such as the enhanced oil recovery techniques
utilized by the Company, the assumed effects of regulations by governmental and
tribal agencies and assumptions concerning future oil and natural gas prices,
future operating costs, severance and excise taxes, development costs and
workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net cash flows expected therefrom may vary
substantially. Any significant variance in the assumptions could materially
effect the estimated quantity and value of the reserves. Actual production,
revenues and expenditures with respect to the Company's reserves will likely
vary from estimates, and such variances may be material.
The PV-10 referred to in this report should not be construed as the current
market value of the estimated oil and natural gas reserves attributable to the
Company's properties. In accordance with applicable requirements, the estimated
discounted future net cash flows from proved reserves are based on prices and
costs as of the date of the estimate, whereas actual future prices and costs may
be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply
and demand for oil and natural gas, refinery capacity, curtailments or increases
in consumption by natural gas purchasers and changes in governmental regulations
or taxation. The timing of actual future net cash flows from proved reserves,
and thus their actual present value, will be affected by the timing of both the
production and the incurrence of expenses in connection with development and
production of oil and natural gas properties. In addition, the 10% discount
factor, which is required to be used to calculate discounted future net cash
flows for reporting purposes, is not necessarily the most appropriate discount
factor based on interest rates in effect from time to time and risks associated
with the Company or the oil and natural gas industry in general.
HISTORY OF OPERATING LOSSES AND NET LOSSES.
The Company has experienced operating losses in each year since its inception in
1993, including an operating loss of approximately $2,006,000 in 1999. Excluding
the effect of the $1.3 million gain on the sale of the 50% interest in Antelope
Creek in 1996, the Company also has experienced net losses in each year since
its inception. Although the Company expects its results of operations to improve
as it develops its Uinta Basin and Raton Basin assets, there is no assurance
that the Company will achieve, or be able to sustain, profitability.
LIMITED OPERATING HISTORY.
The Company, which began operations in April 1993, has a limited operating
history upon which the Company's stockholders may base their evaluation of the
Company's performance. As a result of its brief operating history, expanded
drilling program and change in the Company's mix of properties during such
period as a result of its acquisition and disposition of properties, the
operating results from the Company's historical periods may not be indicative of
future results. There can be no assurance that the Company will continue to
experience growth in, or maintain its current level of, revenues, oil and
natural gas reserves or production.
EARLY STAGES OF DEVELOPMENT ACTIVITIES.
The Company's development plan includes (i) the drilling of development and
exploratory wells in the Uinta Basin when oil prices improve to reasonable
levels, together with injection well
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conversions that are intended to repressurize producing reservoirs in the Lower
Green River formation, (ii) subject to increasing water removal rates with the
10 additional water removal wells and observing increasing commercial gas
production from several of the 17 pilot wells, the drilling of additional wells
in connection with the development of a coalbed methane project in the Raton
Basin and (iii) the use of 3-D seismic technology to exploit its properties in
South Texas. The success of these projects will be materially dependent on
whether the Company's development and exploratory wells can be drilled and
completed as commercially productive wells, whether the enhanced oil recovery
techniques can successfully repressurize reservoirs and increase the rate of
production and ultimate recovery of oil and natural gas from the Company's
acreage in the Uinta Basin and whether the Company can successfully implement
its planned coalbed methane project on its acreage in the Raton Basin. Although
the Company believes the geologic characteristics of its project areas reduce
the probability of drilling nonproductive wells, there can be no assurance that
the Company will drill productive wells. If the Company drills a significant
number of nonproductive wells, the Company's business, financial condition and
results of operations would be materially adversely affected. While the
Company's pilot enhanced oil recovery projects in the Uinta Basin have indicated
that rates of oil production can be increased, the repressurization takes place
over a period of approximately two years and depends heavily on the amount and
rates of injected water, with full response occurring after approximately five
years; therefore, the ultimate effect of the enhanced oil recovery operations
will not be known for several years. While the Company's pilot coalbed methane
recovery project in the Raton Basin have indicated that the economically
recoverable volumes are present in the reservoir, the dewatering process can
take place over a period from three months to several years and depends heavily
on the amount and rates of produced water, with full dewatering occurring one to
two years after commercial volumes of gas are initially produced; therefore, the
ultimate effect of the dewatering operations will not be known for several
years. Ultimate recoveries of oil and natural gas from the enhanced oil and
coalbed methane recovery programs may also vary at different locations within
the Company's Uinta Basin and Raton Basin properties. Accordingly, due to the
early stage of development, the Company is unable to predict whether its
development activities in the Uinta Basin and Raton Basin will meet its
expectations. In the event the Company's enhanced oil and coalbed methane
recovery program does not effectively increase rates of production or ultimate
recovery of oil and gas reserves, the Company's business, financial condition
and results of operation will likely be materially adversely affected.
RISKS ASSOCIATED WITH OPERATING IN THE UINTA BASIN
Concentration in Uinta Basin. The Company's properties in the Greater
Monument Butte Region of the Uinta Basin constitute the majority of the
Company's existing inventory of producing properties and drilling locations.
Approximately 80% of the Company's 1999 capital expenditures of approximately
$10.1 million was dedicated to developing and acquiring additional interest in
the Company's enhanced oil recovery projects in this area. There can be no
assurance that the Company's operations in the Uinta Basin will yield positive
economic returns. Failure of the Company's Uinta Basin properties to yield
significant quantities of economically attractive reserves and production would
have a material adverse impact on the Company's financial condition and results
of operations.
Limited Refining Capacity for Uinta Basin Black Wax. The marketability of
the Company's oil production depends in part upon the availability, proximity
and capacity of refineries, pipelines and processing facilities. The crude oil
produced in the Uinta Basin is known as "black wax" or "yellow wax" and has a
higher paraffin content than crude oil found in most other major North American
basins. Currently, the most economic markets for the Company's black wax
production are five refineries in Salt Lake City that have limited facilities to
refine efficiently this type of crude oil. Because these refineries have limited
capacity, any significant increase in Uinta Basin "black wax" production or
temporary or permanent refinery shutdowns due to maintenance, retrofitting,
repairs, conversions to or from "black wax" production or otherwise could create
an over supply of "black wax" in the market, causing prices for Uinta Basin oil
to decrease. Since July 1996, the posted prices for Uinta Basin oil production
have been lower than major national indexes for crude oil. The Company believes
these differences are attributable to one or more market factors, including
refinery capacity constraints caused by the increase in supply of Uinta Basin
"black wax" production resulting from the recent drilling activity or the
reaction to the availability of additional non-Uinta Basin crude oil production
associated with a new pipeline. There can be no assurance that prices will
return to historical levels or that other price declines related to supply
imbalances will not occur in the future. To the extent crude oil prices decline
further or the Company is unable to market efficiently its oil production, the
Company's business, financial condition and results of operations could be
materially adversely affected.
Marketability of Natural Gas Production. The Company's Uinta Basin
properties currently produce natural gas in association with the production of
crude oil. The produced natural gas is gathered into the Company's natural gas
pipeline gathering system and compressed into an interstate natural gas
pipeline, at which point the produced natural gas is sold to
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marketers or end users. Because current state and Ute tribal regulations
prohibit the flaring or venting of natural gas produced in the Uinta Basin, in
the event the Company is unable to market its natural gas production due to
pipeline capacity constraints or curtailments, the Company may be forced to shut
in or curtail its oil and natural gas production from any affected wells or
install the necessary facilities to reinject the natural gas into existing
wells. Federal and state regulation of oil and natural gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its natural gas. Any dramatic change in any of these market
factors or curtailment of oil and natural gas production due to the Company's
inability to vent or flare natural gas could have a material adverse effect on
the Company.
Availability of Water for Enhanced Oil Recovery Program. The Company's
enhanced oil recovery program involves the injection of water into wells to
pressurize reservoirs and, therefore, requires substantial quantities of water.
The Company intends to satisfy its requirements from one or more of three
sources: water produced from water wells, water purchased from local water
districts and water produced in association with oil production. The Company
currently has drilled water wells only in the Antelope Creek field, and there
can be no assurance that these water wells will continue to produce quantities
sufficient to support the Company's enhanced oil recovery program, that the
Company will be able to obtain the necessary approvals to drill additional water
wells or that successful water wells can be drilled in its other Uinta Basin
development areas. The Company has a contract with East Duchesne Water District
to purchase up to 10,000 barrels of water per day through September 30, 2004.
After the initial term, this contract automatically renews each year for one
additional year; however, either party may terminate the agreement with twelve
months prior notice. In the event of a water shortage, the East Duchesne Water
District contract provides that preferences will be given to residential
customers and other water customers having a higher use priority than the
Company. In addition, the Company has not yet secured a water source for full
development of its Natural Buttes Extension properties. There can be no
assurance that water shortages will not occur or that the Company will be able
to renew or enter into new water supply agreements on commercially reasonable
terms or at all. To the extent the Company is required to pay additional amounts
for its supply of water, the Company's financial condition and results of
operations may be adversely affected. While the Company believes that there will
be sufficient volumes of water available to support its improved oil recovery
program and has taken certain actions to ensure an adequate water supply will be
available, in the event the Company is unable to obtain sufficient quantities of
water, the Company's enhanced oil recovery program and business would be
materially adversely affected.
RISKS ASSOCIATED WITH OPERATING IN THE RATON BASIN
Coalbed Methane Production. During the last ten years, new technology has
lowered the cost of coalbed methane production, making such development
commercially viable in areas where production was previously thought to be
uneconomic. While the Company believes that these new technologies will be
applicable to its acreage in the Raton Basin, the Company is still in the early
stages of its development program. There can be no assurance that although the
Company has discovered natural gas, that it will be successful in completing
commercially productive wells.
Water Disposal. The Company believes that the future water production from
the Raton Basin coal seams will be low in dissolved solids, allowing the
Company, operating under permits which the Company believes will be issued by
the State of Colorado, to discharge the water into streambeds or stockponds.
However, if nonpotable water is discovered, it may be necessary to install and
operate evaporators or to drill disposal wells to reinject the produced water
back into the underground rock formations adjacent to the coal seams or to lower
sandstone horizons. In the event the Company is unable to obtain permits from
the State of Colorado, if nonpotable water is discovered or if applicable future
laws or regulations require water to be disposed of in an alternative manner,
the costs to dispose of produced water will increase, which increase could have
a material adverse effect on the Company's operations in this area.
SUBSTANTIAL CAPITAL REQUIREMENTS.
The Company's development plans will require it to make substantial capital
expenditures in connection with the exploration, development and exploitation of
its oil and natural gas properties. The Company's enhanced oil recovery project
and pilot coalbed methane project require substantial initial capital
expenditures. Historically, the Company has funded its capital expenditures
through a combination of internally generated funds from sales of production or
properties, equity contributions, long-term debt financing and short-term
financing arrangements.
The Company currently has no borrowing capacity on its existing credit
agreement which converts in December 2000, to a term loan requiring quarterly
principal payments of approximately $916,000. The Company intends to refinance
its existing credit facility and replace it with a new credit agreement with an
initial revolving period of at least two years. The anticipated facility,
together with a planned sale of certain Texas oil and gas properties, is
expected to provide a portion of the capital resources required to fund the
Company's 2000 development program and support its ongoing operations. If the
Company is successful in replacing its existing credit facility, additional
capital resources will still be required to completely fund the Company's 2000
development plan. The Company does not currently have any other committed
sources of debt or equity capital, but anticipates these sources will become
available. However, if the Company is unable to replace its existing credit
facility, additional capital resources will be required to fund maturities of
debt as they become due. There can be no assurance that any additional financing
will be available to the Company on acceptable terms or at all. In the event
sufficient capital is not available, the Company may be unable to develop its
Uinta Basin and Raton Basin properties in accordance with its planned schedule,
pay its maturities of debt as they become due, maintain compliance with existing
debt covenants and may be required to take further measures to reduce the size
and scope of its business.
