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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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________ TO ______________
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:
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NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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None None
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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 23, 1999, the Registrant had outstanding 5,458,333 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 23, 1999, as reported on the Nasdaq National Market, was
approximately $4,594,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Stockholders to be held on May 26, 1999 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, 1998.
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TABLE OF CONTENTS
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PART I
Item 1. Business...............................................................................1
Item 2. Properties.............................................................................7
Item 3. Legal Proceedings.....................................................................11
Item 4. Submission of Matters to a Vote of Security Holders...................................11
Executive Officers of the Registrant...............................................................12
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.................13
Item 6. Selected Financial Data...............................................................14
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................................15
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.............................27
Item 8. Consolidated Financial Statements and Supplementary Data..............................27
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..................................................................27
PART III
Item 10. Directors and Executive Officers of the Registrant....................................27
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.
1998 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, including Petroglyph Gas
Partners, L.P. 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 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 up to $3 million in 1999 in connection with these projects, but has
postponed aggressive development in the area until oil prices improve to more
favorable levels. 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
ultimately have the potential to be commercially productive. In addition to its
Uinta Basin activities, the Company recently developed a pilot coalbed methane
project on its 76,600 gross and net acres in the Raton Basin in Colorado.
Management believes the 17 well pilot area will be sufficient to determine the
commercial viability of the area. The pilot area is currently producing 23,000
barrels of water per day as the Company attempts 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. The Company is actively drilling shallow gas
wells in the area, and plans to spend up to an additional $1.0 million on four
gross (3 net) wells on the acreage early in 1999. The Company is also making
this non-core property available for sale for the purpose of reducing its level
of debt and to improve its ability to respond to potential acquisition
opportunities.
Using an average realized price of $8.04 per barrel for oil and $2.09 per
Mcf for gas, as of December 31, 1998, the Company had estimated net proved
reserves of approximately 6.4 MMBbls of oil and 15.5 Bcf of natural gas, or an
aggregate of 9.0 MMBOE with a PV-10 of $28.3 million. Of the Company's estimated
proved reserves, 96% are located in the Uinta Basin. The Company has not
included any reserves from its Raton Basin development in proved categories, as
the pilot area is in the dewatering process. When commercial quantities of Raton
Basin gas are produced, the associated probable reserves will be classified in
proved categories. At December 31, 1998, the Company had a total acreage
position of approximately 133,000 gross (121,000 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 of additional property interests, and
(v) the development of a strong financial position that affords the Company the
financial flexibility to execute its business strategy.
The Company intends to pursue acquisitions of producing reserves in other
U.S. basins where the Company can employ economies of scale, focused operations
and operating expertise to give it a competitive advantage in pursuing further
consolidation and acquisition opportunities.
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
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grew primarily through acquisition of oil and natural gas properties and the
development of such properties. Under the exchange agreement, effective upon
consummation of its initial public offering (the "Offering"), (i) the limited
partners of the partnership transferred all of their limited partnership
interests 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
Energy, Inc. owned, 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.
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, particularly the manufacturing
sector, 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.
In June 1994, the Company entered into a contract to sell its oil
production from certain leases of its Utah properties to an industry
participant. The price under this contract is agreed upon monthly and is
generally based on such purchaser's posted prices. This contract will continue
in effect until terminated by either party upon giving proper notice. During the
years ended December 31, 1998, 1997 and 1996, the volumes sold under this
contract totaled approximately 125 MBbls, 74 MBbls and 61 MBbls, respectively,
at an average sales price per Bbl for each year of $9.27, $14.80 and $19.33,
respectively.
In July 1997, the Company entered into a modification of its crude oil
sales contract to sell its black wax crude oil production from the Antelope
Creek field to a major oil company at a price equal to posting, less an agreed
upon adjustment to cover handling and gathering costs. This contract will
continue in effect until terminated by either party upon giving proper notice.
For the years ended December 31, 1998 and 1997, the Company sold 38 MBbls and 70
MBbls, respectively, under this contract at an average price of $9.04 and $16.58
per Bbl, respectively.
In June 1997, the Company entered into a crude oil contract to sell black
wax production from certain of its oil tank batteries in the Antelope Creek
Field in Utah to a refinery. This contract expired May 31, 1998 and called for
the Company to receive a price equal to the current month NYMEX closing price
for sweet crude, averaged over the month in which the crude is sold, less an
agreed upon adjustment. Volumes sold under this contract totaled 25 MBbls and 73
MBbls at an average price of $12.88 and $14.50 for the year ended December 31,
1998 and 1997, 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 has 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 beginning February 1, 1999,
and ending
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January 31, 2009. The commitment begins 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. The Company can reduce the minimum
monthly commitment by selling its available pipeline capacity at market rates.
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 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 the future physical delivery of the hedged products. While use of these
hedging arrangements limits the downside risk of price declines, such
arrangements also limit the benefits which may be derived from price increases.
Approximately 159 MBbls and 72 MBbls of the Company's expected oil
production through December 31, 1999 and 2000, respectively, was subject to
collars at December 31, 1998 with NYMEX floor prices of $17.00 and $14.00 and
ceiling prices of $22.00 and $16.00 based on 1999 and 2000 NYMEX pricing,
respectively. During March 1999, the Company liquidated the hedge contract
covering 72 MBbls in the year 2000 for approximately $16,000.
The Company monitors oil markets and the Company's actual performance
compared to the estimates used in 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 in the Uinta Basin, the Raton Basin and in other areas that provide
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, 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 structural 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.
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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 for its Uinta Basin properties 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
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 State of Utah and many other states
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. 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.
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.
Proceedings on remanded issues are currently ongoing at FERC. In addition,
numerous parties have filed for review of Order 636 as well as orders in
individual pipeline restructuring proceedings. Because these orders may be
modified as a result of the appeals, it is difficult to predict the ultimate
impact of the orders on the Company and its natural gas marketing efforts.
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.
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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 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 an environmental impact statement 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
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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 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 two years, 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. This building is currently held for sale.
EMPLOYEES
As of December 31, 1998, the Company had 47 full-time employees, none of
whom is represented by any labor union. Included in the total were 16 corporate
employees located in the Company's office in Hutchinson, Kansas. The Company
considers its relations with its employees to be good.
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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 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 76,600 gross and 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. Upon the drilling and completion
of the pilot area, 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. Currently, the Company is removing water at
a rate of 23,000 barrels per day. The Company intends to maximize the water
withdrawal rate in order to accelerate the potential for commercial quantities
of methane gas production in 1999. When several of the seventeen wells have
achieved minimum commercial production levels of gas, the Company will evaluate
additional development within the field. The Company is interested in selling up
to a 50% working interest in its Raton Basin assets if a favorable offer can be
obtained.
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. The Company is actively drilling shallow gas wells in the area, and plans
to spend up to an additional $1.0 million on four gross (3 net) wells on the
acreage early in 1999. The Company is also making this non-core property
available for sale. Proceeds from such sale are expected to be utilized to
reduce debt and to improve the Company's ability to respond to potential
acquisition opportunities.
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, 1998,
1997 and 1996:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------------------------------------------------
1998 1997 1996
----------------------- ----------------------- ---------------------
NATURAL NATURAL NATURAL
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
--------- --------- --------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed:
Utah........................... 5,260 10,686 4,620 9,202 568 1,600
Other.......................... 60 1,984 122 1,637 297 1,410
--------- --------- --------- --------- -------- --------
Total................... 5,320 12,670 4,742 10,839 865 3,010
-------- -------- -------- -------- -------- --------
Proved undeveloped:
Utah........................... 1,107 2,822 4,714 9,856 5,262 15,802
-------- --------- -------- --------- -------- -------
Total................... 1,107 2,822 4,714 9,856 5,262 15,802
-------- --------- -------- --------- -------- -------
Total proved............ 6,427 15,492 9,456 20,695 6,127 18,812
======== ======== ======== ======== ======== =======
</TABLE>
7
<PAGE> 10
The following table sets forth the future net cash flows from the Company's
estimated proved reserves:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future net cash flow before income taxes:
Utah ............................................................ $ 49,992 $ 96,768 $117,101
Other ........................................................... 2,368 2,469 6,699
-------- -------- --------
Total .................................................... $ 52,360 $ 99,237 $123,800
======== ======== ========
Future net cash flow before income taxes, discounted at 10%:
Utah ............................................................ $ 26,581 $ 41,631 $ 59,447
Other ........................................................... 1,727 1,798 4,656
-------- -------- --------
Total .................................................... $ 28,308 $ 43,429 $ 64,103
======== ======== ========
</TABLE>
The reserve estimates for 1998 and 1997 were prepared by Lee Keeling and
Associates Inc., the Company's independent petroleum engineers. The reserve
estimates reflected above for 1996 were prepared by the Company.
The Company has not included any reserves from its Raton Basin development
in proved categories, as the pilot area is in the dewatering process. When
commercial quantities of Raton Basin gas are produced, 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 estimated to be 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 utilizing waterflood technology 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 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. The Company's
estimated proved reserves have not been filed with or included in reports to any
federal agency during the fiscal year ended December 31, 1998.
8
<PAGE> 11
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated. At December 31, 1998, the Company
was waiting to complete six gross and net Raton Basin wells as producers.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1998 1997 1996
---------------- -------------- -----------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil ..................... 1 1.0 2 2.0 -- --
Natural gas ............. 5 5.0 2 1.0 -- --
Nonproductive ........... 1 1.0 -- -- -- --
---- ----- --- ----- ---- -----
Total ............ 7 7.0 4 3.0 -- --
==== ===== === ===== ==== =====
Development:
Oil ..................... 26 13.0 52 26.0 38 19.0
Natural gas ............. 20 19.0 -- -- -- --
Nonproductive ........... 1 1.0 -- -- -- --
---- ----- --- ----- ---- -----
Total ............ 47 33.0 52 26.0 38 19.0
==== ===== === ===== ==== =====
Total:
Productive .............. 52 38.0 56 29.0 38 19.0
Nonproductive ........... 2 2.0 -- -- -- --
---- ----- --- ----- ---- -----
Total ................... 54 40.0 56 29.0 38 19.0
==== ===== === ===== ==== =====
</TABLE>
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, 1998 in productive oil and natural gas wells in the development
areas indicated.
<TABLE>
<CAPTION>
OIL NATURAL GAS TOTAL
-------------------- ------------------- -------------------
AREA GROSS NET GROSS NET GROSS NET
-------- -------- ------- ------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Utah:
Antelope Creek Field................... 94 47.0 -- -- 94 47.0
Duchesne Field......................... 3 3.0 -- -- 3 3.0
Natural Buttes Extension............... -- -- 2 1.5 2 1.5
-------- -------- ------- ------- ------ --------
Total........................... 97 50.0 2 1.5 99 51.5
Colorado.................................... -- -- 17 17.0 17 17.0
Other....................................... 3 3.0 4 2.0 7 5.0
-------- -------- ------- ------- ------ --------
Total........................... 100 53.0 23 20.5 123 73.5
======== ======== ======= ======= ====== ========
</TABLE>
9
<PAGE> 12
In addition, as of December 31, 1998, the Company had 37 gross (18.5 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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
---------- --------- ---------
<S> <C> <C> <C>
Net production (1):
Oil (Bbls)................................................................. 261,817 251,631 262,910
Natural gas (Mcf).......................................................... 679,992 537,466 553,770
Oil equivalent (BOE)....................................................... 375,149 341,209 355,205
Average sales price (2):
Oil (per Bbl):
Utah (3)............................................................... $ 11.01 $ 14.37 $ 15.82
Other.................................................................. 12.95 18.94 20.35
Weighted average (4)................................................... 11.12 14.84 16.96
Natural gas (per Mcf):
Utah................................................................... $ 2.12 $ 1.91 $ 1.64
Other.................................................................. 1.75 2.37 1.96
Weighted average....................................................... 2.01 1.99 1.80
Average lease operating expenses including production and property
taxes (per BOE):
Utah....................................................................... $ 5.06 $ 3.67 $ 5.21
Other...................................................................... 10.02 15.08 11.99
Weighted average........................................................... 5.72 5.09 7.37
</TABLE>
(1) The Company's 1997 oil and gas production volumes include the effect of the
sale of a 50% interest in its Antelope Creek properties in June 1996 and
the sale of certain non-strategic properties in late 1996 and early 1997.