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Future cash flows and the availability of financing will be subject to a number
of variables, such as the level of production from existing wells, prices of oil
and natural gas, the Company's success in locating and producing new reserves
and the success of the enhanced recovery program in the Uinta Basin and the
coalbed methane project in the Raton Basin. To the extent that future financing
requirements are satisfied through the issuance of equity securities, the
Company's existing stockholders may experience dilution that could be
substantial. The incurrence of debt financing could result in a substantial
portion of the Company's operating cash flow being dedicated to the payment of
principal and interest on such indebtedness, could render the Company more
vulnerable to competitive pressures and economic downturns and could impose
restrictions on the Company's operations. If revenue were to decrease as a
result of lower oil and natural gas prices, decreased production or otherwise,
and the Company had no availability under the Credit Agreement or any other
credit facility, the Company could have a reduced ability to execute its current
development plans, replace its reserves or to maintain production levels, which
could result in decreased production and revenue over time.
COMPLIANCE WITH GOVERNMENTAL AND TRIBAL REGULATIONS.
Oil and natural gas operations are subject to extensive federal, state and
local laws and regulations relating to the exploration for, and the development,
production and transportation of, oil and natural gas, as well as safety
matters, which may be changed from time to time in response to economic or
political conditions. In addition, approximately 33% of the Company's acreage is
located on Ute tribal land and is leased by the Company from the Ute Indian
Tribe and the Ute Distribution Corporation. Because the Ute tribal authorities
have certain rule making authority and jurisdiction, such leases may be subject
to a greater degree of regulatory uncertainty than properties subject to only
state and federal regulations. Although the Company has not experienced any
material difficulties with its Ute tribal leases or in complying with Ute tribal
laws or customs, there can be no assurance that material difficulties will not
be encountered in the future. Matters subject to regulation by federal, state,
local and Ute tribal authorities include permits for drilling operations, road
and pipeline construction, reports concerning operations, the spacing of wells,
unitization and pooling of properties, taxation and environmental protection.
Prior to drilling any wells in the Uinta Basin, applicable federal and Ute
tribal requirements and the terms of its development agreements will require the
Company to have prepared by third parties and submitted for approval an
environmental and archaeological assessment for each area to be developed prior
to drilling any wells in such areas. Although the Company has not experienced
any material delays that have affected its development plans, there can be no
assurance that delays will not be encountered in the preparation or approval of
such assessments, or that the results of such assessments will not require the
Company to alter its development plans. Any delays in obtaining approvals or
material alterations to the Company's development plans could have a material
adverse effect on the Company's operations. From time to time, regulatory
agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and natural gas wells below actual
production capacity in order to conserve supplies of oil and natural gas.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation, and the
Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. Significant expenditures may be
required to comply with governmental and Ute tribal laws and regulations and may
have a material adverse effect on the Company's financial condition and results
of operations.
COMPLIANCE WITH ENVIRONMENTAL REGULATIONS.
The Company's operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. The implementation of new, or the modification of
existing, laws or regulations could have a material adverse effect on the
Company. The discharge of oil, natural gas or potential pollutants into the air,
soil or water may give rise to significant liabilities on the part of the
Company to the government and third parties and may require the Company to incur
substantial costs of remediation. Moreover, the Company has agreed to indemnify
sellers of properties purchased by the Company against certain liabilities for
environmental claims associated with such properties. No assurance can be given
that existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not materially
adversely affect the Company's results of operations and financial condition or
that material indemnity claims will not arise against the Company with respect
to properties acquired by the Company.
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RESERVE REPLACEMENT RISK.
The Company's future success depends upon its ability to find, develop or
acquire additional oil and natural gas reserves that are economically
recoverable. The proved reserves of the Company will generally decline as
reserves are depleted, except to the extent that the Company conducts successful
exploration or development activities, enhanced oil recovery activities or
acquires properties containing proved reserves. Approximately 42% of the
Company's total proved reserves at December 31, 1999 were undeveloped. In order
to increase reserves and production, the Company must continue its development
and exploitation drilling programs or undertake other replacement activities.
The Company's current development plan includes increasing its reserve base
through continued drilling, development and exploitation of its existing
properties. There can be no assurance, however, that the Company's planned
development and exploitation projects will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at anticipated finding and development costs.
In addition to the development of its existing proved reserves, the Company
expects that its inventory of unproved drilling locations will be the primary
source of new reserves, production and cash flow over the next few years. The
Company's properties in the Uinta Basin constitute the majority of the Company's
existing inventory. There can be no assurance that the Company's activities in
the Uinta Basin will yield economic returns. The failure of the Uinta Basin to
yield significant quantities of economically recoverable reserves could have a
material adverse impact on the Company's future financial condition and results
of operations and could result in a write-off of a significant portion of its
investment in the Uinta Basin.
DEPENDANCE ON KEY PERSONNEL.
The Company's success has been and will continue to be highly dependent on
Robert C. Murdock, its Chairman of the Board, President and Chief Executive
Officer, Sidney Kennard Smith, its Executive Vice President and Chief Operating
Officer, Tim A. Lucas, its Vice President and Chief Financial Officer, and a
limited number of other senior management and technical personnel. Loss of the
services of Mr. Murdock, Mr. Smith, Mr. Lucas or any of those other individuals
could have a material adverse effect on the Company's operations. The Company's
failure to retain its key personnel or hire additional personnel could have a
material adverse effect on the Company.
ACQUISITION RISKS.
The Company has grown primarily through the acquisition and development of
its oil and natural gas properties. Although the Company expects to concentrate
on such activities in the future, the Company expects that it may evaluate and
pursue from time to time acquisitions in the Uinta Basin, the Raton Basin and in
other areas that provide attractive investment opportunities for the addition of
production and reserves and that meet the Company's selection criteria. The
successful acquisition of producing properties and undeveloped acreage requires
an assessment of recoverable reserves, future oil and natural gas prices,
operating costs, potential environmental and other liabilities and other factors
beyond the Company's control. This assessment is necessarily inexact and its
accuracy is inherently uncertain. In connection with such an assessment, the
Company performs a review of the subject properties it believes to be generally
consistent with industry practices. This review, however, will not reveal all
existing or potential problems, nor will it permit a buyer to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. The Company generally assumes preclosing liabilities, including
environmental liabilities, and generally acquires interests in the properties on
an "as is" basis. With respect to its acquisitions to date, the Company has no
material commitments for capital expenditures to comply with existing
environmental requirements. There can be no assurance that any acquisitions will
be successful. Any unsuccessful acquisition could have a material adverse effect
on the Company.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
At March 31, 2000, the Company had 204,000 Bbls of 2000 oil production
subject to hedging and swap arrangements at various levels that result in an
average NYMEX floor price of $18.89 per Bbl and an average NYMEX ceiling price
of $21.99 per Bbl. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company also had
398,000 MMBtu of its 2000 natural gas production hedged at swap prices ranging
from $2.01 to $2.2425 per MMBtu. The Company uses hedging contracts to manage
its price risk and limit exposure to short-term fluctuations in commodity
prices. However, should 2000 NYMEX oil prices remain above $21.99 per Bbl, the
Company would not receive the marginal benefit of oil prices in excess of $21.99
per Bbl for the Bbls under hedge contracts.
Additionally, the Company is subject to interest rate risk, as $11.0
million owed at March 31, 2000 under the Company's revolving credit facility
accrues interest at floating rates tied to LIBOR. The Company's current average
rate is approximately 8.78% locked in for various terms from 90 to 180 days.
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The Company performed a sensitivity analysis to assess the potential effect
of commodity price risk and interest rate risk and determined that the effect,
if any, of reasonably possible near-term changes in NYMEX oil prices or interest
rates on the Company's financial position, results of operations and cash flow
should not be material.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements required by this item are
included on the pages immediately following the Index to Consolidated Financial
Statements appearing on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1 - Election of Directors" and to the
information under the caption "Compliance with Section 16(a) of the Securities
Exchange Act of 1934" in the Company's definitive Proxy Statement (the "2000
Proxy Statement") for its annual meeting of stockholders to be held on May 31,
2000. The 2000 Proxy Statement will be filed with the Securities and Exchange
Commission (the "Commission") not later than 120 days subsequent to December 31,
1999.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference
to the 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-K
(a) 1. Consolidated Financial Statements:
See Index to Consolidated Financial Statements on page F-1.
2. Financial Statement Schedules: None Required.
3. Exhibits: The following documents are filed as exhibits to this report:
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
2 Exchange Agreement (filed as Exhibit 2 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
3.1 Certificate of Incorporation (filed as Exhibit 3.1 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
3.2 Bylaws (filed as Exhibit 3.2 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
4.1 Form of Common Stock Certificate (filed as Exhibit 4 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
4.2 Note Purchase Agreement dated as of August 20, 1999, by and
between Petroglyph Energy, Inc. and III Exploration Company
(filed as Exhibit 4.1 to the Company's Current Report on Form
8-K filed September 2, 1999, and incorporated by reference
herein).
4.3 Warrant Agreement among III Exploration Company and Petroglyph
Energy, Inc. dated as of August 20, 1999 (filed as Exhibit 99.5
to the Schedule 13D filed by Intermountain Industries, Inc., III
Exploration Company, Century Partners and Richard Hokin on
August 30, 1999, and incorporated herein by reference).
10.1 Stockholders Agreement (filed as Exhibit 10.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.2 Registration Rights Agreement (filed as Exhibit 10.2 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
10.3 Financial Advisory Services Agreement (filed as Exhibit 10.3 to
the Company's Registration Statement on Form S-1, Registration
No. 333-34241, and incorporated herein by reference).
10.4 1997 Incentive Plan (filed as Exhibit 10.4 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.5 Form of Confidentiality and Noncompete Agreement between the
Company and each of its executive officers (filed as Exhibit
10.5 to the Company's Registration Statement on Form S-1,
Registration No. 333-34241, and incorporated herein by
reference).
10.6 Form of Indemnity Agreement between the Company and each of its
executive officers (filed as Exhibit 10.6 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.7 Amended and Restated Loan Agreement, dated September 15, 1997,
among Petroglyph Gas Partners, L.P., Petroglyph Energy, Inc. and
The Chase Manhattan Bank (filed as Exhibit 10.7 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
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10.8 Cooperative Plan of Development and Operation for the Antelope
Creek Enhanced Recovery Project, Duchesne County, Utah, dated as
of February 17, 1994, by and between Petroglyph Operating
Company, Inc., Inland Resources, Inc., Petroglyph Gas Partners,
L.P., Ute Indian Tribe and Ute Distribution Corporation (filed
as Exhibit 10.12 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.9 Exploration and Development Agreement between The Ute Indian
Tribe, The Ute Distribution Corporation and Petroglyph Gas
Partners, L.P. (filed as Exhibit 10.13 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.10 Antelope Creek Unit Participation Agreement, dated as of June 1,
1996, by and between Petroglyph Operating Company, Inc.,
Petroglyph Gas Partners, L.P. and CoEnergy Enhanced Production,
Inc. (filed as Exhibit 10.14 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
10.11 Unit Operating Agreement Unit, dated June 1, 1996, by and
between Petroglyph Operating Company, Inc., Petroglyph Gas
Partners, L.P. and CoEnergy Enhanced Production, Inc. (filed as
Exhibit 10.15 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.12 Water Agreement, dated October 1, 1994, between East Duchesne
Culinary Water Improvement District and Petroglyph Operating
Company, Inc. (filed as Exhibit 10.16 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.13 Asset Purchase and Sale Agreement, dated May 15, 1997, among
Infinity Oil & Gas, Inc. and PGP II, L.P. (filed as Exhibit
10.17 to the Company's Registration Statement on Form S-1,
Registration No. 333-34241, and incorporated herein by
reference).