(2) Before deduction of property taxes.
(3) 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 $9.44, $15.12, and $20.18 for the years
ended December 31, 1998, 1997 and 1996, respectively.
(4) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average sales price per Bbl of oil was
$9.65, $15.52 and $20.22 for the years ended December 31, 1998, 1997 and
1996, respectively.
10
<PAGE> 13
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties ............... $ 7,141,142 $ 1,721,636 $ 490,487
Proved properties ................. 42,533 147,387 --
Development costs ...................... 10,123,616 10,003,468 6,983,715
Exploration costs ...................... 192,526 -- --
Improved recovery costs ................ -- 895,317 327,027
----------- ----------- -----------
Total ......................... $17,499,817 $12,767,808 $ 7,801,229
=========== =========== ===========
</TABLE>
ACREAGE
The following table sets forth, as of December 31, 1998, the gross and net
acres of developed and undeveloped oil and natural gas leases which the Company
holds or has the right to acquire.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
--------------------- -------------------- ---------------------
AREA GROSS NET GROSS NET GROSS NET
--------- --------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Utah:
Antelope Creek Field................... 6,560 3,280 14,137 6,126 20,697 9,406
Duchesne Field......................... 1,400 1,067 13,215 12,482 14,615 13,549
Natural Buttes Extension............... 360 360 15,336 15,336 15,696 15,696
--------- --------- -------- -------- -------- --------
Total.............................. 8,320 4,707 42,688 33,944 51,008 38,651
--------- --------- -------- -------- -------- --------
Colorado.................................... 950 950 75,647 75,647 76,597 76,597
Other....................................... 5,210 4,900 441 441 5,651 5,341
--------- --------- -------- -------- -------- --------
Total.............................. 14,480 10,557 118,776 110,032 133,256 120,589
========= ========= ======== ======== ======== ========
</TABLE>
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any material legal proceedings.
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 1998.
11
<PAGE> 14
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, 1998:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Robert C. Murdock.................... 41 President, Chief Executive Officer and Chairman of the Board
Robert A. Christensen................ 52 Executive Vice President, Chief Technical Officer and Director
S. "Ken" Smith....................... 56 Executive Vice President, Chief Operating Officer and Secretary
Tim A. Lucas......................... 34 Vice President, Chief Financial Officer and Treasurer
</TABLE>
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.
Robert A. Christensen has served as Executive Vice President and Director
of the Company since its inception in April 1993, and currently functions as
Chief Technical Officer with primary responsibility for property acquisition
evaluations, business development and strategic alliance formation. From April
1993 to 1996, Mr. Christensen served as President of Petroglyph Operating
Company, Inc., a wholly owned operating subsidiary of the Company. From January
1992 to April 1993, Mr. Christensen was the President of Bishop Resources, Inc.,
where he was responsible for managing the oil and natural gas assets of the
company. From April 1988 to April 1993, Mr. Christensen was Manager of Project
Development for Management Resources Group, Ltd. From November 1985 to April
1988, Mr. Christensen was an independent consultant in engineering operations
and economic evaluations, primarily in Kansas. Prior to November 1985, Mr.
Christensen held various positions with independent oil and natural gas
exploration and production companies, as well as a major service company. He is
a member of the Society of Petroleum Engineers, the Society of Professional Well
Log Analysts and has completed the James M. Smith and William T. Cobb course in
waterflooding.
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.
12
<PAGE> 15
PART II
ITEM 5. MARKET FOR REGISTRANT'S 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.
<TABLE>
<CAPTION>
High Low
---- ---
1997:
<S> <C> <C>
October 20 to December 31 $ 13.625 $ 7.25
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 1.75
(through March 23)
</TABLE>
As of March 23, 1999, the Company estimates that there were more than 900
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.
13
<PAGE> 16
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."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(in thousands, except per share amounts and operating data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil sales ........................................... $ 2,912 $ 3,735 $ 4,459 $ 3,217 $ 1,644
Natural gas sales ................................... 1,366 1,070 999 1,016 796
Other ............................................... 190 61 -- 36 45
-------- -------- -------- -------- --------
Total operating revenues ........................ 4,468 4,866 5,458 4,269 2,485
-------- -------- -------- -------- --------
Operating expenses:
Lease operating ..................................... 1,927 1,560 2,369 2,260 1,601
Production taxes .................................... 218 179 249 188 89
Exploration costs ................................... 193 -- 69 376 70
Depreciation, depletion and amortization ............ 1,866 1,852 2,806 2,302 1,977
Impairments ......................................... 4,848 -- -- 109 --
General and administrative .......................... 2,129 1,300 902 1,064 956
-------- -------- -------- -------- --------
Total operating expenses ........................ 11,181 4,891 6,395 6,299 4,693
-------- -------- -------- -------- --------
Operating loss .......................................... (6,713) (25) (937) (2,030) (2,208)
Other income (expenses):
Interest income (expense), net ...................... 407 114 40 (216) (93)
Gain (loss) on sales of property and
equipment, net .................................. 59 12 1,384 (138) 44
-------- -------- -------- -------- --------
Net income (loss) before income taxes ................... (6,247) 101 487 (2,384) (2,257)
Income tax benefit (expense) (1) ........................ 2,062 (2,514) (190) -- --
-------- -------- -------- -------- --------
Net income (loss) ....................................... $ (4,185) $ (2,413) $ 297 $ (2,384) $ (2,257)
======== ======== ======== ======== ========
Supplemental earnings (loss) per
common share (2) ........................................ $ (.77) $ (.73) $ .11 $ (.84) $ (.80)
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in):
Operating activities ................................ $ (1,467) $ 1,633 $ 4,129 $ 347 $ (67)
Investing activities ................................ (20,535) (15,514) 303 (9,580) (8,131)
Financing activities ................................ 7,331 28,982 (3,930) 10,049 8,119
OTHER FINANCIAL DATA:
Capital expenditures .................................... $ 20,623 $ 16,260 $ 8,665 $ 10,443 $ 8,277
Adjusted EBITDA (3) ..................................... 253 1,839 3,322 619 (117)
Operating cash flow (4) ................................. 601 1,896 2,024 608 (233)
BALANCE SHEET DATA:
Cash and cash equivalents ............................... $ 2,008 $ 16,679 $ 1,578 $ 1,075 $ 258
Working capital ......................................... 1,952 14,873 (541) 1,133 113
Total assets ............................................ 46,035 46,714 17,470 17,598 9,685
Total long-term debt .................................... 7,500 -- 52 3,900 1,800
Total stockholders' equity .............................. 35,312 39,498 12,695 12,207 6,592
</TABLE>
(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.
(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, 1998 were 5,458,333 for 1998, 3,326,826 for 1997 and 2,833,333 (pro
forma) shares for 1996, 1995 and 1994.
14
<PAGE> 17
(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 $193,000, zero, $69,000, $376,000 and
$70,000 for each of the years ended December 31, 1998, 1997, 1996, 1995 and
1994, 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. MANAGEMENT'S 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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
PRODUCTION DATA(1):
Oil (Bbls).......................................................... 261,817 251,631 262,910
Natural Gas (Mcf)................................................... 679,992 537,466 553,770
Total (BOE)..................................................... 375,149 341,209 355,205
AVERAGE SALES PRICE PER UNIT(2):
Oil (per Bbl)(3).................................................... $ 11.12 $ 14.84 $ 16.96
Natural Gas (per Mcf)............................................... 2.01 1.99 1.80
BOE................................................................. 11.40 14.08 15.36
COSTS PER BOE:
Lease operating expense............................................. $ 5.14 $ 4.57 $ 6.67
Production and property taxes....................................... 0.58 .52 0.70
General and administrative.......................................... 5.67 3.81 2.54
Depreciation, depletion and amortization............................ 4.97 5.43 7.90
Average finding costs(4)............................................ 0.85 3.00 2.86
</TABLE>
- --------------------
(1) The Company's 1997 oil and gas production volumes include the effect of the
sale of a 50% interest in its Antelope Creek properties in June 1996 and
the sale of certain non-strategic properties in late 1996 and early 1997.
(2) Before deduction of production taxes.
(3) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average sales price per Bbl of oil was
$9.65, $15.52 and $20.22 for the years ended December 31, 1998, 1997 and
1996, respectively.
(4) The calculation of average finding costs for the years ended December 31,
1997 and 1996 includes a change in future development costs of $2.7 million
and $16.5 million, respectively. Average finding cost per BOE excluding
these amounts were $2.37 and $.85 for the years ended December 31, 1997 and
1996, respectively. The calculation of average finding cost for the year
ended December 31, 1998 includes a reduction in future
15
<PAGE> 18
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 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, 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
16
<PAGE> 19
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.
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.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
OPERATING REVENUES
Oil revenues decreased by 16% to $3,735,000 for the year ended December 31,
1997 as compared to $4,459,000 for 1996 primarily as a result of an 11,000 Bbl
decrease in the Company's oil production volume and a decline in average oil
sales prices from $16.96 per Bbl in 1996 to $14.84 in 1997. The decline in the
Company's oil production is due to the sale of a 50% interest in the Utah
properties in June 1996 and the sale of certain other non-strategic properties
between the third quarter of 1996 and the first quarter of 1997, partially
offset by increased production volume from the Company's remaining 50% interest
in the Utah properties as a result of the Company's aggressive drilling program
on its Utah properties beginning in the second half of 1996. The decline in
average oil sales price of $2.12 per Bbl was due to a reduction in demand for
the Company's production as a result of a temporary maintenance shutdown during
1996 and early 1997 of one of the refineries which is a primary user of the
Company's Utah production, a crude oil hedge loss of $132,000 and amortization
of deferred revenue of $46,000. The Company's average oil sales price for the
year ended December 31, 1997, excluding the effects of the hedge loss and
amortization of deferred revenue was $15.52 per Bbl.
Natural gas revenues increased by 7% to $1,070,000 for the year ended
December 31, 1997, as compared to $999,000 for 1996 primarily as a result of an
increase in the average natural gas sales price to $1.99 per Mcf during the year
ended December 31, 1997, as compared to $1.80 per Mcf for 1996. The increase in
natural gas prices was partially offset by a decline in natural gas production
of 16,000 Mcf primarily due to dispositions of certain non-strategic natural gas
properties during 1996, the sale of a 50% interest in the Utah properties in
June 1996 and the inception of the secondary oil recovery program on the
Company's Utah properties in mid-1996. These declines in natural gas production
volumes were offset by increased natural gas production volumes related to the
Company's remaining 50% interest in the Utah properties as a result of the
Company's aggressive drilling program on the properties beginning in the second
half of 1996.
OPERATING EXPENSES
Lease operating expenses decreased by 34% to $1,560,000 for the year ended
December 31, 1997, as compared to $2,369,000 for 1996 primarily as a result of
the sale of a 50% interest in the Company's Utah properties in June 1996 and the
sale of certain other non-strategic oil and natural gas properties between the
third quarter of 1996 and the first quarter of 1997, partially offset by an
increase in the number of producing wells in which the Company has an interest
due to the aggressive drilling program on the Company's Utah properties, which
began in the second half of 1996. In addition, the Company's lease operating
expenses on a per BOE basis declined by 31% to $4.57 per BOE during 1997 as
compared to $6.67 per BOE for 1996. This decline in lease operating expenses per
BOE is due to the benefits of improved economies of scale from increasing
production volumes from the Utah properties and the Company's continued focus on
reduction of operating costs through improved efficiencies. This decline was
partially offset by a significant increase in per BOE production costs of the
Company's non-Utah properties due to several workovers performed during 1997.
Depreciation, depletion and amortization expense decreased by 34% to
$1,852,000 for the year ended December 31, 1997, as compared to $2,806,000 for
1996 primarily as a result of a significant increase in proved reserves in 1997
as a result of the Company's aggressive drilling program which began in the
second half of 1996, the sale of the 50% interest in the Company's Utah
properties in June 1996 and the sale of certain other non-strategic oil and
natural gas properties in the third quarter of 1996 through the first quarter of
1997. These items were partially offset by increased production from the
Company's remaining interest in the Utah properties.