10.14 Lease Agreement between Hutch Realty, L.L.C. and Petroglyph
Operating Company, Inc. (filed as Exhibit 10.18 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.15 Letter dated August 21, 1997, from Hutch Realty, L.L.C. to
Petroglyph Operating Company, Inc. concerning renewal of Lease
Agreement (filed as Exhibit 10.19 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
10.16 Warrant Agreement, dated September 15, 1997, among The Chase
Manhattan Bank, Petroglyph Gas Partners, L.P. and Petroglyph
Energy, Inc. (filed as Exhibit 10.20 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.17 Registration Rights Agreement, dated September 15, 1997, between
The Chase Manhattan Bank and Petroglyph Energy, Inc. (filed as
Exhibit 10.21 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.18 Guaranty dated September 15, 1997, by Petroglyph Energy, Inc. in
favor of The Chase Manhattan Bank (filed as Exhibit 10.22 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
10.19 First Firm Transportation Service Agreement, dated July 1, 1998,
between Petroglyph Energy, Inc. and Colorado Interstate Gas
Company (filed as Exhibit 10.19 to the Company's 1998 Annual
Report on Form 10K filed March 31, 1999, and incorporated herein
by reference).
10.20 Second Firm Transportation Service Agreement, dated July 1,
1998, between Petroglyph Energy, Inc. and Colorado Interstate
Gas Company (filed as Exhibit 10.20 to the Company's 1998 Annual
Report on Form 10K filed March 31, 1999, and incorporated herein
by reference).
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10.21 Interruptible Transportation Service Agreement, dated January 1,
1999, between Petroglyph Energy, Inc. and Colorado Interstate
Gas Company (filed as Exhibit 10.21 to the Company's 1998 Annual
Report on Form 10K filed March 31, 1999, and incorporated herein
by reference).
10.22 Form of Severance Agreement as entered into effective as of
December 1, 1998, by and between Petroglyph Energy, Inc. and
each of Robert C. Murdock, Robert A. Christensen, S. Kennard
Smith and Tim A. Lucas (filed as Exhibit 10.22 to the Company's
1998 Annual Report on Form 10K filed March 31, 1999, and
incorporated herein by reference).
10.23 Amendment No. 1, dated August 20, 1999, to Second Amended and
Restated Loan Agreement among Petroglyph Gas Partners, L.P.,
Petroglyph Energy, Inc. and The Chase Manhattan Bank (filed as
Exhibit 10.1 to the Company's Current Report on Form 8-K filed
September 2, 1999, and incorporated by reference herein).
10.24 Purchase and Sale Agreement between III Exploration Company and
the Company dated December 28, 1999 (filed as Exhibit 10.1 to
the Company's Current Report on Form 8-K filed December 30,
1999, and incorporated by reference herein).
10.25 Subscription Agreement between III Exploration Company and the
Company dated December 28, 1999 (filed as Exhibit 10.1 to the
Company's Current Report on Form 8-K filed December 30, 1999,
and incorporated by reference herein).
21 Subsidiaries of the Registrant (filed as Exhibit 21 to the
Company's 1998 Annual Report on Form 10-K filed March 31, 1999,
and incorporated by reference herein).
23.1 Consent of Lee Keeling and Associates, Inc., independent reserve
engineers.
27 Financial Data Schedule.
(b) Reports on Form 8-K:
The Company filed a report on Form 8-K on December 30, 1999, reporting the
execution of a Purchase and Sale Agreement with III Exploration Company.
On November 3, 1999, the Company also amended a report on Form 8-K filed
September 2, 1999, to include financial statements and pro forma financial
information relating to an acquisition of certain oil and gas property.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and this report. Unless otherwise indicated in this
report, natural gas volumes are stated at the legal pressure base of the state
or area in which the reserves are located and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple. BOEs are determined
using the ratio of six Mcf of natural gas to one Bbl of oil.
Average Finding Costs. The average amount of total capital expenditures,
including acquisition costs, and exploration and abandonment costs for oil and
natural gas activities divided by the amount of proved reserves (expressed in
BOE) added in the specified period (including the effect on proved reserves or
reserve revisions).
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
BOE. Barrels of oil equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu or British thermal unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Coalbed methane. Methane gas from coals in the ground, extracted using
conventional oil and natural gas industry drilling and completion methodology.
The gas produced is usually over 90% methane with a small percentage of ethane
and impurities such as carbon dioxide and nitrogen. Methane is the principal
component of natural gas. Coalbed methane shares the same markets as
conventional natural gas via the natural gas pipeline infrastructure.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Condensate. A hydrocarbon mixture that becomes liquid and separates from
natural gas when the natural gas is produced and is similar to oil.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry well. A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion as an oil or natural gas
well.
Exploratory well. A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which the Company has a working interest.
LOE. Lease operating expenses.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
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MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMcf. One million cubic feet of natural gas.
Net acres or net wells. Gross acres or wells multiplied, in each case, by
the percentage working interest owned by the Company.
Net production. Production that is owned by the Company less royalties and
production due others.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration,
development, and production of an oil or natural gas well or lease.
Original oil in place. The estimated number of barrels of crude oil in
known reservoirs prior to any production.
Present Value of Future Net Revenues or PV-10. The present value of
estimated future net revenues to be generated from the production of proved
reserves, net of estimated production and ad valorem taxes, future capital costs
and operating expenses, using prices and costs in effect as of the date
indicated, without giving effect to federal income taxes. The future net
revenues have been discounted at an annual rate of 10% to determine their
"present value". The present value is shown to indicate the effect of time on
the value of the revenue stream and should not be construed as being the fair
market value of the properties.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and natural gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by natural gas-oil and/or oil-water contacts, if
any; and (B) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information on
fluid contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
ii. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped
33
36
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reserve replacement cost. Total cost incurred for exploration and
development, divided by reserves added from all sources, including reserve
discoveries, extensions and improved recovery additions, net revisions to
reserve estimates and purchases of reserves-in-place.
Reserves. Proved reserves.
Royalty. An interest in an oil and natural gas lease that gives the owner
of the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Spud. Start drilling a new well (or restart).
3-D seismic. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
Tcf. One trillion cubic feet of natural gas.
Undeveloped acreage. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether or not such acreage contains proved
reserves. Included within undeveloped acreage are those lease acres (held by
production under the terms of a lease) that are not within the spacing unit
containing, or acreage assigned to, the productive well holding such lease.
Waterflood. The injection of water into a reservoir to fill pores or
fractures vacated by produced fluids, thus maintaining reservoir pressure and
assisting production.
Working interest. An interest in an oil and natural gas lease that gives
the owner of the interest the right to drill for and produce oil and natural gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a working
interest owner is entitled will always be smaller than the share of costs that
the working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties. For example, the owner of a 100%
working interest in a lease burdened only by a landowner's royalty of 12.5%
would be required to pay 100% of the costs of a well but would be entitled to
retain 87.5% of the production.
Workover. Operations on a producing well to restore or increase production.
34
37
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, hereunder duly authorized, as of March 31, 2000.
PETROGLYPH ENERGY, INC.
Registrant
By: /s/ ROBERT C. MURDOCK
-------------------------------------
Robert C. Murdock
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below as of March 31, 2000, by the following persons on
behalf of the Registrant and in the capacity indicated.
/s/ ROBERT C. MURDOCK
- -------------------------------------
Robert C. Murdock
President, Chief Executive Officer and
Chairman of the Board
/s/ TIM A. LUCAS
- -------------------------------------
Tim A. Lucas
Vice President, Chief Financial
Officer and Treasurer
/s/ RICHARD HOKIN
- -------------------------------------
Richard Hokin
Director
/s/ WILLIAM C. GLYNN
- -------------------------------------
William C. Glynn
Director
/s/ EUGENE C. THOMAS
- -------------------------------------
Eugene C. Thomas
Director
/s/ A. J. SCHWARTZ
- -------------------------------------
A. J. Schwartz
Director
35
38
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF PETROGLYPH ENERGY, INC.
PAGE
----
Report of Independent Public Accountants...............................................................F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998...........................................F-3
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997.............F-4
Consolidated Statements of Changes in Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997.....................................................F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997.............F-6
Notes to Consolidated Financial Statements.............................................................F-7
F-1
39
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Petroglyph Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
Petroglyph Energy, Inc. (a Delaware corporation) and subsidiary as of December
31, 1999 and 1998, and the related consolidated statements of operations,
changes in stockholders' equity, and cash flows for each of the three years in
the period ended December 31, 1999. 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 audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Petroglyph Energy, Inc. and subsidiary as of December 31, 1999 and 1998 and the
results of their operations and cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
April 19, 2000
F-2
40
PETROGLYPH ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31,
----------------------------
1999 1998
------------ ------------
ASSETS
Current Assets:
Cash and cash equivalents ....................................... $ 1,741,849 $ 2,007,737
Accounts receivable:
Oil and natural gas sales .................................. 656,338 264,827
Joint interest billing ..................................... 33,827 834,910
Other ...................................................... 86,489 133,342
------------ ------------
776,654 1,233,079
Inventory ....................................................... 1,489,420 1,234,323
Prepaid expenses ................................................ 137,668 247,518
------------ ------------
Total Current Assets .................................. 4,145,591 4,722,657
------------ ------------
Property and equipment, successful efforts method at cost:
Proved properties ............................................... 38,835,247 32,191,345
Unproved properties ............................................. 11,769,103 10,072,036
Pipelines, gas gathering and other .............................. 10,424,319 10,024,602
------------ ------------
61,028,669 52,287,983
Less--Accumulated depreciation, depletion, and amortization ..... (12,516,006) (11,590,068)
------------ ------------
Property and equipment, net ................................ 48,512,663 40,697,915
------------ ------------
Note receivable from officers ........................................ 247,043 392,465
Other assets, net .................................................... 41,230 222,164
------------ ------------
Total Assets .......................................... $ 52,946,527 $ 46,035,201
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade ...................................................... $ 635,007 $ 2,088,290
Oil and natural gas sales .................................. 115,985 280,179
Current portion of long-term debt .......................... 916,666 --
Accrued taxes payable ...................................... 138,762 124,857
Other ...................................................... 370,787 277,637
------------ ------------
Total Current Liabilities ......................... 2,177,207 2,770,963
------------ ------------
Long-term debt ............................................................ 14,953,134 7,500,000
------------ ------------
Deferred tax liability .................................................... -- 452,488
------------ ------------
Stockholders' Equity:
Common Stock, par value $.01 per share; 25,000,000 shares
authorized; 6,458,333 shares issued and outstanding ........ $ 64,583 $ 54,583
Paid-in capital ...................................................... 48,195,022 46,134,018
Retained deficit ..................................................... (12,443,419) (10,876,851)
------------ ------------
Total Stockholders' Equity ............................ 35,816,186 35,311,750
------------ ------------
Total Liabilities and Stockholders' Equity ................................ $ 52,946,527 $ 46,035,201
============ ============
The accompanying notes are an integral part of
these consolidated financial statements.