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<PAGE> 20
Exploration costs declined to zero for the year ended December 31, 1997 from
$69,000 for 1996, as all of the Company's exploratory drilling activities were
successful during the period and no geological and geophysical work was
performed.
General and administrative expenses increased by 44% to $1,300,000 for the
year ended December 31, 1997, as compared to $902,000 for 1996. This increase
was the result of an increase in engineering, geological and administrative
staff necessary for the increased development activity and increased accounting
staff needed to meet the increased reporting requirements associated with being
a public company.
OTHER INCOME (EXPENSES)
Interest income (expense) net, for the year ended December 31, 1997,
increased to $114,000 as compared to $40,000 in 1996 primarily as a result of
interest earned on the proceeds from the Offering, partially offset by an
increase in average outstanding debt during 1997.
Gain on sales of property and equipment declined to $12,000 for the year
ended December 31, 1997, as compared to $1,384,000 for 1996 due to gains
recognized from the sale of a 50% interest in the Company's Utah properties in
June 1996 and sales of non-strategic oil and gas properties in the third quarter
of 1996.
INCOME TAX EXPENSE
Income tax expense increased for the year ended December 31, 1997 to
$2,514,000 as compared to the pro forma amount of $190,000 for the same period
in 1996. This increase is due to the impact of a one-time, non-cash charge
associated with the adoption of SFAS No. 109, "Accounting for Income Taxes."
SFAS No. 109 required that the net deferred tax liabilities of the Company on
the date of the Conversion be recognized as a component of income tax expense.
The Company recognized $2,475,000 in net deferred tax liabilities and income tax
expense on the date of the Conversion.
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties ............. $ 7,141,142 $ 1,721,636 $ 490,487
Proved properties ............... 42,533 147,387 --
Development costs ...................... 10,123,616 10,003,468 6,983,715
Exploration costs ...................... 192,526 -- --
Improved recovery costs ................ -- 895,317 327,027
----------- ----------- -----------
Total .................................. $17,499,817 $12,767,808 $ 7,801,229
=========== =========== ===========
</TABLE>
Due to continued low oil prices, in the second quarter of 1998, the Company
shifted its focus from developing its Uinta Basin oil reserves to drilling and
exploiting its Raton Basin methane gas properties. The Company's 1999 waterflood
development plans in the Uinta Basin are limited by low oil prices and the
resulting cash flow constraints to maximizing injected water volumes through a
series of injector well conversions. The Company does not anticipate drilling
new producing wells in the Uinta Basin in 1999, but rather intends to convert up
to 17 gross (8.5 net) wells at a projected cost of up to $1.5 million, in order
to enhance injected water rates and reduce the time required to repressurize the
reservoir
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<PAGE> 21
on a field-wide basis. Additionally, the Company plans to aggressively withdraw
water from 17 pilot coalbed methane wells in the Raton Basin. If the dewatering
process is successful in reducing water levels and pressures within the
reservoir to the point where commercial quantities of gas are produced from
several wells within the pilot area, the Company intends to drill up to 10
additional wells in 1999 at an estimated cost of up to $2.5 million. Finally, in
cooperation with an industry partner, the Company plans to drill at least four
gross (3 net) wells in Victoria and DeWitt Counties in South Texas.
The funding of additional capital expenditures beyond the first quarter of
1999 will be dependent upon the Company's ability to realize proceeds from
future asset sales and increased operating cash flow, whether as result of
successful operations in the Raton Basin, improvements in prevailing commodity
prices or otherwise. While the Company anticipates receiving funds from these
sources during 1999, to the extent such funds are not available in the amounts
or at the times needed, additional 1999 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 $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.
Cash provided by operating activities was $1,633,000 for the year ended
December 31, 1997. The Company used cash on hand, proceeds from sales of
property and equipment of $746,000, draws on its revolving line of credit of
$10,000,000 and a portion of the Offering proceeds to finance $16,260,000 of
capital spending to drill and complete 29 net wells, acquire the Raton Basin
acreage and pipeline and complete the water distribution system in the Company's
Antelope Creek Field. Additionally, the Company incurred $1,485,000 in
organization and financing costs associated with the Offering and renewing the
Credit Agreement. During the fourth quarter of 1997, the Company completed its
initial public offering of 2,625,000 shares of common stock at $12.50 per share,
including 125,000 shares of the underwriters' over-allotment option, resulting
in net proceeds to the Company of $30,516,000. Approximately $10,000,000 of the
net proceeds were used to eliminate all outstanding amounts under the Credit
Agreement. As a result of this activity, the Company's working capital increased
from a deficit of ($541,000) to a positive of $14,872,000. The balance of the
proceeds was utilized to develop production and reserves in the Company's core
Uinta Basin and Raton Basin development properties and for other working capital
needs.
The Company believes that cash on hand, proceeds from future asset sales,
revenues and availability under the Credit Agreement, if any, will be adequate
to support its budgeted working capital and capital expenditure requirements for
at least the next 12 months. The Company anticipates that proceeds from sales of
assets will provide additional capital to fund its debt reduction plans and
position the Company to better take advantage of acquisition opportunities and
fund its discretionary capital budget. The Company believes that after 1999 it
will require a combination of additional financing and cash flow from operations
to implement its future development plans. The Company currently does not have
any arrangements with respect to, or sources of, additional financing other than
the Credit Agreement, and there can be no assurance that any additional
financing will be available to the Company on acceptable terms, if 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.
Financing
In September 1997, the Company entered into the Amended and Restated Loan
Agreement with the Chase Manhattan Bank ("Chase"), (as amended, the "Credit
Agreement"). The Credit Agreement included a $20.0 million combination credit
facility with a two-year revolving credit facility and an original borrowing
base of $7.5 million to be redetermined semi-annually ("Tranche A"), which was
set to expire on September 15, 1999, at which time all balances outstanding
under Tranche A would have converted to a term loan expiring on September 15,
2002. Additionally, the Credit Agreement contained a separate revolving facility
of $2.5 million ("Tranche B"), which was set to expire on March 15, 1999. The
Company utilized a portion of the proceeds from the Offering to eliminate all
outstanding amounts
19
<PAGE> 22
under the Credit Agreement in October, 1997. With the repayment of the Tranche B
indebtedness, the $2.5 million under that portion of the Credit Agreement was no
longer available to the Company. Effective September 30, 1998, the Company
amended the Credit Agreement with Chase, (the "Amendment"). The Amendment
increased the credit facility to $50.0 million with a two-year revolving credit
facility and an original borrowing base of $15.0 million to be redetermined
quarterly beginning December 31, 1998. The next scheduled borrowing base
redetermination date is March 31, 1999. Because of historically low crude oil
prices, management expects the borrowing base amount available under the Credit
Agreement will decline from the current level of $15.0 million. Although the
borrowing base amount ultimately determined by Chase is outside of the Company's
control, management believes the borrowing base amount will not be reduced below
the current outstanding balance of $8.5 million. 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. 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.
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 limit 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.
The Company had two open hedge contracts at December 31, 1998, which are
crude oil collars on 159,000 Bbls of oil during 1999 and 72,000 Bbls of oil
during 2000, with floor prices of $17.00 and $14.00 per Bbl, respectively, and
ceiling prices of $22.00 and $16.00 per Bbl, respectively, indexed to the NYMEX
light crude future settlement price. See Note 8 to the Notes to Consolidated
Financial Statements. During March 1999, the Company liquidated the hedge
contract covering 72,000 Bbls in the year 2000 for approximately $16,000.
YEAR 2000 ISSUES
The Company is aware of the date sensitivity issues associated with the
programming code in many existing computer systems and devices with embedded
technology. The "Year 2000" problem concerns the inability of information and
technology-based operating systems to properly recognize and process
date-sensitive information beyond December 31, 1999. The risk is that computer
systems will not properly recognize "00" in date sensitive information when the
year changes to 2000, which could cause system failures or miscalculations,
resulting in the potential disruption of business.
The management of the Company believes it is appropriately addressing the
Company's business and financial risk associated with the Year 2000 issue. In
response to the potential impact of the Year 2000 issue on the Company's
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<PAGE> 23
business and operations, the Company has formed a Year 2000 Team (the "Team"),
consisting of members of senior management and the Information Systems Manager.
The Team is developing a program around the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and governmental
entities
The information technology and systems of the Company are believed to be
Year 2000 compliant. Activity in this area included installing and testing
software upgrades and service releases supplied by vendors and testing the
processing ability of hardware and computer equipment with embedded technology.
Most of these upgrades were system replacements conducted in 1996 and 1997 to
improve business efficiencies and functionality and were not undertaken solely
to address Year 2000 issues. As such, management believes the Year 2000 issues
with respect to the Company's information technology and systems will not have a
significant potential effect on the Company's financial position or operations.
The process controls and embedded technology area is in the assessment
phase with approximately 70% of the evaluation process in the remediation and
verification phases. Field level processors, meters and equipment utilized by
the Company are not expected to contain embedded technology such as
microprocessors. However, the Company continues to conduct internal evaluations
and hold discussions with suppliers to ensure appropriate measures are taken to
minimize the impact to operations caused by any unidentified company or third
party Year 2000 issues. The Company also relies on non-information technology
systems such as telephones, facsimile machines, security systems and other
equipment which may have embedded technology such as micro-processors, which may
or may not be Year 2000 compliant. Management believes any such disruption is
not likely to have a significant effect on the Company's financial position or
operations. Management anticipates a complete evaluation of this area by the end
of the second quarter 1999.
The third-party suppliers, vendors, partners, customers and governmental
entities area is currently in the assessment phase with approximately 50% in the
remediation and verification phase. Formal communications have been initiated
with vendors, suppliers, customers and others with whom the Company has
significant business relationships. The Company continues to evaluate responses
and make additional inquiries as needed. Since the Company is in the process of
collecting this information from third parties, management cannot currently
determine whether third party compliance issues will materially affect its
operations. However, the Company is not currently aware of any third party
issues that would cause a significant business disruption. Management
anticipates a complete evaluation of this area to conclude by the end of the
second quarter 1999.
The total cost of the Company's Year 2000 program is not expected to be
material to the Company's financial position. Not including the cost of
replacing its information systems between 1996 and 1997, the Company anticipates
spending a total of $75,000 during the remainder of 1999 for Year 2000 related
modifications and testing. Expenditures during 1998 for computers and peripheral
hardware and software and software support were approximately $160,000. These
expenditures were made in the normal course of business and not necessarily for
the purpose of resolving Year 2000 problems.
The company is developing contingency plans in the unlikely event that
portions of its Year 2000 program are inadequate. The Company believes that the
most likely worst case Year 2000 scenarios are as follows: (i) unanticipated
Year 2000 induced failures in information systems could cause a reliance on
manual contingency procedures and significantly reduce efficiencies in the
performance of certain normal business activities; (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
considered to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company. The Company's contingency plans should be completed by
the end of the third quarter 1999.
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<PAGE> 24
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.
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,
22
<PAGE> 25
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 affect 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.
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.
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 $1,865,000 excluding the effect of a $4.8
million impairment in 1998. 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.
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
conversions that are intended to repressurize producing reservoirs in the Lower
Green River formation, (ii) subject to 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. Ultimate recoveries of oil and natural gas
from the enhanced oil recovery programs may also vary at different locations
within the Company's Uinta Basin properties. Accordingly, due to the early stage
of development, the Company is unable to predict whether its development
activities in the Uinta Basin will meet its expectations. In the event the
Company's enhanced oil recovery program does not effectively increase rates of
production or ultimate recovery of oil reserves, the Company's business,
financial condition and results of operation will likely be materially adversely
affected.
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<PAGE> 26
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 53% of the Company's 1998 capital expenditures of approximately
$20.6 million was dedicated to developing 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 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.
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<PAGE> 27
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 PLANNED OPERATIONS 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 has recently begun its
development program. There can be no assurance that this program will discover
natural gas and, if natural gas is discovered, that the Company 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 believes that
cash on hand, proceeds from future asset sales, revenues and availability under
the Credit Agreement, if any, will be sufficient to meet its estimated capital
expenditure requirements for 1999. The Company anticipates that proceeds from
sales of assets will provide additional capital to fund its debt reduction plans
and position the Company to better take advantage of acquisition opportunities
and fund its discretionary capital budget. The Company believes that after 1999
it will require a combination of additional financing, proceeds from asset sales
and cash flow from operations to implement its future development plans. The
Company currently does not have any arrangements with respect to, or sources of,
additional financing other than the Credit Agreement, and there can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all. 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
25
<PAGE> 28
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.
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 18%
of the Company's total proved reserves at December 31, 1998 were undeveloped and
an additional 5.2 MMBOE (36%) previously included in proved categories were
determined to be marginally economical under year-end prices and were not
included in proved reserves. 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, Robert A. Christensen, its Executive Vice
President and Chief Technical Officer, Sidney Kennard Smith, its Executive Vice
President and Chief
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<PAGE> 29
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. Christensen, 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 23, 1999, the Company had 13,250 Bbls per month of 1999 oil
production hedged at a NYMEX floor price of $17.00 per Bbl and a ceiling price
of $22.00 per Bbl. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company uses hedging
contracts to manage its price risk and limit exposure to short-term fluctuations
in commodity prices. However, should 1999 NYMEX oil prices rise above $22.00 per
Bbl, the Company would not receive the marginal benefit of oil prices in excess
of $22.00 per Bbl.
Additionally, the Company is subject to interest rate risk, as $8.5 million
owed at March 23, 1999 under the Company's revolving credit facility accrues
interest at floating rates tied to LIBOR. The Company's current average rate is
approximately 7% locked in for 90 day terms.
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 "1999
Proxy Statement") for its annual meeting
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<PAGE> 30
of stockholders to be held on May 26, 1999. The 1999 Proxy Statement will be
filed with the Securities and Exchange Commission (the "Commission") not later
than 120 days subsequent to December 31, 1998.
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 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
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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:
See Index to Consolidated Financial Statements on page F-1.
3. Exhibits: The following documents are filed as exhibits to this
report:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
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 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).
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).
</TABLE>
29
<PAGE> 32
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
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.
10.20 Second Firm Transportation Service Agreement, dated July 1, 1998, between Petroglyph
Energy, Inc. and Colorado Interstate Gas Company.
</TABLE>
30
<PAGE> 33
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
10.21 Interruptible Transportation Service Agreement, dated January 1, 1999, between Petroglyph
Energy, Inc. and Colorado Interstate Gas Company.
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.
21 Subsidiaries of the Registrant
23.1 Consent of Lee Keeling and Associates, Inc., independent reserve engineers.
27 Financial Data Schedule.
</TABLE>
(b) No reports on Form 8-K were filed during the last quarter of the period
covered by this Annual Report on Form 10-K.
31
<PAGE> 34
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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<PAGE> 35
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 reserves be
attributable to any acreage for which an application of fluid injection or other
improved
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<PAGE> 36
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
<PAGE> 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 20, 1998.
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 20, 1998, 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/ ROBERT A. CHRISTENSEN
- ---------------------------------------------------------------
Robert A. Christensen
Executive Vice President and Director
/s/ TIM A. LUCAS
- ---------------------------------------------------------------
Tim A. Lucas
Vice President, Chief Financial Officer and Treasurer
/s/ DAVID R. ALBIN
- ---------------------------------------------------------------
David R. Albin
Director
/s/ KENNETH A. HERSH
- ---------------------------------------------------------------
Kenneth A. Hersh
Director
/s/ A. J. SCHWARTZ
- ---------------------------------------------------------------
A. J. Schwartz
Director
<PAGE> 38
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF PETROGLYPH ENERGY, INC.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants...............................................................F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997...........................................F-3
Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996.............F-4
Consolidated Statements of Changes in Stockholders' Equity for the Years Ended
December 31, 1998, 1997 and 1996..............................................................F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996.............F-6
Notes to Consolidated Financial Statements.............................................................F-7
</TABLE>
F-1
<PAGE> 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, 1998 and 1997, 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, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Petroglyph Energy, Inc. and subsidiary as of December 31, 1998 and 1997 and the
results of their operations and cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Dallas, Texas
February 25, 1999
F-2
<PAGE> 40
PETROGLYPH ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents ............................................ $ 2,007,737 $ 16,678,655
Accounts receivable:
Oil and natural gas sales ........................................ 264,827 665,214
Joint interest billing ........................................... 834,910 463,400
Other ............................................................ 133,342 144,684
------------ ------------
1,233,079 1,273,298
Inventory ............................................................ 1,234,323 1,376,737
Prepaid expenses ..................................................... 247,518 246,193
------------ ------------
Total Current Assets .................................... 4,722,657 19,574,883
------------ ------------
Property and equipment, successful efforts method at cost:
Proved properties .................................................... 32,191,345 23,317,886
Unproved properties .................................................. 10,072,036 2,957,707
Pipelines, gas gathering and other ................................... 10,024,602 6,901,300
------------ ------------
52,287,983 33,176,893
Less--Accumulated depreciation, depletion, and amortization .......... (11,590,068) (6,607,487)
------------ ------------
Property and equipment, net ...................................... 40,697,915 26,569,406
------------ ------------
Note receivable from officers ............................................. 246,500 246,500
Other assets, net ......................................................... 368,129 323,189
------------ ------------
Total Assets ............................................ $ 46,035,201 $ 46,713,978
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade ............................................................ $ 2,088,290 $ 3,608,144
Oil and natural gas sales ........................................ 280,179 735,343
Current portion of long-term debt ................................ -- 36,598
Accrued taxes payable ............................................ 124,857 172,411
Other ............................................................ 277,637 149,771
------------ ------------
Total Current Liabilities ............................... 2,770,963 4,702,267
------------ ------------
Long-term debt ............................................................ 7,500,000 --
------------ ------------
Deferred tax liability .................................................... 452,488 2,514,154
------------ ------------
Stockholders' Equity:
Common Stock, par value $.01 per share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding .............. $ 54,583 $ 54,583
Paid-in capital ...................................................... 46,134,018 46,134,018
Retained earnings (deficit) .......................................... (10,876,851) (6,691,044)
------------ ------------
Total Stockholders' Equity .............................. 35,311,750 39,497,557
------------ ------------
Total Liabilities and Stockholders' Equity ................................ $ 46,035,201 $ 46,713,978
============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-3
<PAGE> 41
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Operating Revenues:
Oil sales ............................................. $ 2,912,293 $ 3,734,856 $ 4,458,769
Natural gas sales ..................................... 1,365,850 1,070,195 998,920
Other ................................................. 189,924 60,847 --
------------ ------------ ------------
Total operating revenues ........................ 4,468,067 4,865,898 5,457,689
------------ ------------ ------------
Operating Expenses:
Lease operating ....................................... 1,927,334 1,559,885 2,368,973
Production taxes ...................................... 218,129 178,822 248,848
Exploration costs ..................................... 192,526 -- 68,818
Depreciation, depletion, and amortization ............. 1,866,111 1,852,296 2,805,693
Impairments ........................................... 4,848,218 -- --
General and administrative ............................ 2,128,774 1,299,851 902,409
------------ ------------ ------------
Total operating expenses ........................ 11,181,092 4,890,854 6,394,741
------------ ------------ ------------
Operating Loss ............................................. (6,713,025) (24,956) (937,052)
Other Income (Expenses):
Interest income (expense), net ........................ 406,975 114,036 40,580
Gain (loss) on sales of property and equipment, net ... 58,577 12,440 1,383,766
------------ ------------ ------------
Net income (loss) before income taxes ...................... (6,247,473) 101,520 487,294
------------ ------------ ------------
Income Tax Expense (Benefit):
Current ............................................... -- (463,238) --
Deferred .............................................. (2,061,666) 2,977,392 --
Pro forma ............................................. -- -- 190,044
------------ ------------ ------------
Total Income Tax (Benefit) Expense .............. (2,061,666) 2,514,154 190,044
------------ ------------ ------------
Net Income (Loss) .......................................... $ (4,185,807) $ (2,412,634) $ 297,250
============ ============ ============
Earnings (Loss) per Common Share, Basic and Diluted ........ $ (.77) $ (.73) $ .11
============ ============ ============
Weighted Average Common Shares Outstanding (Note 4)
Actual ................................................ 5,458,333 3,326,826 --
Pro forma ............................................. -- -- 2,833,333
============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-4
<PAGE> 42
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
RETAINED
COMMON PARTNERS' PAID IN EARNINGS
STOCK CAPITAL CAPITAL (DEFICIT) TOTAL EQUITY
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1995 ........ $ -- $ 16,973,044 $ -- $ (4,765,704) $ 12,207,340
Contributions ..................... -- -- -- -- --
Net income before income
taxes ............................. -- -- -- 487,294 487,294
------------ ------------ ------------ ------------ ------------
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 0 46,134,018 (6,691,044) 39,497,557
Net income (loss) ................. -- -- -- (4,185,807) (4,185,807)
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1998 ........ $ 54,583 $ 0 $ 46,134,018 $(10,876,851) $ 35,311,750
============ ============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-5
<PAGE> 43
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Operating Activities:
Net income (loss) ................................................. $ (4,185,807) $ (2,412,634) $ 487,294
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization ................. 1,866,111 1,852,296 2,805,693
Gain on sales of property and equipment, net .............. (58,577) (12,440) (1,383,766)
Amortization of deferred revenue .......................... -- (45,860) (524,140)
Impairments ............................................... 4,848,218 -- --
Exploration costs ......................................... 192,526 -- --
Property abandonments ..................................... -- -- 68,818
Deferred Taxes ............................................ (2,061,666) 2,514,154 --
Proceeds from deferred revenue ............................ -- -- 570,000
Changes in assets and liabilities--
(Increase) decrease in accounts and other receivables ........ (113,462) 142,144 (481,169)
Increase in inventory ........................................ (33,586) (311,935) (579,257)
(Increase) decrease in prepaid expenses ...................... (26,325) (113,945) 3,561
Increase (decrease) in accounts payable and accrued
liabilities ............................................... (1,894,706) 20,819 3,162,406
------------ ------------ ------------
Net cash provided by (used in) operating activities ....... (1,467,274) 1,632,599 4,129,440
Investing Activities:
Proceeds from sales of property and equipment ..................... 88,200 745,712 8,968,274
Additions to oil and natural gas properties, including
exploration costs ............................................ (17,499,817) (12,767,808) (7,801,229)
Additions to pipelines, gas gathering and other ................... (3,123,302) (3,491,853) (863,911)
------------ ------------ ------------
Net cash provided by (used in) investing activities .......... (20,534,919) (15,513,949) 303,134
Financing Activities:
Proceeds from issuance of equity securities ....................... -- 30,515,625 --
Proceeds from issuance of, and draws on, notes payable ............ 7,500,000 10,085,381 2,085,024
Payments on notes payable ......................................... (36,598) (10,133,545) (5,908,527)
Payments for organization and financing costs ..................... (132,127) (1,485,088) (106,375)
------------ ------------ ------------
Net cash provided by (used in) financing activities .......... 7,331,275 28,982,373 (3,929,878)
------------ ------------ ------------
Net increase in cash and cash equivalents ............................ (14,670,918) 15,101,023 502,696
Cash and cash equivalents, beginning of period ....................... 16,678,655 1,577,632 1,074,936
------------ ------------ ------------
Cash and cash equivalents, end of period ............................ $ 2,007,737 $ 16,678,655 $ 1,577,632
============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-6
<PAGE> 44
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
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 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 immediately prior to the closing of the
initial public offering of the Company's Common Stock (the "Offering"). The
Conversion has been 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.
The accompanying consolidated financial statements of Petroglyph
include the assets, liabilities and results of operations of PGP, its wholly
owned subsidiary, Petroglyph Operating Company, Inc. ("POCI"), and PGP's
proportionate share of assets, liabilities and revenues and expenses of PGP II
through June 30, 1998. Prior to that time, PGP owned a 99% interest in PGP II.
POCI is a subchapter C corporation. POCI is the designated operator of all wells
for which Petroglyph 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.
SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest during 1998, 1997 and 1996 totaled $116,000,
$325,000, and $250,000, respectively. The Company did not make any cash payments
for income taxes during 1998 based on net losses for the year, and no cash
payments for income taxes were made in 1997 or 1996 based on its partnership
structure in effect during those periods.
F-7
<PAGE> 45
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful
accounts, the amounts of which are immaterial as of December 31, 1998 and 1997.