F-3
41
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
------------------------------------------------
1999 1998 1997
------------ ------------ ------------
Operating Revenues:
Oil sales ............................................ $ 3,652,095 $ 2,912,293 $ 3,734,856
Natural gas sales .................................... 1,159,512 1,365,850 1,070,195
Other ................................................ 230,603 189,924 60,847
------------ ------------ ------------
Total operating revenues ...................... 5,042,210 4,468,067 4,865,898
------------ ------------ ------------
Operating Expenses:
Lease operating ...................................... 2,953,369 1,927,334 1,559,885
Production taxes ..................................... 359,122 218,129 178,822
Exploration costs .................................... 38,640 192,526 --
Depreciation, depletion, and amortization ............ 1,673,409 1,866,111 1,852,296
Impairments .......................................... -- 4,848,218 --
General and administrative ........................... 2,024,119 2,128,774 1,299,851
------------ ------------ ------------
Total operating expenses ...................... 7,048,659 11,181,092 4,890,854
------------ ------------ ------------
Operating Loss ............................................. (2,006,449) (6,713,025) (24,956)
Other Income (Expenses):
Interest income (expense), net ....................... (679,284) 406,975 114,036
Gain (loss) on sales of property and equipment, net .. 840,412 58,577 12,440
------------ ------------ ------------
Net income (loss) before income taxes ...................... (1,845,321) (6,247,473) 101,520
------------ ------------ ------------
Income Tax Expense (Benefit):
Current .............................................. -- -- (463,238)
Deferred ............................................. (389,943) (2,061,666) 2,977,392
------------ ------------ ------------
Total Income Tax (Benefit) Expense ............ (389,943) (2,061,666) 2,514,154
------------ ------------ ------------
Net Income (Loss) before Change in Accounting Principle .... $ (1,455,378) $ (4,185,807) $ (2,412,634)
============ ============ ============
Accounting Change - Expense of Start Up Costs (net
of tax) .............................................. (111,190) -- --
Net Income (Loss): ......................................... $ (1,566,568) $ (4,185,807) $ (2,412,634)
============ ============ ============
Earnings (Loss) per Share before Accounting Change ......... $ (0.27) $ (0.77) $ (0.73)
Earnings (Loss) per Share from Accounting Change ........... $ (0.02) $ -- $ --
------------ ------------ ------------
Earnings (Loss) per Common Share, Basic and Diluted ........ $ (0.29) $ (0.77) $ (0.73)
============ ============ ============
Weighted Average Common Shares Outstanding (Note 5) ........ $ 5,469,292 $ 5,458,333 $ 3,326,826
============ ============ ============
The accompanying notes are an integral part of
these consolidated financial statements.
F-4
42
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
COMMON PARTNERS' PAID IN RETAINED
STOCK CAPITAL CAPITAL DEFICIT TOTAL EQUITY
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1996 $ -- $ 16,973,044 $ -- $ (4,278,410) $ 12,694,634
Initial public offering of
common stock, net of
offering costs 26,250 -- 29,189,307 -- 29,215,557
Transfers at Conversion 28,333 (16,973,044) 16,944,711 -- --
Deferred income taxes
recorded upon Conversion
(Note 2) -- -- -- (2,474,561) (2,474,561)
Net income -- -- -- 61,927 61,927
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1997 54,583 -- 46,134,018 (6,691,044) 39,497,557
Net loss -- -- -- (4,185,807) (4,185,807)
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1998 $ 54,583 $ -- $ 46,134,018 $(10,876,851) $ 35,311,750
Private offering of common
stock, net of offering costs 10,000 -- 1,921,504 -- 1,931,504
Warrants issued in connection
with subordinated loan -- -- 139,500 -- 139,500
Net loss -- -- -- (1,566,568) (1,566,568)
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1999 $ 64,583 $ -- $ 48,195,022 $(12,443,419) $ 35,816,186
============ ============ ============ ============ ============
The accompanying notes are an integral part of
these consolidated financial statements.
F-5
43
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1999 1998 1997
------------ ------------ ------------
Operating Activities:
Net income (loss) ............................................ $ (1,566,568) $ (4,185,807) $ (2,412,634)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization ............ 1,691,409 1,866,111 1,852,296
Amortization of warrants - interest expense
and notes payable .................................... 9,300 -- --
Gain on sales of property and equipment, net ......... (840,412) (58,577) (12,440)
Amortization of deferred revenue ..................... -- -- (45,860)
Impairments .......................................... -- 4,848,218
Exploration Costs .................................... 38,640 192,526 --
Expense capitalized start-up costs - Change in
Accounting Principle ................................. 173,735 -- --
Write-off of officer note receivable ................. 175,901
Deferred Taxes ....................................... (452,488) (2,061,666) 2,514,154
Changes in current assets and liabilities--
(Increase) decrease in accounts and other
receivables ............................................. 425,946 (113,462) 142,144
Increase in inventory ................................... (324,294) (33,586) (311,935)
(Increase) decrease in prepaid expenses ................. 109,850 (26,325) (113,945)
Increase (decrease) in accounts payable and
accrued liabilities .................................. (1,510,423) (1,894,706) 20,819
------------ ------------ ------------
Net cash provided by (used in) operating
activities ........................................... (2,069,404) (1,467,274) 1,632,599
------------ ------------ ------------
Investing Activities:
Proceeds from sales of property and equipment ................ 1,498,390 88,200 745,712
Additions to oil and natural gas properties, including
exploration costs ....................................... (9,517,954) (17,499,817) (12,767,808)
Additions to pipelines, gas gathering and other .............. (590,913) (3,123,302) (3,491,853)
------------ ------------ ------------
Net cash used in investing activities ................... (8,610,477) (20,534,919) (15,513,949)
------------ ------------ ------------
Financing Activities:
Proceeds from issuance of equity securities .................. 1,931,504 -- 30,515,625
Proceeds from issuance of, and draws on, notes payable ....... 8,500,000 7,500,000 10,085,381
Payments on notes payable .................................... -- (36,598) (10,133,545)
Payments for organization and financing costs ................ (17,511) (132,127) (1,485,088)
------------ ------------ ------------
Net cash provided by financing activities ....................... 10,413,993 7,331,275 28,982,373
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents ............ (265,888) (14,670,918) 15,101,023
Cash and cash equivalents, beginning of period .................. 2,007,737 16,678,655 1,577,632
------------ ------------ ------------
Cash and cash equivalents, end of period ....................... $ 1,741,849 $ 2,007,737 $ 16,678,655
============ ============ ============
The accompanying notes are an integral part of
these consolidated financial statements.
F-6
44
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
1. ORGANIZATION:
Petroglyph Energy, Inc. ("Petroglyph" or the "Company") was
incorporated in Delaware in April 1997 for the purpose of consolidating and
continuing the activities previously conducted by Petroglyph Gas Partners, L.P.
("PGP" or the "Partnership"). PGP was a Delaware limited partnership organized
on April 15, 1993 to acquire, explore for, produce and sell oil, natural gas,
and related hydrocarbons. The general partner of PGP at its formation was
Petroglyph Energy, Inc., a Kansas corporation ("PEI"). Petroglyph Gas Partners
II, L.P. ("PGP II") was organized on April 15, 1995 as a Delaware limited
partnership, to acquire, explore for, produce and sell oil, natural gas and
related hydrocarbons. The general partner of PGP II was PEI (1% interest) and
the sole limited partner was PGP (99% interest). Pursuant to the terms of an
Exchange Agreement dated August 22, 1997 (the "Exchange Agreement"), the Company
acquired all of the outstanding partnership interests of the Partnership and all
of the stock of PEI in exchange for shares of Common Stock of the Company (the
"Conversion"). The Conversion and other transactions contemplated by the
Exchange Agreement were consummated on October 24, 1997, immediately prior to
the closing of the initial public offering of the Company's Common Stock (the
"Offering"). The Conversion was accounted for as a transfer of assets and
liabilities between affiliates under common control and resulted in no change in
carrying values of these assets and liabilities. Effective June 30, 1998, PEI,
PGP and PGP II were dissolved and the assets and liabilities and results of
operations were rolled up into the Company with no change in carrying values.
During August of 1999, III Exploration Company ("III Exploration")
completed the purchase (the "Purchase") from Robert A. Christensen, a director
and executive officer of the Company, David R. Albin, a director of the Company,
Kenneth A. Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster,
Bruce B. Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural
Gas Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of Common Stock of the Company. III Exploration
is controlled by Intermountain Industries, Inc., an Idaho corporation
("Intermountain"). As a result of the Purchase, Intermountain, through its
ownership of III Exploration, acquired approximately 50.4% of the outstanding
Common Stock of the Company (the "Change of Control").
The accompanying consolidated financial statements of Petroglyph
include the assets, liabilities and results of operations of its wholly owned
subsidiary, Petroglyph Operating Company, Inc. ("POCI"). POCI is a subchapter C
corporation. POCI is the designated operator of all wells for which the Company
has acquired operating rights. Accordingly, all producing overhead and
supervision fees were charged to the joint accounts by POCI. All material
intercompany transactions and balances have been eliminated in the preparation
of the accompanying consolidated financial statements.
The Company's operations are primarily focused in the Uinta Basin of
Utah and the Raton Basin of Colorado.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
MANAGEMENT'S USE OF ESTIMATES
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 at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
F-7
45
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest during 1999, 1998 and 1997 totaled $807,000,
$116,000 and $325,000, respectively. The Company did not make any cash payments
for income taxes during 1999 and 1998 based on net losses for the year, and no
cash payment for income taxes was made in 1997 based on its partnership
structure in effect during that period.
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful
accounts, the amounts of which are immaterial as of December 31, 1999, 1998 and
1997.
INVENTORY
Inventories consist primarily of crude oil held in tanks available for
sale, tubular goods and oil field materials and supplies, which the Company
plans to utilize in its ongoing exploration and development activities and are
carried at the lower of weighted average historical cost or market value.
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its
oil and natural gas properties whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized on a unit-of-
production basis over the respective properties' remaining proved reserves.
Amortization of capitalized costs is provided on a prospect-by-prospect basis.
Leasehold costs are capitalized when incurred. Unproved oil and natural
gas properties with significant acquisition costs are periodically assessed and
any impairment in value is charged to impairment expense. The costs of unproved
properties which are not individually significant are assessed periodically in
the aggregate based on historical experience, and any impairment in value is
charged to exploration costs. The costs of unproved properties that are
determined to be productive are transferred to proved oil and natural gas
properties.
Exploration costs, including geological and geophysical expenses,
property abandonments and annual delay rentals, are charged to expense as
incurred. Exploratory drilling costs, if any, including the cost of
stratigraphic test wells, are initially capitalized but charged to expense if
and when the well is determined to be unsuccessful.
The Company adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," in connection with its formation.
SFAS No. 121 requires that proved oil and natural gas properties be assessed for
an impairment in their carrying value whenever events or changes in
circumstances indicate that such carrying value may not be recoverable. SFAS No.
121 requires that this assessment be performed by comparing the anticipated
future net cash flows to the net carrying value of oil and natural gas
properties. This assessment must generally be performed on a
property-by-property basis. The Company recognized impairments of $4,848,218 in
1998. No such impairments were required in the years ended December 31, 1999 and
1997.
The Company has a significant unproved natural gas property in the
Raton Basin with a carrying value of $11,154,000 at December 31, 1999 that has
not yet demonstrated the ability to produce commercial quantities of natural
gas. The Company believes that additional development and time will be required
to achieve the production of commercial quantities of natural gas. However,
there can be no assurance that the Raton property will ultimately produce
commercial quantities of natural gas. If the additional development of the Raton
Basin project does not result in commercial quantities of natural gas
production, the Company would be required to record an impairment expense that
could potentially be equal to the carrying value of the property.
Pipelines, Gas Gathering and Other
Other property and equipment is primarily comprised of field water
distribution systems and natural gas gathering systems located in the Uinta
Basin and Raton Basin, field building and land, office equipment, furniture and
fixtures and automobiles. The gathering systems and the field water distribution
systems are amortized on a unit-of-production basis over
F-8
46
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
the remaining proved reserves attributable to the properties served. These other
items are amortized on a straight-line basis over their estimated useful lives
which range from three to thirty years.
ORGANIZATION AND FINANCING COSTS
During 1999, the Company adopted Statement of Position ("SOP") 98-5,
Reporting on the Costs of Start-Up Activities, which requires future start-up
and organization charges to be expensed as they are incurred and previously
capitalized charges to be expensed upon adoption as a change in accounting
principle. Accordingly, the Company has shown as a change in accounting
principle a $111,190 expense, which represents the writeoff of net capitalized
organization costs of $173,735 net of the associated income tax benefit of
$62,545. Prior to 1999, organization costs were amortized over a period not to
exceed five years and presented net of accumulated amortization of $100,385 and
$61,895 at December 31, 1998 and 1997, respectively. Amortization of $38,490 and
$12,436 is included in depreciation, depletion and amortization expense in the
accompanying consolidated statements of operations for the years ended December
31, 1998, and 1997, respectively.