INVENTORY
Inventories consist primarily of 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 exploration costs. 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. The Company does not capitalize general and administrative costs
related to drilling and development activities.
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, 1997 and
1996.
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 and
Raton Basins, 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 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
forty years.
F-8
<PAGE> 46
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
ORGANIZATION AND FINANCING COSTS
Organization costs are amortized on a straight-line basis over a period
not to exceed 5 years and are presented net of accumulated amortization of
$100,385, $61,895 and $49,459 at December 31, 1998, 1997 and 1996, respectively.
Amortization of $38,490, $12,436, and $21,447 is included in depreciation,
depletion and amortization expense in the accompanying consolidated statements
of operations for the years ended December 31, 1998, 1997 and 1996,
respectively. Organization costs for periods prior to December 31, 1996 were
comprised of costs related to the formation of PGP and PGP II, which were
amortized over a period of three years.
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 $25,883 are included in interest expense
in the accompanying statements of operations for the year ended December 31,
1998.
INTEREST INCOME (EXPENSE)
For the years ended December 31, 1998, 1997 and 1996, interest income
is presented net of interest expense of $132,193, $198,519 and $106,715,
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 $90,000, $127,000 and $195,000 for the
years ended December 31, 1998, 1997 and 1996, 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, 1998 or 1997.
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 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. Pro
forma income tax information for the year ended December 31, 1996, presented in
the accompanying consolidated statements of operations and in Note 7, reflects
the income tax expense (benefit), net income (loss) and net income (loss) per
common share as if all
F-9
<PAGE> 47
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
Partnership income for 1996 had been subject to corporate federal income tax,
exclusive of the effects of recording the Company's net deferred tax liabilities
upon the Conversion.
DERIVATIVES
The Company uses derivatives on a limited basis 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
Upon the Conversion, the Company adopted 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. As of December 31, 1998
and December 31, 1997, there is no impact from adoption of APB No. 25 or
Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation" (SFAS No. 123) as no stock options, warrants or grants had been
exercised at such dates. The Company will, however, adopt the disclosure
requirements of SFAS No. 123, "Accounting for Stock-Based Compensation" which
will require the Company to present pro forma disclosures of net income and
earnings per share as if SFAS No. 123 had been adopted.
RECLASSIFICATIONS
Certain reclassifications have been made to prior year balances to
conform to current year presentation.
3. ACQUISITIONS AND DISPOSITIONS:
In June 1996, the Company sold a 50% working interest in its Antelope
Creek field properties to an industry partner. The Company retained a 50%
working interest and continues to serve as operator of the property. In exchange
for the sale of the interest in the Antelope Creek field, the Company received
$7.5 million, as adjusted, in cash and the parties entered into a Unit
Participation Agreement for development of the Antelope Creek field. Under the
terms of this agreement, the Company received $5.3 million in carried
development costs for approximately 50 wells over a 12 month period which ended
on June 30, 1997. The Company recognized a pre-tax gain on this sale of $1.3
million. This Unit Participation Agreement is structured such that the Company
paid 25% of the development costs of the Antelope Creek field from the date of
the agreement until approximately $21 million in total development costs had
been incurred. By December 31, 1997, all of this carried development cost had
been expended. In addition, under the terms of the Unit Participation Agreement,
the Company's working interest in the Antelope Creek field will increase to 58%,
and its partner's working interest will be reduced to 42%, at such time as the
Company's partner in the Antelope Creek field achieves payout, as defined in the
Unit Participation Agreement.
As an additional part of the purchase and sale agreement, the Company
sold a 50% net profits interest (NPI) in its remaining 50% interest in the
Antelope Creek field commencing on the date of the agreement. The NPI continued
in effect until 67,389 barrels of equivalent production related to the NPI was
produced from the Antelope Creek field. The NPI entitled the holder to receive
the net profits, defined in the purchase and sale agreement as revenues less
direct operating expenses, from the sale of the barrels of oil equivalent
production relating to the NPI. A value of $570,000 was assigned to the sale of
the NPI and recorded as deferred revenue. This amount was determined based on
the projected net profits that would have been received from the sale of the
barrels of oil equivalent production related to
F-10
<PAGE> 48
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
3. ACQUISITIONS AND DISPOSITIONS: -- (CONTINUED)
the NPI. As these barrels of oil equivalent production were produced and NPI
proceeds were disbursed to the holder of the NPI, an equal amount of the
deferred revenue was recognized as oil and natural gas revenue. Through December
31, 1996, the Company recognized $524,140 of revenue related to this NPI. The
remaining $45,860 was recognized during the year ended December 31, 1997.
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 20,600 net mineral acres were
acquired by December 31, 1998 from various parties for a total of 76,600 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. 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.
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."
Pro forma weighted average shares outstanding for the year ended
December 31, 1996 are presented as if the Conversion had occurred, resulting in
common stock outstanding as of the beginning of the year. The computation of
basic and diluted EPS were identical for the years ended December 31, 1998, 1997
and 1996 due to the following reasons:
o Options to purchase 273,000 shares of common stock at $5.00 per share
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 options, which expire on October 19, 2008, were still
outstanding at December 31, 1998.
o Options to purchase 321,000 shares and 337,000 shares of common stock
at $12.50 per share at December 31, 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 321,000 options, which expire on November 1, 2007,
were still outstanding at December 31, 1998.
F-11
<PAGE> 49
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
EARNINGS PER SHARE INFORMATION: -- (CONTINUED)
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,
1998. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1998.
o As the Company completed the Offering in 1997, there were no equity
securities, nor any potentially dilutive equity securities outstanding
at December 31, 1996.
5. TRANSACTIONS WITH AFFILIATES:
The Company had notes receivable from certain executive officers
aggregating $246,500 at December 31, 1998 and 1997. These notes bear interest at
a rate of 9% and mature December 31, 2003. Accrued interest on the notes at
December 31, 1998 was $142,980.
The Company leases an office building from an affiliate. Rentals paid
to the affiliate for such leases totaled $36,486 during 1998 and $34,800 during
1997 and 1996. 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, 1998, 1997 and 1996, the Company paid
legal fees of $57,060, $139,384 and $109,000, respectively, to the law firm of
Morris, Laing, Evans, Brock & Kennedy, Chartered, where A.J. Schwartz, a
director of the Company, is a partner.
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 2
wells through December 31, 1998. 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. As of December 31, 1998, SEGO owed the Company
$18,525 relating to this activity.
6. LONG-TERM DEBT:
In September 1997, the Company entered into the Credit Agreement with
Chase. The Credit Agreement included a $20.0 million combination credit facility
with a two-year revolving credit facility and an original borrowing base of $7.5
million to be redetermined semi-annually ("Tranche A"), which was set to expire
on September 15, 1999, at which time all balances outstanding under Tranche A
would have converted to a term loan expiring on September 15, 2002.
Additionally, the Credit Agreement contained a separate revolving facility of
$2.5 million ("Tranche B"), which was set to expire on March 15, 1999. The
Company utilized a portion of the proceeds from the Offering to eliminate all
outstanding amounts under the Credit Agreement in October 1997. With the
repayment of the Tranche B indebtedness, the $2.5 million under that portion of
the Credit Agreement was no longer available to the Company. Effective September
30, 1998, the Company amended the Credit Agreement with Chase, (the
"Amendment"). The Amendment increased the credit facility to $50.0 million with
a two-year revolving credit facility and an original borrowing base of $15.0
million to be redetermined quarterly beginning December 31, 1998. The next
scheduled borrowing base redetermination date is March 31, 1999. Because of
historically low crude oil prices, management expects the borrowing base amounts
available under the Credit Agreement will decline from the current level of
$15.0 million. Although the borrowing base amount ultimately determined by Chase
is outside of the Company's control, management believes the borrowing base
amount will not be reduced below the current outstanding balance of $8.5
F-12
<PAGE> 50
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
6. LONG-TERM DEBT: -- (CONTINUED)
million. 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. 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.
7. INCOME TAXES:
Upon the completion of the Offering in November 1997, all income of the
Company became taxable as a corporation. Pro forma information in the 1996
consolidated statements of operations reflects the income tax expense (benefit),
net income (loss) and net income (loss) per common share/unit as if all prior
Partnership income had been subject to corporate federal income tax, exclusive
of the effects of recording the Company's net deferred tax liabilities upon the
conclusion of the Offering. This pro forma information is presented below for
comparative purposes only.
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the periods shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
---- ---- ----
(pro forma)
<S> <C> <C> <C>
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 ...................................... 2% -- --
True-ups ................................................... 1% -- --
Other ...................................................... 1% -- --
----- ------ ----
$ (33)% $ 2477% $ 39%
===== ====== ====
</TABLE>
Components of income tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
(pro forma)
<S> <C> <C> <C>
Current .................................................... $ -- $ (463,238) $ (222,169)
Deferred ................................................... (2,061,666) 2,977,392 412,213
----------- ----------- -----------
Total .................................... $(2,061,666) $ 2,514,154 $ 190,044
=========== =========== ===========
</TABLE>
F-13
<PAGE> 51
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
7. 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, 1998 and 1997, are summarized below:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1998 1997
----------- -----------
(pro forma)
<S> <C> <C>
Deferred Tax Assets:
Inventory and other ......................... 76,188 --
Net operating loss carryforwards ............ $ 6,344,613 $ 496,232
----------- -----------
Total Deferred Tax Assets ................ 6,420,801 496,232
----------- -----------
Deferred Tax Liabilities:
Inventory and other ......................... -- (32,994)
Property and equipment ...................... (6,873,289) (2,977,392)
----------- -----------
Total Deferred Tax Liabilities ........... (6,873,289) (3,010,386)
----------- -----------
Total Net Deferred Tax Liability ......... $ (452,488) $(2,514,154)
=========== ===========
</TABLE>
The net deferred tax liability as of December 31, 1997 is primarily the
amount that the Company was required to recognize as income tax expense on the
date of the Conversion discussed in Note 2.
8. 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 gain of $386,000 in 1998, a net loss of $132,200 in 1997 and a net loss of
$128,400 in 1996. Included in natural gas revenues in 1997 is a net loss of
$46,000.
In September 1995, the Company assumed the obligations of a former
joint interest owner under a financial swap arrangement. This agreement covers
the sale of 549,000 Bbls from January 1996 to December 1999 at a NYMEX floor
price of $17.00 per Bbl and a ceiling price of $20.75 per Bbl. The ceiling price
was increased to $22.00 per Bbl for 1999. Additionally, during 1998, the Company
entered into a swap arrangement covering the sale of 6,000 Bbls per month from
January, 2000 to December, 2000 at a NYMEX floor price of $14.00 and a ceiling
price of $16.00 per Bbl. At December 31, 1998, this contract was outstanding and
calls for the remaining sale of 231,000 barrels of oil over the next two years
as follows:
<TABLE>
<CAPTION>
YEAR BBLS
---- --------
<S> <C>
1999.................................... 159,000
2000.................................... 72,000
--------
Total............................... 231,000
========
</TABLE>
During March of 1999, the Company liquidated the hedge contract
covering 72,000 Bbls in the year 2000 for approximately $16,000.
In June 1994, the Company entered into a contract to sell its oil
production from certain leases of its Utah properties to Purchaser "A." The
price under this contract is agreed upon on a monthly basis and is generally
based on
F-14
<PAGE> 52
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
DERIVATIVES AND SALES CONTRACTS: -- (CONTINUED)
this purchaser's posted price for yellow or black wax production, as applicable.
This contract will continue in effect until terminated by either party upon
giving proper notice. During the years ended December 31, 1998, 1997 and 1996
the volumes sold under this contract totaled 125 MBbls, 74 MBbls and 61 MBbls,
respectively, at an average sales price per Bbl for each year of $9.27, $14.80
and $19.33, respectively.
In January 1996, the Company entered into a contract to sell black wax
production from its Utah leases to Purchaser "B." The price under this contract
is based on the monthly average of the NYMEX price for West Texas Intermediate
("WTI") crude oil, less $.50 per Bbl, adjusted for the pricing differential
related to the gravity difference between Purchaser B's Utah black wax posting
and WTI, less $2.50 per Bbl to cover gathering costs and quality differential.
During the year ended December 31, 1996, the Company sold 59 MBbls of oil under
this contract at an average price of $19.69 per Bbl. This contract was canceled
effective January 1, 1997.
In July 1997, the Company entered into a modification of its crude oil
sales contract to sell its black wax crude oil production from the Antelope
Creek field to Purchaser "C" at a price equal to posting, less an agreed upon
adjustment to cover handling and gathering costs. This contract supersedes the
contract which the Company had with this purchaser from February 1994 through
June 1997. This contract will continue in effect until terminated by either
party upon giving proper notice. For the years ended December 31, 1998 and 1997,
the Company sold 38 MBbls and 70 MBbls, respectively, under this contract at an
average price of $9.04 and $16.58 per Bbl, respectively.
In June 1997, the Company entered into a crude oil contract to sell
black wax production from certain of its oil tank batteries in Antelope Creek to
Purchaser "D." This contract was effective until May 31, 1998 and called for the
Company to receive a per Bbl price equal to the current month NYMEX closing
price for sweet crude, averaged over the month in which the crude is sold, less
an agreed upon fixed adjustment. Volumes sold under this contract totaled 25
MBbls and 73 MBbls at an average price of $12.88 and $14.50 for the years ended
December 31, 1998 and 1997, respectively.
In addition to the sales contracts discussed above, Purchaser "C" has 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, this 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 Purchaser "C"
exercises the call option, 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
1998 were 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.
Oil sales to three purchasers in 1996 were approximately 26%, 26% and 12% of
total 1996 oil and gas revenues.
F-15
<PAGE> 53
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
9. 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, 1998 and 1997. The fair value
of the Company's bank borrowings approximate their carrying value because the
borrowings bear interest at market rates. The Company does not have any
investments in debt or equity securities as of December 31, 1998 or 1997. The
fair value of the Company's outstanding oil price swap arrangement, described in
the preceding note, has an estimated fair value of $648,000 and $182,000 at
December 31, 1998 and 1997, respectively. These estimates are based on quoted
market values.
10. STOCK 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 is subject to the approval of
the stockholders of the Company at the annual stockholders meeting to be held on
May 26, 1999. As of December 31, 1998, options have been granted to purchase
594,000 shares of Common Stock. This amount includes 54,000 shares of Common
Stock available under the 1997 Incentive Plan as originally adopted that were
granted to participants at an exercise price equal to $5.00 per share and
219,000 shares of Common Stock, subject to stockholder approval, also granted at
an exercise price of $5.00 per share. One third of the options granted in
October 1998 will vest each year commencing on October 19, 1999.
As of December 31, 1997, options were granted to purchase 337,000
shares of Common Stock to participants at an exercise price per share equal to
$12.50 per share. 16,000 of those shares have subsequently been terminated.
One-third of these options vest each year commencing on November 1, 1998. No
options had been exercised under the 1997 Incentive Plan as of December 31,
1998.
The following table summarized information about Petroglyph's stock
options which were outstanding, and those which were exercisable, as of December
31, 1998.
OPTIONS OUTSTANDING
<TABLE>
<CAPTION>
EXERCISE NUMBER REMAINING NUMBER
PRICE OUTSTANDING LIFE EXERCISABLE
-------- ----------- --------- -----------
<S> <C> <C> <C>
$ 5.00 273,000 9.8 years --
$ 12.50 321,000 8.8 years 107,000
----------- --------- ---------- ---------
594,000 9.3 years 107,000
</TABLE>
F-16
<PAGE> 54
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
DESCRIPTION OF PLAN: -- (CONTINUED)
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.
Warrants to purchase up to 6,496 shares of common stock, at a price
equal to par value, were granted to Chase under the terms of the Credit
Agreement. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1998.
PRO FORMA EFFECT OF RECORDING STOCK-BASE COMPENSATION AT ESTIMATED FAIR VALUE
(UNAUDITED)
The following table presents pro forma loss available to common stock
and loss per common share for 1998, 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):
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED
DECEMBER 31, 1998 DECEMBER 31, 1997
----------------- -----------------
<S> <C> <C>
Loss available to common stock
As reported $ (4,185,807) $ (2,412,634)
Pro forma $ (4,633,833) $ (2,492,007)
Loss per common share
As reported, basic and diluted $ (.77) $ (.73)
Pro forma, basic and diluted $ (.85) $ (.75)
</TABLE>
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:
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Risk free interest rate 4.62% 5.89%
Expected life 7 years 7 years
Expected volatility 43.59% 45.24%
Expected dividends 0 0
</TABLE>
There was no impact of adoption of APB No. 25 or SFAS No. 123 for the
year ended December 31, 1996 as no stock options, warrants or grants had been
issued at such date.
F-17
<PAGE> 55
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
11. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company leases offices and office equipment in its primary
locations under non-cancelable operating leases. As of December 31, 1998, total
minimum future lease payments for all non-cancelable lease agreements is
$137,747.
Amounts incurred by the Company under operating leases (including
renewable monthly leases) were $91,042, $53,383, and $41,548, in 1998, 1997 and
1996, 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 effect on the Company's financial position or
results of operations.
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 has 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 beginning February 1, 1999,
and ending January 31, 2009. The commitment begins 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. The Company can reduce
the minimum monthly commitment by selling its available pipeline capacity at
market rates.
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
F-18
<PAGE> 56
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
ENVIRONMENTAL MATTERS: -- (CONTINUED)
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.
12. 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):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition
Unproved Properties ............... $ 7,141,142 $ 1,721,636 $ 490,487
Proved Properties ................. 42,533 147,387 --
Development ............................ 10,123,616 10,003,468 6,983,715
Exploration ............................ 192,526 -- --
Improved recovery costs ................ -- 895,317 327,027
----------- ----------- -----------
Total ........................ $17,499,817 $12,767,808 $ 7,801,229
=========== =========== ===========
</TABLE>
PROVED RESERVES
Independent petroleum engineers have estimated the Company's proved oil
and natural gas reserves as of December 31, 1998 and 1997, all of which are
located in the United States. Prior period reserves were estimated by the
Company's reserve engineer. 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% 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
F-19
<PAGE> 57
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
STANDARDIZED MEASURE:-- (CONTINUED)
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.
<TABLE>
<CAPTION>
OIL Natural Gas
(BBLS) (Mcf)
----------- -----------
<S> <C> <C>
Proved Reserves (Unaudited):
December 31, 1995 ..................................... 1,561,092 6,659,160
Revisions .................................... (801,535) (3,146,699)
Extensions, additions and discoveries ........ 6,440,869 18,448,489
Production ................................... (262,910) (553,770)
Purchases of reserves ........................ -- --
Sales in place ............................... (810,380) (2,594,717)
----------- -----------
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
=========== ===========
PROVED DEVELOPED RESERVES:
December 31, 1995 ..................................... 1,561,092 6,659,160
=========== ===========
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
=========== ===========
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Future cash inflows .............................. $ 84,010,748 $ 169,302,079 $ 184,248,490
Future costs:
Production .............................. (25,826,978) (50,913,842) (43,993,010)
Development ............................. (5,823,801) (19,151,264) (16,455,901)
------------- ------------- -------------
Future net cash flows before income tax .......... 52,359,969 99,236,973 123,799,579
=============
Future income tax ................................ (8,767,729) (22,247,206) (32,657,687)
------------- ------------- -------------
Future net cash flows ............................ 43,592,240 76,989,767 91,141,892
10% annual discount .............................. 19,398,715 (42,836,688) (43,117,804)
------------- ------------- -------------
Standardized Measure ............................. $ 24,193,525 $ 34,153,079 $ 48,024,088
============= ============= =============
</TABLE>
F-20
<PAGE> 58
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Standardized Measure, Beginning of Period ............. $ 34,153,079 $ 48,024,088 $ 13,370,705
Revisions:
Prices and costs ............................. (32,472,461) (26,476,631) 4,839,954
Quantity estimates ........................... 2,814,596 380,840 6,000,942
Accretion of discount ........................ 4,346,915 6,484,830 1,484,547
Future development cost ...................... 7,332,602 (1,869,101) (15,068,164)
Income tax ................................... 5,201,663 7,508,139 (14,604,066)
Production rates and other ................... (6,027,000) (8,545,510) 1,901,254
------------ ------------ ------------
Net revisions ....................... (18,803,685) (22,517,433) (15,445,533)
Extensions, additions and discoveries ................. 6,061,487 12,757,280 56,781,465
Production ............................................ (2,132,680) (3,372,040) (2,390,023)
Development costs ..................................... 5,031,367 -- --
Purchases in place .................................... -- 397,644 --
Sales in place ........................................ (116,043) (1,136,460) (4,292,526)
------------ ------------ ------------
Net change ................................... (9,959,554) (13,871,009) 34,653,383
Standardized Measure, End of Period ................... $ 24,193,525 $ 34,153,079 $ 48,024,088
============ ============ ============
</TABLE>
Year-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $8.04, $13.46, and
$19.50 per Bbl at December 31, 1998, 1997, and 1996, respectively. Year-end
weighted average gas prices were $2.09, $2.03, and $3.37, per Mcf at December
31, 1998, 1997, and 1996, respectively. 1998 weighted average oil price includes
a positive impact from crude oil hedging transactions resulting in a realized
price of $11.89 in 1999 and $8.75 in 2000. Weighted average oil price, excluding
hedges would have been $7.80. Price and cost revisions are primarily the net
result of changes in period-end prices, based on beginning of period reserve
estimates.
F-21
<PAGE> 59
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
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 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).
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).
</TABLE>
<PAGE> 60
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
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.
10.20 Second Firm Transportation Service Agreement, dated July 1, 1998, between Petroglyph
Energy, Inc. and Colorado Interstate Gas Company.
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
- ------- -----------------------
<S> <C>
10.21 Interruptible Transportation Service Agreement, dated January 1, 1999, between Petroglyph
Energy, Inc. and Colorado Interstate Gas Company.
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.
21 Subsidiaries of the Registrant
23.1 Consent of Lee Keeling and Associates, Inc., independent reserve engineers.
27 Financial Data Schedule.
</TABLE>
<PAGE> 1
Exhibit 10.19
Contract No. 33206000
Firm Transportation Service Agreement
Rate Schedule TF-1
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
<PAGE> 2
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-1
- -------------------------------------------------------------------------------
The Parties identified below, in consideration of their mutual
promises, agree as follows:
1. TRANSPORTER: COLORADO INTERSTATE GAS COMPANY
2. SHIPPER: PETROGLYPH ENERGY, INC.
3. APPLICABLE TARIFF: Transporter's FERC Gas Tariff, First Revised Volume
No. 1, as the same may be amended or superseded from time to time ("the
Tariff").
4. CHANGES IN RATES AND TERMS: Transporter shall have the right to propose to
the FERC changes in its rates and terms of service, and this Agreement
shall be deemed to include any changes which are made effective pursuant to
FERC Order or regulation or provisions of law, without prejudice to
Shipper's right to protest the same.
5. TRANSPORTATION SERVICE: Transportation Service at and between Primary
Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm
basis. Receipt and Delivery of quantities at Secondary Point(s) of Receipt
and/or Secondary Point(s) of Delivery shall be in accordance with the
Tariff.
6. POINTS OF RECEIPT AND DELIVERY: Shipper agrees to Tender gas for
Transportation Service, and Transporter agrees to accept Receipt Quantities
at the Primary Point(s) of Receipt identified in Exhibit "A." Transporter
agrees to provide Transportation Service and Deliver gas to Shipper (or for
Shipper's account) at the Primary Point(s) of Delivery identified in
Exhibit "A."
7. RATES AND SURCHARGES: As set forth in Exhibit "B."
8. NEGOTIATED RATE AGREEMENT: N/A
9. PEAK MONTH MDQ:
<TABLE>
<CAPTION>
MDQ (DTH/D) EFFECTIVE DATE FROM IN-SERVICE DATE*
- ------------ ---------------------------------------------
<S> <C>
2,000 In-Service Date through month 3
3,000 Month 4 through month 6
4,000 Month 7 through month 9
5,000 Month 10 through month 12
6,000 Month 13 through month 15
7,000 Month 14 through month 18
8,000 Month 19 through month 21
10,000 Month 22 through month 24
16,000 Month 25 through year 10
14,000 10 years through 10 years, 3 months
13,000 10 years, 4 months through 10 years, 6 months
12,000 10 years, 7 months through 10 years, 9 months
11,000 10 years, 10 months through 11 years
10,000 11 years through 11 years, 3 months
9,000 11 years, 4 months through 11 years, 6 months
8,000 11 years, 10 months through 12 years
6,000
</TABLE>
*The "In-Service Date" of the Cucharas Lateral is defined as the first day of
the month following the date the Cucharas Lateral is completed and in service.