Costs related to the issuance of the Company's notes payable are
deferred and amortized on a straight-line basis over the life of the related
borrowing. Such amortization costs of $18,000 and $26,000 are included in
interest expense in the accompanying statements of operations for the year ended
December 31, 1999 and 1998, respectively.
INTEREST INCOME (EXPENSE)
For the year ended December 31, 1999, interest expense is presented net
of interest income of $93,000. For the years ended December 31, 1998 and 1997,
interest income is presented net of interest expense of $132,193 and $198,519,
respectively.
CAPITALIZATION OF INTEREST
Interest costs associated with maintaining the Company's inventory of
unproved oil and natural gas properties and significant development projects are
capitalized. Interest capitalized totaled $118,000, $90,000 and $127,000 for the
years ended December 31, 1999, 1998 and 1997, respectively.
REVENUE RECOGNITION AND NATURAL GAS BALANCING
The Company utilizes the entitlements method of accounting whereby
revenues are recognized based on the Company's revenue interest in the amount of
oil and natural gas production. The amount of oil and natural gas sold may
differ from the amount which the Company is entitled based on its revenue
interests in the properties. The Company had no significant natural gas
balancing positions at December 31, 1999 or 1998.
INCOME TAXES
Prior to the Conversion, the results of operations of the Company were
included in the tax returns of its owners. As a result, tax strategies were
implemented that are not necessarily reflective of strategies the Company would
have implemented. In addition, the tax net operating losses generated by the
Company during the period from its inception to date of the Conversion will not
be available to the Company to offset future taxable income as such benefit
accrued to the owners.
In conjunction with the Conversion, the Company adopted SFAS No. 109,
"Accounting for Income Taxes," which provides for determining and recording
deferred income tax assets or liabilities based on temporary differences between
the financial statement carrying amounts and the tax bases of assets and
liabilities using enacted tax rates. SFAS No. 109 requires that the net deferred
tax liabilities of the Company on the date of the Conversion be recognized as a
component of
F-9
47
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
income tax expense. The Company recognized a one-time charge of approximately
$2.5 million in deferred tax liabilities and income tax expense on the date of
the Conversion. Upon the Conversion, the Company became taxable as a
corporation.
DERIVATIVES
The Company uses derivatives to hedge against interest rate and product
prices risks, as opposed to their use for trading purposes. The Company's policy
is to ensure that a correlation exists between the financial instruments and the
Company's pricing in its sales contracts prior to entering into such contracts.
Gains and losses on commodity futures contracts and other price risk management
instruments are recognized in oil and natural gas revenues when the hedged
transaction occurs. Cash flows related to derivative transactions are included
in operating activities.
STOCK-BASED COMPENSATION
The Company follows the provisions of Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." In accordance with
APB No. 25, no compensation will be recorded for stock options or other
stock-based awards that are granted with an exercise price equal to or above the
common stock price on the date of the grant.
RECLASSIFICATIONS
Certain reclassifications have been made to prior year balances to
conform to current year presentation.
3. ACQUISITIONS AND DISPOSITIONS
During August 1999, the Company acquired the remaining 50% working
interest in the Antelope Creek Field in the Uinta Basin of Utah (the "Antelope
Creek Property") from its non-operated working interest partner, Williams
Production Rocky Mountain Company ("Williams"), for a purchase price of $6.9
million (the "Antelope Creek Acquisition"). The Antelope Creek Acquisition,
which was effective August 1, 1999, gives the Company a 100% working interest in
the Antelope Creek Property. The following table shows operating revenues, net
loss and earnings per share as if the Company had owned 100% working interest in
the Antelope Creek Field from January 1, 1998.
Revenues Net Loss Loss per Share
------------- ------------- --------------
1998 $ 7,627,100 $ (4,300,891) $ (0.79)
1999 $ 6,544,184 $ (1,159,476) $ (0.21)
In July 1997, the Company acquired 56,000 net mineral acres in the
Raton Basin in Colorado for approximately $700,000. This acquisition had an
effective date of May 15, 1997. An additional 17,100 net mineral acres were
acquired by December 31, 1999 from various parties for a total of 73,100 net
acres. In addition, the Company also acquired, simultaneously, an 80% interest
in a 25 mile pipeline strategically located across the Company's acreage
positions in the Raton Basin for total consideration of approximately $320,000.
The Company, together with an industry partner, formed a partnership to operate
this pipeline. Under the terms of the purchase and sale agreement, the Company
paid $75,000 at closing, $75,000 on December 31, 1997, and paid a final $35,000
during 1998. Additionally, the Company assumed an obligation for delinquent
property taxes of approximately $135,000, which were paid in November of 1997.
The Company acquired the remaining 20% interest in the pipeline for $60,000
effective December 1998. Simultaneously, the partnership formed to operate the
pipeline was dissolved.
4. FUTURE OPERATIONS
The Company has experienced operating losses in each year since its
inception and incurred an operating cash flow deficit (net cash provided by
operating activities before changes in working capital) in the year ended
December 31, 1999. Such operating losses and cash flow deficits have continued
subsequent to December 31, 1999. The future success of the
F-10
48
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
4. FUTURE OPERATIONS: (CONTINUED)
Company is dependent upon its ability to develop additional oil and natural gas
reserves that are economically recoverable within its two primary operating
areas, the Uinta Basin and Raton Basin Projects. Development of these projects
will require substantial additional capital expenditures. The Company currently
has no borrowing capacity on its existing credit agreement which converts in
December 2000, to a term loan requiring quarterly principal payments of
approximately $916,000. The Company intends to refinance its existing credit
facility and replace it with a new credit agreement with an initial revolving
period of at least two years. The anticipated facility, together with a planned
sale of certain Texas oil and gas properties, is expected to provide a portion
of the capital resources required to fund the Company's 2000 development program
and support its ongoing operations. If the Company is successful in replacing
its existing credit facility, additional capital resources will still be
required to completely fund the Company's 2000 development plan. The Company
does not currently have any other committed sources of debt or equity capital,
but anticipates these sources will become available. However, if the Company is
unable to replace its existing credit facility, additional capital resources
will be required to fund maturities of debt as they become due. There can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all. In the event sufficient capital is not available,
the Company may be unable to develop its Uinta Basin and Raton Basin properties
in accordance with its planned schedule, pay its maturities of debt as they
become due, maintain compliance with existing debt covenants and may be required
to take further measures to reduce the size and scope of its business.
5. STOCKHOLDERS' EQUITY:
INITIAL PUBLIC OFFERING
On October 24, 1997, Petroglyph completed its initial public offering
(the "Offering") of 2,500,000 shares of common stock at $12.50 per share,
resulting in net proceeds to the Company of approximately $29.1 million.
Approximately $10.0 million of the net proceeds were used to eliminate all
outstanding amounts under the Company's Credit Agreement, the balance of the
proceeds were utilized to develop production and reserves in the Company's core
Uinta Basin and Raton Basin development properties and for other working capital
needs.
On November 24, 1997, the Company's underwriters exercised a portion of
an over-allotment option granted in connection with the Offering, resulting in
the issuance of an additional 125,000 shares of common stock at $12.50 per
share, with net proceeds to the Company of approximately $1.5 million.
PRIVATE PLACEMENT
On December 28, 1999, the Company sold 1,000,000 shares of Common Stock
to III Exploration in a privately negotiated sale at a purchase price of $2.00
per share, for aggregate proceeds of $2.0 million (the "Private Placement"). The
Common Stock issued in the Private Placement has not been registered under the
Securities Act of 1933, as amended (the "Securities Act"), and may not be
offered or sold in the United States absent registration or an applicable
exemption from registration requirements. The Company intends to use the
proceeds from the Private Placement for working capital, to finance existing
operations and to finance a portion of the Company's 2000 development plans for
its Uinta Basin and Raton Basin properties. As a result of the Private
Placement, III Exploration's ownership interest in the Company's Common Stock
has increased to 59.07% (assuming the exercise of a warrant to purchase 150,000
shares of Common Stock issued in connection with the subordinated notes).
WARRANTS
A warrant to purchase 150,000 shares of Common Stock, at an exercise
price equal to $3.00 per share, was issued to Intermountain in conjunction with
the issuance of $5 million in subordinated notes. The warrant expires on August
20, 2009 and was still outstanding at December 31, 1999.
EARNINGS PER SHARE INFORMATION
Effective December 31, 1997, the Company adopted the provisions of SFAS
No. 128, "Earnings Per Share," which prescribes standards for computing and
presenting earnings per share ("EPS") and supersedes APB Opinion 15, "Earnings
Per Share."
F-11
49
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
5. STOCKHOLDERS' EQUITY: (CONTINUED)
The computation of basic and diluted EPS were identical for the years
ended December 31, 1999, 1998 and 1997 due to the following reasons:
o A warrant to purchase 150,000 shares of common stock was not included
in the computation of diluted EPS as they are antidilutive as a result
of the Company's net loss for the year ended December 31, 1999. The
warrants, which expire on August 20, 2009, were still outstanding at
December 31, 1999.
o Options to purchase 210,000 and 280,000 shares of common stock at $5.00
per share at December 31, 1999 and 1998, respectively, were outstanding
since October 19, 1998, but were not included in the computation of
diluted EPS because to do so would have been antidilutive. The 210,000
options, which expire on October 19, 2008, were still outstanding at
December 31, 1999.
o Options to purchase 210,000, 314,000 and 337,000 shares of common stock
at $12.50 per share at December 31, 1999, 1998 and 1997, respectively,
were outstanding since November 1, 1997, but were not included in the
computations of diluted EPS because to do so would have been
antidilutive. The 210,000 options, which expire on November 1, 2007,
were still outstanding at December 31, 1999.
o Warrants to purchase up to 6,496 shares of common stock were not
included in the computation of diluted EPS as they are antidilutive as
a result of the Company's net loss for the year ended December 31,
1999. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1999.
6. TRANSACTIONS WITH AFFILIATES:
The Company had notes receivable from certain executive officers
aggregating $141,738 and $246,500 at December 31, 1999 and 1998, respectively.
These notes bear interest at a rate of 9% and mature December 31, 2003. Accrued
interest on the notes at December 31, 1999 and 1998 was $105,305 and $145,965,
respectively. In August 1999, the Company forgave a note receivable of $104,762
with accrued interest of $71,139 owed to the Company by a former executive
officer. In exchange for the debt forgiveness, the officer relinquished his
rights under a severance agreement, which had a potential cash value of
$250,000.
The Company leases an office building from an affiliate. Rentals paid
to the affiliate for such leases totaled $41,676 during 1999, $36,486 during
1998 and $34,800 during 1997. These rentals are included in general and
administrative expense in the accompanying consolidated financial statements.
In August 1997, the Company and Natural Gas Partners ("NGP") entered
into a financial advisory services agreement whereby NGP agreed to provide
financial advisory services to the Company for a quarterly fee of $13,750. In
addition, NGP was reimbursed for its out of pocket expenses incurred while
performing such services. The agreement was terminated at the end of the third
quarter 1998. Advisory fees paid to NGP during 1998 and 1997 totaled $43,190 and
$10,163, respectively.
For the years ended December 31, 1999, 1998 and 1997, the Company paid
legal fees of $25,254, $57,060 and $139,384, respectively, to the law firm of
Morris, Laing, Evans, Brock & Kennedy, Chartered, where A.J. Schwartz, a
director of the Company, is a shareholder.
During 1997, the Company entered into an agreement with Sego Resources,
Inc. (SEGO), a portfolio company of NGP, to serve as operator on a series of
wells to be drilled in the Wasatch formation in the Company's Natural Buttes
Extension acreage. The Company has participated in drilling and completing two
wells through December 31, 1999. As a result of the drilling and operating
activity, the Company paid SEGO $183,359 for capital expenditures and $6,182 for
operating charges in 1998.
F-12
50
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
6. TRANSACTIONS WITH AFFILIATES: (CONTINUED)
In August 1999, the Company sold $5 million of 8% senior subordinated
notes due 2004 (the "Notes") to III Exploration to fund a portion of the $6.9
million Antelope Creek Acquisition. The Notes required the Company to deliver to
III Exploration a stock purchase warrant to acquire 150,000 shares of Common
Stock of the Company at an exercise price of $3.00 per share and granted III
Exploration the ability to obtain additional stock purchase warrants over the
life of the Notes. The number of future stock purchase warrants will be based on
the future stock price performance and the amount and duration of the Notes
outstanding. The maximum number of shares of Common Stock issuable under the
stock purchase warrants for any given period is limited to 250,000 shares in any
one year, 400,000 over the first three years and 750,000 over the five-year life
of the Notes. The Company may redeem the Notes at par without penalty at any
time. Upon redemption of the Notes, any remaining unissued and unearned stock
purchase warrants will expire.
On December 28, 1999, the Company sold 1,000,000 shares of Common Stock
to III Exploration in a privately negotiated sale at a purchase price of $2.00
per share, for aggregate proceeds of $2.0 million (the "Private Placement"). The
Common Stock issued in the Private Placement has not been registered under the
Securities Act of 1933, as amended (the "Securities Act"), and may not be
offered or sold in the United States absent registration or an applicable
exemption from registration requirements. The Company intends to use the
proceeds from the Private Placement for working capital, to finance existing
operations and to finance a portion of the Company's 2000 development plans for
its Uinta Basin and Raton Basin properties. As a result of the Private
Placement, III Exploration's ownership interest in the Company's Common Stock
increased to 59.07% (assuming the exercise of a warrant to purchase 150,000
shares of Common Stock).
7. LONG-TERM DEBT:
Effective September 30, 1998, the Company entered into the Credit
Agreement with the Chase Manhattan Bank ("Chase"). The Credit Agreement
established a credit facility for the Company of up to $50.0 million with a
two-year revolving line and a borrowing base to be redetermined quarterly. The
revolving credit facility expires on September 30, 2000, at which time all
outstanding balances will convert to a term loan expiring on September 30, 2003.
The Credit Agreement contains certain financial covenants including a minimum
fixed charge coverage ratio, a minimum current ratio and others. Interest on
outstanding borrowings is calculated, at the Company's option, at either Chase's
prime rate or the London Interbank Offer Rate ("LIBOR") plus a margin determined
by the amount outstanding under the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition,
the borrowing base was increased to $11.0 million and the quarterly
redetermination scheduled for September 30, 1999 was waived. The redetermination
scheduled for December 31, 1999 resulted in no change to the borrowing base. The
next redetermination was scheduled to occur on or before March 31, 2000,
however, the Company is in the process of replacing the Credit Agreement and
requested that the redetermination be postponed.
In order to finance the Antelope Creek Acquisition, the Company and
Chase entered into Amendment No. 1 to the Credit Agreement dated as of August
20, 1999, pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated
notes due 2004 to III Exploration. The Notes required the Company to deliver to
III Exploration a stock purchase warrant to acquire 150,000 shares of Common
Stock of the Company at an exercise price of $3.00 per share and the ability for
III Exploration to obtain additional stock purchase warrants over the life of
the Notes. The Company may redeem the Notes at par without penalty at any time.
F-13
51
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
7. LONG-TERM DEBT: (CONTINUED)
The following table sets forth the Company's maturities of long-term
debt as of December 31, 1999.
YEAR LONG-TERM DEBT
------------------- --------------
2001 $ 3,666,667
2002 3,666,667
2003 2,750,000
2004 4,869,800
-----------
Long-term Debt 14,953,134
Current Portion 916,666
-----------
Total Debt $15,869,800
===========
8. INCOME TAXES:
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the periods shown below:
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1999 1998 1997
----------- ----------- -----------
Income tax expense (benefit) at the federal statutory
rate ....................................................... (35%) (35%) 35%
State income tax expense (benefit) .............................. (4%) (4%) 4%
Deferred tax liabilities recorded upon the Offering ............. -- -- 2438%
Net operating loss utilized by partners ......................... -- 2% --
Permanent differences ........................................... 1% 2% --
True-ups ........................................................ 2% 1% --
Valuation allowance ............................................. 14% -- --
Other ........................................................... -- 1%
----------- ----------- -----------
$ (22%) $ (33%) $ 2477%
=========== =========== ===========
Components of income tax expense (benefit) are as follows:
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1999 1998 1997
----------- ----------- -----------
Current ......................................................... $ -- $ -- $ (463,238)
Deferred ........................................................ (452,488) (2,061,666) 2,977,392
----------- ----------- -----------
Total ......................................... $ (452,488) $(2,061,666) $ 2,514,154
=========== =========== ===========
F-14
52
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
8. INCOME TAXES: (CONTINUED)
Deferred tax assets and liabilities are the results of temporary
differences between the financial statement carrying values and tax bases of
assets and liabilities. The Company's net deferred tax liability positions as of
December 31, 1999 and 1998, are summarized below:
DECEMBER 31,
---------------------------------
1999 1998
----------- -----------
Deferred Tax Assets:
Inventory and other .............................. $ 72,168 $ 76,188
Net operating loss carryforwards ................. 3,514,958 2,703,339
Valuation allowance .............................. (290,058) --
----------- -----------
Total Deferred Tax Assets ............... $ 3,297,068 $ 2,779,527
----------- -----------
Deferred Tax Liabilities:
Property and equipment ........................... (3,297,068) (3,232,015)
----------- -----------
Total Deferred Tax Liabilities .......... (3,297,068) (3,232,015)
----------- -----------
Total Net Deferred Tax Liability ........ $ -- $ (452,488)
=========== ===========
In August 1999, III Exploration completed the purchase of a majority
interest in the Company from the Sellers. As a result of the Purchase, the
Company's net operating loss carryforwards at the time of the transaction became
subject to an annual limitation of approximately $848,000 under Section 382 of
the Internal Revenue Code of 1986, as amended. Additionally, during 1999, the
Company recognized a valuation allowance due to the uncertainty of realizing a
portion of the Company's net operating loss carryforwards.
9. DERIVATIVES, SALES CONTRACTS AND SIGNIFICANT CUSTOMERS:
DERIVATIVES AND SALES CONTRACTS
The Company accounts for forward sales transactions as hedging
activities and, accordingly, records all gains and losses in oil and natural gas
revenues in the period the hedged production is sold. Included in oil revenue is
a net loss of $144,000 in 1999, a net gain of $386,000 in 1998 and a net loss of
$132,000 in 1997. Included in natural gas revenues in 1999 is a net loss of
$187,000, and a net loss of $46,000 in 1997.
During March of 1999, the Company liquidated a hedge contract covering
72,000 Bbls in the year 2000 for approximately $16,000.
The Company has used various financial instruments such as collars,
swaps and futures contracts in an attempt to manage its price risk. Monthly
settlements on these financial instruments are typically based on differences
between the fixed prices specified in the instruments and the settlement price
of certain future contracts quoted on the NYMEX or certain other indices. The
instruments used by the Company for oil hedges have not contained a contractual
obligation which requires or allows the future physical delivery of the hedged
products.
F-15
53
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
9. DERIVATIVES, SALES CONTRACTS AND SIGNIFICANT CUSTOMERS: (CONTINUED)
At December 31, 1999, the following hedge positions were in place.
Type Floor Cap Price From To Volume
- ---- ----- --- ----- ---- -- ------
Crude Oil Collar $17.00 $20.00 NA 1/1/00 12/31/00 12,000 Bbl/Month
Crude Oil Swap NA NA $20.05 1/1/00 6/30/00 12,000 Bbl/Month
Crude Oil Collar $20.00 $23.00 NA 7/1/00 9/30/00 6,000 Bbl/Mo
Natural Gas Swap NA NA $2.010
(Questar Index) 10/1/99 9/30/00 700 MMBtu/Day
Natural Gas Swap NA NA $2.2275
(Houston Ship Channel
Index) 8/1/99 3/31/00 1,000 MMBtu/Day
Natural Gas Swap NA NA $2.2425 4/1/00 3/31/01 1,000 MMBtu/Day
Additional hedge positions were contracted subsequent to December 31, 1999.
Type Floor Cap Price From To Volume
- ---- ----- --- ----- ---- -- ------
Crude Oil Collar $23.00 $31.70 NA 7/1/00 9/30/00 4,000 Bbl/Mo
Crude Oil Collar $22.00 $27.00 NA 10/1/00 12/31/00 10,000 Bbl/Mo
The Company has historically sold its oil production under long-term
contracts calling for a purchaser posted price or NYMEX price and an adjustment
deduction. These contracts have expired and have been extended or re-negotiated
for shorter time periods. The Company currently markets its crude oil either
month-to-month or a longer term basis up to six months. During the years ended
December 31, 1999, 1998 and 1997, Company oil sales volumes totaled
approximately 230 MBbls, 262 MBbls and 252 MBbls, respectively, at an average
sales price per Bbl, exclusive of the impact of hedging, for each year of
$16.53, $9.65 and $15.52, respectively.
Natural gas in Utah is sold through a long-term contract because of the
need for firm pipeline transportation. The contract expires June 2003. The price
for the natural gas is based on an Inside FERC index. Natural gas in Texas is
sold under an annual, renewable contract. A contract of this shorter duration is
more valuable to the purchaser and, in turn, yields a better price to the
Company. For the years ended December 31, 1999, 1998 and 1997, the Company sold
630 MMcf, 680 MMcf and 537 MMcf, respectively at an average price per Mcf,
exclusive of the impact of hedging, for each year of $2.14, $2.01 and $2.08,
respectively.
There is a call on all of the Company's share of oil production from
the Antelope Creek Field, which has priority over all other sales contracts.
Under the terms of the Oil Production Call Agreement (the "Call Agreement"),
which the Company assumed in connection with its acquisition of its initial
interest in the Antelope Creek Field, a purchaser has the option to purchase all
or any portion of the oil produced from the Antelope Creek field at the current
market price for the gravity and type of oil produced and delivered by the
Company. The Call Agreement was assumed by the Company on the date it acquired
its interest in the Antelope Creek Field and has no expiration date. In the
event the call option is exercised, the Company will not be penalized under its
other sales contracts for failure to deliver volumes thereunder.
SIGNIFICANT CUSTOMERS
The Company's revenues are derived principally from uncollateralized
sales to customers in the oil and gas industry. The concentration of credit risk
in a single industry affects the Company's overall exposure to credit risk
because customers may be significantly affected by changes in economic and other
conditions. In addition, the Company sells a significant portion of its oil and
natural gas revenue each year to a few customers. Oil sales to two purchasers in
1999 were approximately 40% and 26% of total 1999 oil and gas revenues. Natural
gas sales to two purchasers in 1999 were approximately 13% each of total 1999
oil and natural gas revenues. Oil sales to two purchasers in 1998 were
F-16
54
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
9. DERIVATIVES, SALES CONTRACTS AND SIGNIFICANT CUSTOMERS: (CONTINUED)
approximately 30% and 9% of total 1998 oil and gas revenues. Natural gas sales
to one purchaser in 1998 were approximately 25% of total oil and natural gas
revenues. Oil sales to three purchasers in 1997 were approximately 24%, 23% and
22% of total 1997 oil and gas revenues. Natural gas sales to one purchaser in
1997 were approximately 18% of total oil and natural gas revenues.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Because of their short-term maturity, the fair value of cash and cash
equivalents, certificates of deposit, accounts receivable and accounts payable
approximate their carrying values at December 31, 1999 and 1998. The fair value
of the Company's bank borrowings approximate their carrying value because the
borrowings bear interest at market rates. The fair value of the Company's
subordinated loans approximate their carrying value because the loans bear
interest at market rates and are reflected net of the value assigned to
associated stock warrants. The Company does not have any investments in debt or
equity securities as of December 31, 1999 or 1998. The fair value of the
Company's outstanding oil price swap arrangement, described in the preceding
note, has an estimated fair value of $857,000 and $648,000 at December 31, 1999
and 1998, respectively. These estimates are based on quoted market values.