<PAGE> 3
If, at any time after the second anniversary date of the In-Service Date (but
prior to the tenth anniversary date of the In-Service Date), there is
insufficient Available Production to fill Shipper's MDQ, then Shipper shall
have the one-time option to reduce the MDQ under this Agreement to the level of
Available Production. To exercise such option, Shipper shall provide
Transporter with 60 days' prior written notice and shall pay Transporter the
prepaid reservation charges (PRC) amount described below. "Available
Production" means the monthly average daily volume of gas produced from the
leases and lease positions owned, hereafter acquired or controlled by
operation, by Shipper or a Shipper affiliate in the geographic area described
on Exhibit "C" hereto, excluding lease use gas, line loss, and gas used as
gathering fuel. Notwithstanding anything to the contrary in this Agreement,
Shipper shall have the full and complete right to determine when and to what
extent such leases and lease positions will be developed and gas produced
therefrom.
In the event Shipper elects to reduce the MDQ under this Agreement pursuant
to the provisions of the paragraph above, the PRC amount shall equal the
result of the following formula:
[16,000 - X] Where X = the new MDQ (in Dth/day) under
$6,400,000 x ------------ this Agreement, after reduction by Shipper
16,000
10. TERMS OF AGREEMENT: The term of this Agreement shall commence on the
first of the month following the In-Service Date of
the Cucharas Lateral and shall remain in effect for
12 years thereafter. However, each incremental
increase in MDQ shall be effective for a period of
10 years as shown in paragraph 9.
11. NOTICES, STATEMENTS, AND BILLS:
TO SHIPPER:
INVOICES FOR TRANSPORTATION:
Petroglyph Energy, Inc.
P.O. Box 1839
Hutchinson, Kansas 67504-1839
Attention: Theresa Sotomayor
ALL NOTICES:
Petroglyph Energy, Inc.
1302 North Grand
Hutchinson, Kansas 67501
Attention: Craig Saldin
TO TRANSPORTER:
See Payments, Notices, Nominations, and Points of Contact sheets
in the Tariff.
12. SUPERSEDES AND CANCELS PRIOR AGREEMENT: N/A
13. ADJUSTMENT TO RATE SCHEDULE TF-1 AND/OR GENERAL TERMS AND CONDITIONS: Any
conveyance or other assignment by Shipper, its successors or assigns of an
interest in all or substantially all the leases or other gas rights
underlying Available Production shall include an assignment of this
Agreement to the extent of the interests conveyed. Shipper's rights and
obligations under this Agreement shall not otherwise be assignable without
Transporter's written consent, which consent shall not be unreasonably
withheld. Shipper agrees to execute an instrument suitable for recording in
the real property records of Huerfano and Las Animas counties reflecting
this provision.
14. INCORPORATION BY REFERENCE: This Agreement in all respects shall be subject
to the provisions of Rate Schedule TF-1 and to the applicable provisions of
the General Terms and Conditions of the Tariff as
2
<PAGE> 4
filed with, and made effective by, the FERC as same may change from time to
time (and as they may be amended pursuant to Section 13 of the Agreement).
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
TRANSPORTER: SHIPPER:
COLORADO INTERSTATE GAS COMPANY PETROGLYPH ENERGY, INC.
By /s/ Thomas L. Price By /s/ S.K. Smith
------------------------------- -------------------------------
Thomas L. Price
Vice President
Approved S.K. Smith
for Execution -----------------------------------
(Print or type name)
By [illegible] Executive Vice President
---------------------- -----------------------------------
Legal Dept. (Print or type title)
3
<PAGE> 5
EXHIBIT "A"
Firm Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
1. Shipper's Maximum Delivery Quantity ("MDQ"): See Paragraph 9.
<TABLE>
<CAPTION>
PRIMARY POINT(S) OF MAXIMUM RECEIPT
PRIMARY POINT(S) OF RECEIPT RECEIPT QUANTITY PRESSURE
(NOTE 1) (DTH PER DAY) (NOTE 2) P.S.I.G.
- -------------------------------------- ---------------------- --------------------
<S> <C> <C>
New meter station to be constructed by Same as MDQ At a pressure
Transporter in the north half of sufficient to enter
Township 29S, Range 67W, the Cucharas Lateral
Huerfano County, CO (up to the MAOP of
the Cucharas
Lateral)
</TABLE>
<TABLE>
<CAPTION>
PRIMARY POINT(S) OF MAXIMUM RECEIPT
PRIMARY POINT(S) OF RECEIPT RECEIPT QUANTITY PRESSURE
(NOTE 1) (DTH PER DAY) P.S.I.G.
- -------------------------------------- ---------------------- --------------------
<S> <C> <C>
Dumas (Note 3) Same as MDQ 650
</TABLE>
NOTES: (1) Information regarding Point(s) of Receipt and Point(s) of Delivery,
including legal descriptions, measuring parties, and
interconnecting parties, shall be posted on Transporter's
electronic bulletin board. Transporter shall update such
information from time to time to include additions, deletions, or
any other revisions deemed appropriate by Transporter.
(2) Each Point of Receipt Quantity may be increased by an amount equal
to Transporter's Fuel Reimbursement percentage. Shipper shall be
responsible for providing such Fuel Reimbursement at each Point of
Receipt on a pro rata basis based on the quantities received on any
Day at a Point of Receipt divided by the total quantity Delivered
at all Point(s) of Delivery under this Transportation Service
Agreement.
(3) Shipper shall not be restricted from designating another delivery
point(s) as Primary Delivery Point(s) should another point(s)
become available during the term of this Agreement as specified in
the Tariff. However, unless otherwise agreed, the rate for
transportation service to another Point(s) of Delivery shall be
Transporter's maximum rate.
<PAGE> 6
Page 1 of 3
EXHIBIT "B"
Firm Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
<TABLE>
<CAPTION>
PRIMARY PRIMARY R1
POINT(S) OF POINT(S) OF RESERVATION COMMODITY FUEL
RECEIPT DELIVERY RATE RATE TERM OF RATE REIMBURSEMENT SURCHARGES
- -------------- ----------- ----------- --------- --------------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
New meter Dumas (Notes 1 (Notes 1 12 years from (Note 2) (Note 3)
station to be and 5) and 5) first of the
constructed by month following
Transporter in the date the
the north half Cucharas
of Township Lateral is
29S, Range completed and
67W, in service
Huerfano
County, CO
</TABLE>
<TABLE>
<CAPTION>
SECONDARY SECONDARY R1
POINT(S) OF POINT(S) OF RESERVATION COMMODITY FUEL
RECEIPT DELIVERY RATE RATE TERM OF RATE REIMBURSEMENT SURCHARGES
- -------------- ------------- ----------- --------- --------------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
New meter Barbwire, Big (Notes 1 (Notes 1 12 years from (Note 2) (Note 3)
station to be Blue, and 5) and 5) first of the
constructed by Cattleguard, month following
Transporter in Sherman the date the
the north half County, Cucharas
of Township Tannery, Lateral is
29S, Range Tumbleweed completed and
67W, in service
Huerfano
County, CO
All All (Note 4) (Note 4) 12 years from (Note 2) (Note 3)
first of the
month following
the date the
Cucharas
Lateral is
completed and
in service
</TABLE>
<PAGE> 7
Page 2 of 3
EXHIBIT "B"
NOTES: (1) (a) Except as provided in subparagraph (b) below, the rate for
service under this Agreement ("Fixed Rate") shall be 32.50
cents per Dth (computed on a 100 percent load factor basis),
plus fuel, L&U, GRI, if applicable, and ACA and all other
surcharges applicable to Transporter's Rate Schedule TF-1.
Should Transporter's Maximum Rate as defined below, when
computed on a 100% load factor basis exceed 32.50 cents per Dth
except as provided in subparagraph (b) below, the Fixed Rate
shall nevertheless be applicable. Should Transporter's Maximum
Rate or rate components be set at a level such that Transporter
is unable to collect the Fixed Rate, then Shipper agrees to an
increase in the MDQ or to other lawful arrangements, such that
the Parties are placed in the same economic position as if
Transporter had collected the Fixed Rate.
(b) Transporter and Shipper agree that no reserve dedication, well
dedication, or acreage dedication exists. However, Transporter
is agreeing to the Fixed Rate in recognition of Shipper's
agreement to tender to Transporter for transportation under
this Agreement: (i) all Available Production (other than Local
Consumption) up to the MDQ volume set forth in paragraph 9; and
(ii) only Available Production. For any period of time in which
Shipper fails to satisfy both conditions (i) and (ii) above, at
Transporter's option, the rate for service under this Agreement
shall be the ten-effective maximum reservation and commodity
rates for firm transportation service under Transporter's Rate
Schedule TF-1, plus fuel, L&U, GRI (if applicable), ACA, and
all other surcharges applicable to Transporter's Rate Schedule
TF-1 ("Maximum Rate"). "Local Consumption" means a volume of
Available Production which Shipper delivers from its gathering
system for local consumption.
(2) Fuel Reimbursement shall be as stated on Transporter's Schedule of
Surcharges and Fees in the Tariff, as they may be changed from time
to time, unless otherwise agreed between the Parties.
(3) Surcharges, If Applicable: All applicable surcharges, unless
otherwise specified, shall be the maximum surcharge rate as
stated in the Schedule of Surcharges and Fees in The Tariff, as
such surcharges may be changed from time to time.
GQC:
The Gas Quality Control Surcharge shall be assessed pursuant to
Article 20 of the General Terms and Conditions as set forth in
The Tariff.
GRI:
The GRI Surcharge shall be assessed pursuant to Article 18 of
the General Terms and Conditions as set forth in The Tariff.
HFS:
The Hourly Flexibility Surcharge shall be assessed pursuant to
Article 20 of the General Terms and Conditions as set forth in
The Tariff.
<PAGE> 1
Exhibit 10.20
Contract No. 33209000
Firm Transportation Service Agreement
Rate Schedule TF-1
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
<PAGE> 2
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-1
- ------------------------------------------------------------------------------
The Parties identified below, in consideration of their mutual promises,
agree as follows:
1. TRANSPORTER: COLORADO INTERSTATE GAS COMPANY
2. SHIPPER: PETROGLYPH ENERGY, INC.
3. APPLICABLE TARIFF: Transporter's FERC Gas Tariff, First Revised Volume No.
1, as the same may be amended or superseded from time to time ("the
Tariff").
4. CHANGES IN RATES AND TERMS: Transporter shall have the right to propose to
the FERC changes in its rates and terms of service, and this Agreement
shall be deemed to include any changes which are made effective pursuant to
FERC Order or regulation or provisions of law, without prejudice to
Shipper's right to protest the same.
5. TRANSPORTATION SERVICE: Transportation Service at and between Primary
Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm
basis. Receipt and Delivery of quantities at Secondary Point(s) of Receipt
and/or Secondary Point(s) of Delivery shall be in accordance with the
Tariff.
6. POINTS OF RECEIPT AND DELIVERY: Shipper agrees to Tender gas for
Transportation Service, and Transporter agrees to accept Receipt Quantities
at the Primary Point(s) of Receipt identified in Exhibit "A." Transporter
agrees to provide Transportation Service and Deliver gas to Shipper (or for
Shipper's account) at the Primary Point(s) of Delivery identified in
Exhibit "A."
7. RATES AND SURCHARGES: As set forth in Exhibit "B."
8. NEGOTIATED RATE AGREEMENT: N/A
9. PEAK MONTH MDQ:
<TABLE>
<CAPTION>
MDQ (DTH/D) EFFECTIVE DATE FROM IN-SERVICE DATE*
- ------------ ------------------------------------
<S> <C>
0 In-Service Date through year 3
8,000 End of year 3 through year 4
16,000 End of year 4 through year 13
8,000 Year 14
</TABLE>
* The "In-Service Date" of the Cucharas Lateral is defined as the first day of
the month following the date the Cucharas Lateral is completed and in service.