11. INCENTIVE PLAN:
DESCRIPTION OF PLAN
The Board of Directors and the stockholders of the Company approved the
adoption of the Company's 1997 Incentive Plan (the "1997 Incentive Plan")
effective as of the completion of the Offering. The purpose of the 1997
Incentive Plan is to reward selected officers and key employees of the Company
and others who have been or may be in a position to benefit the Company,
compensate them for making significant contributions to the success of the
Company and provide them with proprietary interest in the growth and performance
of the Company. Participants in the 1997 Incentive Plan are selected by the
Compensation Committee of the Board of Directors from among those who hold
positions of responsibility and whose performance, in the judgment of the
Compensation Committee, can have a significant effect on the success of the
Company.
In October 1998, the Board of Directors of the Company approved an
amendment to the 1997 Incentive Plan, increasing the number of shares available
for grant from 375,000 to 605,000. The amendment was approved by the
stockholders of the Company at the annual stockholders meeting held on May 26,
1999. As of December 31, 1999, options to purchase 420,000 shares of Common
Stock are granted and outstanding. Based upon the provisions of the 1997
Incentive Plan, all options outstanding at the Change of Control automatically
vested. As a result, all 420,000 options outstanding under the 1997 Incentive
Plan are currently vested.
F-17
55
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
11. STOCK INCENTIVE PLAN: (CONTINUED)
The following table summarizes information about Petroglyph's stock
option activity between periods and the number of stock options which were
outstanding, and those which were exercisable, as of December 31, 1999, 1998 and
1997.
GRANT EXPIRATION EXERCISE OPTIONS OPTIONS OPTIONS
DATE DATE PRICE AUTHORIZED ISSUED VESTED
---- ---- ----- ---------- ------ ------
STOCK OPTIONS AUTHORIZED UNDER
1997 INCENTIVE PLAN 375,000
Issued 11/1/97 11/1/07 $12.50 337,000
----------- -----------
TOTAL OPTIONS AT 12/31/97 375,000 337,000 18,722
=========== =========== ==========
STOCK OPTIONS AUTHORIZED UNDER
1998 AMENDMENT TO 1997 INCENTIVE
PLAN 230,000
Surrendered $12.50 (23,000)
Issued 10/19/98 10/19/08 $ 5.00 280,000
----------- -----------
TOTAL OPTIONS AT 12/31/98 605,000 594,000 140,000
=========== =========== ==========
Surrendered $12.50 (104,000)
Surrendered $ 5.00 (70,000)
-----------
TOTAL OPTIONS AT 12/31/99 605,000 420,000 420,000
=========== =========== ==========
Pursuant to the 1997 Incentive Plan, participants will be eligible to
receive awards consisting of (i) stock options, (ii) stock appreciation rights,
(iii) stock, (iv) restricted stock, (v) cash, or (vi) any combination of the
foregoing. Stock options may be either incentive stock options within the
meaning of Section 422 of the Internal Revenue Code of 1986, as amended, or
nonqualified stock options.
PRO FORMA EFFECT OF RECORDING STOCK-BASED COMPENSATION AT ESTIMATED FAIR VALUE
(UNAUDITED)
The following table presents the 1998 and 1997 pro forma loss available
to common stock and loss per common share for the periods indicated as if
stock-based compensation had been recorded at the estimated fair value of stock
awards at the grant date, as prescribed by SFAS No. 123 (Note 2):
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, 1999 DECEMBER 31, 1998 DECEMBER 31, 1997
----------------- ----------------- -----------------
Loss available to common stock
As reported .................. $ (1,566,568) $ (4,185,807) $ (2,412,634)
Pro forma .................... $ (2,262,549) $ (4,633,833) $ (2,492,007)
Loss per common share
As reported, basic and diluted $ (.29) $ (.77) $ (.73)
Pro forma, basic and diluted . $ (.41) $ (.85) $ (.75)
F-18
56
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
11. STOCK INCENTIVE PLAN: (CONTINUED)
The fair value of the options, as determined using the Black-Scholes
pricing model were $2.63 and $6.95 for the options issued during 1998 and 1997,
respectively. The assumptions used in calculating the values are set forth in
the following table:
1998 1997
---- ----
Risk free interest rate 4.62% 5.89%
Expected life 7 years 7 years
Expected volatility 43.59% 45.24%
Expected dividends 0 0
12. COMMITMENTS AND CONTINGENCIES:
LEASES
In the second quarter of 1999, the Company sold is compression
equipment in Utah and Texas to Universal Compression, Inc. The Company then
executed a Master Rental Contract whereby Universal Compression will supply
equipment to meet the Company's natural gas compression requirements. The rental
agreements provide for fixed monthly payments of $29,730 for three years in Utah
and $19,780 for two years in Texas and annual redeterminations thereafter. In
1999 $415,860 in compressor rentals plus associated use taxes has been included
in lease operating expense in the accompanying Statements of Operations.
The Company leases offices and office equipment in its primary
locations under non-cancelable operating leases. As of December 31, 1999, annual
minimum future lease payments for all non_cancelable lease agreements, including
compression, are $669,084, $436,231, and $118,920, for 2000, 2001, and 2002,
respectively.
Exclusive of the compressor rentals discussed above, amounts incurred
by the Company under operating leases (including renewable monthly leases) were
$123,764, $91,042, and $53,383, in 1999, 1998, and 1997, respectively.
LITIGATION
The Company and its subsidiaries are involved in certain litigation and
governmental proceedings arising in the normal course of business. Company
management and legal counsel do not believe that ultimate resolution of these
claims will have a material adverse effect on the Company's financial position
or results of operations.
Mark Lively v. Petroglyph Operating Company, Inc.
The Company is a defendant in a lawsuit filed on or about December 22,
1999, by Mark Lively ("Lively"), wherein Lively seeks an order from the court
evicting the Company from a portion of Lively's property that contains four of
the Company's Raton Basin coalbed methane gas wells. Lively also seeks to
recover attorney fees and costs incurred in connection with the lawsuit. The
Company is vigorously defending itself and has requested that its costs incurred
in connection with the lawsuit be paid by Lively. The Company does not believe
that the resolution of this matter would have a material adverse effect on the
Company's financial position or results of operations.
F-19
57
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
12. COMMITMENTS AND CONTINGENCIES: (CONTINUED)
OTHER COMMITMENTS
During July, 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately 37
miles of 10-inch steel pipeline from near Trinidad, Colorado, to the Company's
Raton Basin coalbed methane development area approximately 6 miles southwest of
Walsenburg, Colorado. The pipeline was placed in service in January 1999, with a
delivery capacity of approximately 50 MMcf per day and will provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity which began February 1,
1999, and ends January 31, 2009. The commitment began at a minimum volume of
2,000 Mcf per day and increases by 1,000 Mcf per day after each three-month
period, with a maximum commitment of 10,000 Mcf per day. At the end of the first
two-year period, the Company has the option to increase the minimum volume or
eliminate the commitment. The cost of eliminating the commitment is the cost of
the pipeline ($6.4 million) less credit applied for the Company's Raton Basin
commercial gas production up to 16,000 Mcf per day. This cost could be applied
as a credit to transportation elsewhere on CIG's system. Subject to certain
restrictions, the Company can reduce the minimum monthly commitment by selling
its available pipeline capacity at market rates. In connection with the minimum
volume commitment, the Company paid $254,000 to CIG under this contract for the
year ending December 31, 1999.
In December 1996, the Company entered into an agreement with an
industry partner whereby the industry partner would pay for the costs of a 3-D
seismic survey on the Company's leasehold interests in the Helen Gohlke field,
located in Victoria and DeWitt Counties of South Texas. In exchange for such
costs, the industry partner has the right to earn a 50% interest in the
leasehold rights of the Company in the Helen Gohlke field. The industry partner
is required to pay 50% of the costs to drill and complete any wells in the area
covered by the seismic survey, and in exchange, will earn a 50% interest in the
well and in certain acreage surrounding the well. The amount of such surrounding
acreage in which the industry partner will earn an interest is to be determined
based upon the depth of the well drilled.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to environmental
protection, including the generation, storage, handling, emission,
transportation and discharge of materials into the environment, and relating to
safety and health. The recent trend in environmental legislation and regulating
generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction of drilling commences and for certain other
activities, limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various of the Company's operations are subject to
revocation, modification and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations, and
violations are subject to fines or injunction, or both. In the opinion of
management, the Company is in substantial compliance with current applicable
environmental laws and regulations, and the Company has no material commitments
for capital expenditures to comply with existing environmental requirements.
Nevertheless, changes in existing environmental laws and regulations or in
interpretations thereof could have a significant impact on the Company, as well
as the oil and natural gas industry in general.
13. SUBSEQUENT EVENTS
On February 15, 2000, the stockholders of the Company approved the
issuance of 250,000 shares of Series A Convertible Preferred Stock (the
"Preferred Shares") to III Exploration Company in exchange for certain producing
oil and gas properties primarily located in the Uinta Basin of Utah (the "III
Exploration Purchase"). The stockholders of the Company also approved the
issuance of shares of Common Stock upon the potential conversion of the
Preferred Shares.
The Preferred Shares will be convertible, beginning two years from the
date of issuance, into shares of Common Stock at a conversion price of $3.50 per
share of Common Stock, based on the preference amount of $10.00 per Preferred
Share. The Company has the option to redeem the Preferred Shares at any time
after the third anniversary of the transaction
F-20
58
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
13. SUBSEQUENT EVENTS: (CONTINUED)
closing date in whole or in part at a redemption price of $12.00 per Preferred
Share. The Preferred Shares are being issued pursuant to an exemption from the
registration requirement under the Securities Act and will be subject to
transfer restrictions imposed by the Securities Act.
The Company anticipates that the III Exploration Purchase will provide
cash flow of approximately $900,000 during the first year and that proved
developed producing reserves will increase 15%, or 400,000 BOE, from December
31, 1999 levels.
The effective date of the Purchase was November 1, 1999. The
transaction was closed on February 18, 2000.
14. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES:
COSTS INCURRED RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1999 1998 1997
----------- ----------- -----------
Acquisition
Unproved Properties ...... $ 1,320,105 $ 7,141,142 $ 1,721,636
Proved Properties ........ 7,120,952 42,533 147,387
Development .................... 1,038,257 10,123,616 10,003,468
Exploration .................... 38,640 192,526 --
Improved recovery costs ........ -- -- 895,317
----------- ----------- -----------
Total ............. $ 9,517,954 $17,499,817 $12,767,808
=========== =========== ===========
PROVED RESERVES
Independent petroleum engineers have estimated the Company's proved oil
and natural gas reserves as of December 31, 1999, 1998 and 1997, all of which
are located in the United States. Proved reserves are the estimated quantities
that geologic and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are the quantities expected to
be recovered through existing wells with existing equipment and operating
methods. Due to the inherent uncertainties and the limited nature of reservoir
data, such estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production of these
reserves may be substantially different from the original estimate. Revisions
result primarily from new information obtained from development drilling and
production history and from changes in economic factors.
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows
("standardized measure") and changes in such cash flows are prepared using
assumptions required by the Financial Accounting Standards Board. Such
assumptions include the use of year-end prices for oil and natural gas and
year-end costs for estimated future development and production expenditures to
produce year-end estimated proved reserves. Discounted future net cash flows are
calculated using a 10%
F-21
59
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
14. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES: (CONTINUED)
rate. Estimated future income taxes are calculated by applying year-end
statutory rates to future pre-tax net cash flows, less the tax basis of related
assets and applicable tax credits.
The standardized measure does not represent management's estimate of
the Company's future cash flows or the value of the proved oil and natural gas
reserves. Probable and possible reserves, which may become proved in the future,
are excluded from the calculations. Furthermore, year-end prices used to
determine the standardized measure of discounted cash flows are influenced by
seasonal demand and other factors and may not be the most representative in
estimating future revenues or reserve data.
OIL NATURAL GAS
(BBLS) (MCF)
-------------- --------------
PROVED RESERVES (UNAUDITED):
December 31,1996 ......................................... 6,127,136 18,812,463
Revisions .................................... 558,350 (2,895,611)
Extensions, additions and discoveries ........ 3,168,390 5,939,453
Production ................................... (251,631) (537,466)
Purchases of reserves ........................ 10,245 269,323
Sales in place ............................... (156,675) (892,712)
-------------- --------------
December 31,1997 ......................................... 9,455,815 20,695,450
Revisions .................................... (3,686,673) (7,358,640)
Extensions, additions and discoveries ........ 937,164 2,835,622
Production ................................... (261,817) (679,992)
Purchases of reserves ........................ -- --
Sales in place ............................... (17,329) --
-------------- --------------
December 31,1998 ......................................... 6,427,160 15,492,440
Revisions .................................... 3,054,195 9,198,718
Extensions, additions and discoveries ........ -- 476,777
Production ................................... (229,651) (630,186)
Purchases of reserves ........................ 9,236,996 18,894,461
Sales in place ............................... -- --
-------------- --------------
December 31,1999 ......................................... 18,488,700 43,432,210
============== ==============
PROVED DEVELOPED RESERVES:
December 31,1996 ......................................... 865,018 3,010,401
December 31,1997 ......................................... 4,742,028 10,839,164
December 31,1998 ......................................... 5,319,768 12,670,033
December 31,1999 ......................................... 10,459,030 24,320,120
============== ==============
F-22
60
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
14. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES: (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED)
DECEMBER 31,
-------------------------------------------------------
1999 1998 1997
------------- ------------- -------------
Future cash inflows .................................... $ 499,812,849 $ 84,010,748 $ 169,302,079
Future costs:
Production ........................................ (108,699,353) (25,826,978) (50,913,842)
Development ....................................... (44,729,910) (5,823,801) (19,151,264)
------------- ------------- -------------
Future net cash flows before income tax ................ 346,383,586 52,359,969 99,236,973
Future income tax ...................................... (113,359,897) (8,767,729) (22,247,206)
------------- ------------- -------------
Future net cash flows .................................. 233,023,689 43,592,240 76,989,767
10% annual discount .................................... (128,359,443) 19,398,715 (42,836,688)
------------- ------------- -------------
Standardized Measure ................................... $ 104,664,246 $ 24,193,525 $ 34,153,079
============= ============= =============
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
DECEMBER 31,
-------------------------------------------------------
1999 1998 1997
------------- ------------- -------------
Standardized Measure, Beginning of Period .............. $ 24,193,525 $ 34,153,079 $ 48,024,088
Revisions:
Prices and costs .................................. 41,769,947 (32,472,461) (26,476,631)
Quantity estimates ................................ 38,374,712 2,814,596 380,840
Accretion of discount ............................. 2,905,978 4,346,915 6,484,830
Future development cost ........................... (13,125,359) 7,332,602 (1,869,101)
Income tax ........................................ (41,752,296) 5,201,663 7,508,139
Production rates and other ........................ (20,963,016) (6,027,000) (8,545,510)
------------- ------------- -------------
Net revisions ................................ 7,209,966 (18,803,685) (22,517,433)
Extensions, additions and discoveries .................. 555,914 6,061,487 12,757,280
Production ............................................. (1,499,116) (2,132,680) (3,372,040)
Development costs ...................................... 737,180 5,031,367 --
Purchases in place ..................................... 73,466,777 -- 397,644
Sales in place ......................................... -- (116,043) (1,136,460)
------------- ------------- -------------
Net change ........................................ 80,470,721 (9,959,554) (13,871,009)
Standardized Measure, End of Period .................... $ 104,664,246 $ 24,193,525 $ 34,153,079
============= ============= =============
Year-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $22.37, $8.04 and
$13.46 per Bbl at December 31, 1999, 1998, and 1997, respectively. Year-end
weighted average gas prices were $1.99, $2.09 and $2.03 per Mcf at December 31,
1999, 1998, and 1997, respectively.
The Company uses hedging strategies to minimize the Company's exposure
to product price risk. The impact of hedging contracts is reflected in the
Company's reserve report . The 1999 and 1998 weighted average oil prices include
the impact of hedging contracts in pricing assumptions in place at December 31,
1999 and 1998 for those projected barrels under contract. The weighted average
oil price, excluding hedges would have been $22.41 in 1999 and $7.80 in 1998.
F-23
61
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
2 Exchange Agreement (filed as Exhibit 2 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
3.1 Certificate of Incorporation (filed as Exhibit 3.1 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
3.2 Bylaws (filed as Exhibit 3.2 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
4.1 Form of Common Stock Certificate (filed as Exhibit 4 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
4.2 NotePurchase Agreement dated as of August 20, 1999, by and
between Petroglyph Energy, Inc. and III Exploration Company
(filed as Exhibit 4.1 to the Company's Current Report on Form
8-K filed September 2, 1999, and incorporated by reference
herein).
4.3 Warrant Agreement among III Exploration Company and Petroglyph
Energy, Inc. dated as of August 20, 1999 (filed as Exhibit 99.5
to the Schedule 13D filed by Intermountain Industries, Inc., III
Exploration Company, Century Partners and Richard Hokin on
August 30, 1999, and incorporated herein by reference).
10.1 Stockholders Agreement (filed as Exhibit 10.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.2 Registration Rights Agreement (filed as Exhibit 10.2 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
10.3 Financial Advisory Services Agreement (filed as Exhibit 10.3 to
the Company's Registration Statement on Form S-1, Registration
No. 333-34241, and incorporated herein by reference).
10.4 1997 Incentive Plan (filed as Exhibit 10.4 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.5 Form of Confidentiality and Noncompete Agreement between the
Company and each of its executive officers (filed as Exhibit
10.5 to the Company's Registration Statement on Form S-1,
Registration No. 333-34241, and incorporated herein by
reference).
10.6 Form of Indemnity Agreement between the Company and each of its
executive officers (filed as Exhibit 10.6 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.7 Amended and Restated Loan Agreement, dated September 15, 1997,
among Petroglyph Gas Partners, L.P., Petroglyph Energy, Inc. and
The Chase Manhattan Bank (filed as Exhibit 10.7 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
62
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
10.8 Cooperative Plan of Development and Operation for the Antelope
Creek Enhanced Recovery Project, Duchesne County, Utah, dated as
of February 17, 1994, by and between Petroglyph Operating
Company, Inc., Inland Resources, Inc., Petroglyph Gas Partners,
L.P., Ute Indian Tribe and Ute Distribution Corporation (filed
as Exhibit 10.12 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.9 Exploration and Development Agreement between The Ute Indian
Tribe, The Ute Distribution Corporation and Petroglyph Gas
Partners, L.P. (filed as Exhibit 10.13 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.10 Antelope Creek Unit Participation Agreement, dated as of June 1,
1996, by and between Petroglyph Operating Company, Inc.,
Petroglyph Gas Partners, L.P. and CoEnergy Enhanced Production,
Inc. (filed as Exhibit 10.14 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
10.11 Unit Operating Agreement Unit, dated June 1, 1996, by and
between Petroglyph Operating Company, Inc., Petroglyph Gas
Partners, L.P. and CoEnergy Enhanced Production, Inc. (filed as
Exhibit 10.15 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.12 Water Agreement, dated October 1, 1994, between East Duchesne
Culinary Water Improvement District and Petroglyph Operating
Company, Inc. (filed as Exhibit 10.16 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.13 Asset Purchase and Sale Agreement, dated May 15, 1997, among
Infinity Oil & Gas, Inc. and PGP II, L.P. (filed as Exhibit
10.17 to the Company's Registration Statement on Form S-1,
Registration No. 333-34241, and incorporated herein by
reference).
10.14 Lease Agreement between Hutch Realty, L.L.C. and Petroglyph
Operating Company, Inc. (filed as Exhibit 10.18 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.15 Letter dated August 21, 1997, from Hutch Realty, L.L.C. to
Petroglyph Operating Company, Inc. concerning renewal of Lease
Agreement (filed as Exhibit 10.19 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
10.16 Warrant Agreement, dated September 15, 1997, among The Chase
Manhattan Bank, Petroglyph Gas Partners, L.P. and Petroglyph
Energy, Inc. (filed as Exhibit 10.20 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
10.17 Registration Rights Agreement, dated September 15, 1997, between
The Chase Manhattan Bank and Petroglyph Energy, Inc. (filed as
Exhibit 10.21 to the Company's Registration Statement on Form
S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.18 Guaranty dated September 15, 1997, by Petroglyph Energy, Inc. in
favor of The Chase Manhattan Bank (filed as Exhibit 10.22 to the
Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
10.19 First Firm Transportation Service Agreement, dated July 1, 1998,
between Petroglyph Energy, Inc. and Colorado Interstate Gas
Company (filed as Exhibit 10.19 to the Company's 1998 Annual
Report on Form 10K filed March 31, 1999, and incorporated herein
by reference).
10.20 Second Firm Transportation Service Agreement, dated July 1,
1998, between Petroglyph Energy, Inc. and Colorado Interstate
Gas Company (filed as Exhibit 10.20 to the Company's 1998 Annual
Report on Form 10K filed March 31, 1999, and incorporated herein
by reference).
63
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
10.21 Interruptible Transportation Service Agreement, dated January 1,
1999, between Petroglyph Energy, Inc. and Colorado Interstate
Gas Company (filed as Exhibit 10.21 to the Company's 1998 Annual
Report on Form 10-K filed March 31, 1999, and incorporated
herein by reference).
10.22 Form of Severance Agreement as entered into effective as of
December 1, 1998, by and between Petroglyph Energy, Inc. and
each of Robert C. Murdock, Robert A. Christensen, S. Kennard
Smith and Tim A. Lucas (filed as Exhibit 10.22 to the Company's
1998 Annual Report on Form 10-K filed March 31, 1999, and
incorporated herein by reference).
10.23 Amendment No. 1, dated August 20, 1999, to Second Amended and
Restated Loan Agreement among Petroglyph Gas Partners, L.P.,
Petroglyph Energy, Inc. and The Chase Manhattan Bank (filed as
Exhibit 10.1 to the Company's Current Report on Form 8-K filed
September 2, 1999, and incorporated by reference herein).
10.24 Purchase and Sale Agreement between III Exploration Company and
the Company dated December 28, 1999 (filed as Exhibit 10.1 to
the Company's Current Report on Form 8-K filed December 30,
1999, and incorporated by reference herein).
10.25 Subscription Agreement between III Exploration Company and the
Company dated December 28, 1999 (filed as Exhibit 10.1 to the
Company's Current Report on Form 8-K filed December 30, 1999,
and incorporated by reference herein).
21 Subsidiaries of the Registrant (filed as Exhibit 21 to the
Company's 1998 Annual Report on Form 10-K filed March 31, 1999,
and incorporated by reference herein).
23.1 Consent of Lee Keeling and Associates, Inc., independent reserve
engineers.
27 Financial Data Schedule.