(a) Shipper shall have the right, prior to an anniversary date of the
In-Service Date to reduce or eliminate the increment of MDQ scheduled to go
into effect on the upcoming anniversary date. Provided, however, (1)
Shipper may do so only if it determines in good faith that it will not have
sufficient Additional Available Production (as defined in Exhibit B, Note 1
[b]) to utilize the additional MDQ specified, and (2) Shipper must give
Transporter notice whether it wishes to reduce or eliminate (and, if so,
the new level of MDQ desired) or whether it wishes to maintain the MDQ at
the scheduled level. Shipper shall provide such notice at least six months
before the effective date of the applicable MDQ increment shown above.
Within 30 days of Transporter's receipt of such notification, Transporter
shall notify Shipper, as provided in subparagraph (b) below, whether the
MDQ level desired by Shipper can be accommodated without the construction
of additional facilities.
<PAGE> 3
(b) If, in order to accommodate any portion of the MDQ or any change in MDQ,
Transporter is required to construct new facilities, Transporter's notice
to Shipper provided for in subparagraph (a) above shall include such
information and Transporter's estimate of the date when such additional
facilities will be ready for service. Further, should Transporter determine
that it is not economic to construct such facilities, such notice shall so
state, notwithstanding any other provision of this Agreement.
(1) The portion of the MDQ or MDQ change related to such required
additional facilities shall not become effective until such additional
facilities, if any, are in service; and
(2) Should Transporter determine that it is not economic to construct such
facilities, then such portion of the MDQ or MDQ change shall not become
effective. In such event, Shipper shall have the options: (A) to
increase the MDQ and/or the timing of schedule MDQ increases to a level
which makes construction of additional facilities economic for
Transporter; (B) postponing the MDQ increase or change; and/or (C)
utilizing the Interruptible and/or Authorized Overrun services [as
described in Exhibit B, Note 1(c)].
(c) Provided capacity is available without construction of additional
facilities: (1) upon prior written notice to Transporter, Shipper may
commence the term for the MDQ increments shown above at any time prior to
the dates shows, and (2) Shipper shall have the right at any time during
the term of this Agreement and following any relinquishment of any capacity
by Shipper under this Agreement to regain such relinquished capacity.
(d) Transporter shall have the right to request Shipper to forego some or all
the MDQ which has not yet become effective under the Above table.
Transporter may make such request(s) at any such time(s) as Transporter
receives other requests for service which Transporter determines may not be
fully satisfied except by the use of some or all of the capacity covered by
this Agreement. In the event that Transporter so requests Shipper to forego
some of all of such MDQ, Shipper may agree to amend this Agreement to
reduce the MDQ which is not yet effective as necessary to allow Transporter
to provide capacity to other shippers. Shipper is under no obligation to
agree to Transporter's request. However, to the extent that Transporter
requests Shipper to relinquish some ora part of such MDQ, and Shipper does
not agree to do so, then (except as provided in subparagraph (b) above)
from the effective date of the request for service by other shipper(s) for
the capacity which Transporter is not able to accommodate due to this
Agreement, the portion of the MDQ under this Agreement that has not yet
become effective and which Shipper has declined to reduce shall then become
effective and the reservation charges associated therewith shall thereafter
become applicable.
10. TERMS OF AGREEMENT: Unless terminated earlier in accordance with the terms
of this Agreement, the term of this Agreement shall
commence on the In-Service Date of the Cucharas Lateral
and shall remain in effect for 14 years thereafter.
11. NOTICES, STATEMENTS, AND BILLS:
TO SHIPPER:
INVOICES FOR TRANSPORTATION:
Petroglyph Energy, Inc.
P.O. Box 1839
Hutchinson, Kansas 67504-1839
Attention: Theresa Sotomayor
2
<PAGE> 4
ALL NOTICES:
Petroglyph Energy, Inc.
P.O. Box 1839
Hutchinson, Kansas 67504-1839
Attention: Craig Saldin
TO TRANSPORTER:
See Payments, Notices, Nominations, and Points of Contact sheets
in the Tariff.
12. SUPERSEDES AND CANCELS PRIOR AGREEMENT: N/A
13. ADJUSTMENT TO RATE SCHEDULE TF-1 AND/OR GENERAL TERMS AND CONDITIONS: Any
conveyance or other assignment by Shipper, its successors or assigns of an
interest in all or substantially all the leases or other gas rights
underlying Available Production shall include an assignment of this
Agreement to the extent of the interests conveyed. Shipper's rights and
obligations under this Agreement shall not otherwise be assignable without
Transporter's written consent, which consent shall not be unreasonably
withheld. Shipper agrees to execute an instrument suitable for recording in
the real property records of Huerfano and Las Animas counties reflecting
this provision.
14. INCORPORATION BY REFERENCE: This Agreement in all respects shall be subject
to the provisions of Rate Schedule TF-1 and to the applicable provisions of
the General Terms and Conditions of the Tariff as filed with, and made
effective by, the FERC as same may change from time to time (and as they
may be amended pursuant to Section 13 of the Agreement).
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
TRANSPORTER: SHIPPER:
COLORADO INTERSTATE GAS COMPANY PETROGLYPH ENERGY, INC.
By /s/ Thomas L. Price By /s/ S.K. Smith
------------------------------- -------------------------------
Thomas L. Price
Vice President
S.K. Smith
Approved -----------------------------------
for Execution (Print or type name)
By [illegible] Executive Vice President
----------------- ----------------------------------
Legal Dept. (Print or type title)
3
<PAGE> 5
EXHIBIT "A"
Firm Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
1. Shipper's Maximum Delivery Quantity ("MDQ"): See Paragraph 9.
<TABLE>
<CAPTION>
PRIMARY POINT(S) OF MAXIMUM RECEIPT
PRIMARY POINT(S) OF RECEIPT RECEIPT QUANTITY PRESSURE
(NOTE 1) (DTH PER DAY) (NOTE 2) P.S.I.G.
- -------------------------------------- ---------------------- --------------------
<S> <C> <C>
New meter station to be constructed by Same as MDQ At a pressure
Transporter in the north half of sufficient to enter
Township 29S, Range 67W, the Cucharas Lateral
Huerfano County, CO (up to the MAOP of
the Cucharas
Lateral)
</TABLE>
<TABLE>
<CAPTION>
PRIMARY POINT(S) OF MAXIMUM RECEIPT
PRIMARY POINT(S) OF RECEIPT RECEIPT QUANTITY PRESSURE
(NOTE 1) (DTH PER DAY) P.S.I.G.
- -------------------------------------- ---------------------- --------------------
<S> <C> <C>
Dumas (Note 3) Same as MDQ 650
</TABLE>
NOTES: (1) Information regarding Point(s) of Receipt and Point(s) of Delivery,
including legal descriptions, measuring parties, and interconnecting
parties, shall be posted on Transporter's electronic bulletin board.
Transporter shall update such information from time to time to
include additions, deletions, or any other revisions deemed
appropriate by Transporter.
(2) Each Point of Receipt Quantity may be increased by an amount equal to
Transporter's Fuel Reimbursement percentage. Shipper shall be
responsible for providing such Fuel Reimbursement at each Point of
Receipt on a pro rata basis based on the quantities received on any
Day at a Point of Receipt divided by the total quantity Delivered at
all Point(s) of Delivery under this Transportation Service Agreement.
(3) Shipper shall not be restricted from designating another delivery
point(s) as Primary Delivery Point(s) should another point(s) become
available during the term of this Agreement as specified in the
Tariff. However, unless otherwise agreed, the rate for transportation
service to another Point(s) of Delivery shall be Transporter's
maximum rate.
<PAGE> 6
EXHIBIT "B"
Firm Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
<TABLE>
<CAPTION>
PRIMARY PRIMARY R1
POINT(S) OF POINT(S) OF RESERVATION COMMODITY FUEL
RECEIPT DELIVERY RATE RATE TERM OF RATE REIMBURSEMENT SURCHARGES
- -------------- ----------- ----------- --------- --------------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
New meter Dumas (Note 1) (Note 1) 14 years from (Note 2) (Note 3)
station to be In-Service Date
constructed by of Cucharas
Transporter in Lateral
the north half
of Township
29S, Range
67W,
Huerfano
County, CO
</TABLE>
<TABLE>
<CAPTION>
PRIMARY PRIMARY R1
POINT(S) OF POINT(S) OF RESERVATION COMMODITY FUEL
RECEIPT DELIVERY RATE RATE TERM OF RATE REIMBURSEMENT SURCHARGES
- -------------- ------------- ----------- --------- --------------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
New meter Barbwire, Big (Note 1) (Note 1) 14 years from (Note 2) (Note 3)
station to be Blue, In-Service Date
constructed by Cattleguard, of Cucharas
Transporter in Sherman Lateral
the north half County,
of Township Tannery, and
29S, Range Tumbleweed
67W,
Huerfano
County, CO
All All (Note 4) (Note 4) 14 years from (Note 2) (Note 3)
In-Service Date
of Cucharas
Lateral
</TABLE>
NOTES: (1) (a) Except as provided in subparagraph (b) below, the rate ("Fixed
Rate") for all gas transported under this Agreement (up to the
volume of the MDQ) shall be $.2877 per Dth on a 100 percent
load factor basis plus fuel, L&U, GRI ( if applicable), and all
other surcharges applicable to Transporter's Rate Schedule
TF-1. Should Transporter's Maximum Rate as defined below, when
computed on a 100% load factor basis exceed $0.2877 per Dth,
except as provided in subparagraph (b) below, the Fixed Rate
shall nevertheless be applicable. Should Transporter's Maximum
Rate or rate components be set at a level such that Transporter
is unable to collect the Fixed Rate, then Shipper
1
<PAGE> 7
agrees to an increase in the MDQ or to other lawful
arrangements, such that the Parties are placed in the same
economic position as if Transporter had collected the Fixed
Rate.
(b) Transporter and Shipper agree that no reserve dedication, well
dedication, or acreage dedication exists. However, Transporter
is agreeing to the Fixed Rate in recognition of Shipper's
agreement to tender to Transporter for transportation under
this Agreement:
(1) Under that Firm Transportation Service Agreement between
Transporter and Shipper (CIG Contract No. 33206000), all
Available Production (other than Local Consumption) up to
the MDQ in Contract No. 33206000 as well as only Available
Production; and
(2) Under this Agreement, all additional Available Production
(other than Local Consumption) up the MDQ under this
Agreement.
For any period of time in which Shipper fails to satisfy both
conditions (1) and (2) above (as well as the additional condition set
forth in subparagraph (c) below, if applicable), then, at Transporter's
option, the rate for service under this Agreement shall be the
then-effective maximum reservation and commodity rates for firm
transportation service under Transporter's Rate Schedule TF-1, plus
fuel, L&U, GRI (if applicable), ACA and all other surcharges applicable
to Transporter's Rate Schedule TF-1 ("Maximum Rate"). In addition, the
rate for any volumes transported under this Agreement which do not
qualify as Available Production shall, at Transporter's option, either
be the Fixed Rate or the Maximum Rate. "Available Production" means the
monthly average daily volume of gas produced from leases and lease
positions owned, hereafter acquired or controlled by operation, by
Shipper or a Shipper affiliate in the geographic area described on
Exhibit "C" hereto, excluding lease use gas, line loss and gas used as
gathering fuel. "Additional Available Production" means the volume of
Available Production up to 32,000 Dth/day (other than the volume of
Available Production up to the MDQ under Contract No. 33206000). "Local
Consumption" means a volume of Available Production which Shipper
delivers from its gathering system for local consumption. Should there
exist Local Consumption, the 100% load factor rate for the first
volumes transported by Transporter up to a volume equal to such Local
Consumption shall be $.3122/Dth. Notwithstanding anything to the
contrary in this Agreement, Shipper shall have the full and complete
right to determine when and to what extent such leases and lease
positions will be developed and gas produced therefrom.
(c) Should Additional Available Production exceed the specified
MDQ level at any time (up to that volume of Additional
Available Production which causes total Available
Production to equal 32,000 Dth/day), as an additional
condition to Shipper's right to receive the Fixed Rate,
Shipper must either: (1) agree to an increase in the MDQ to
accommodate such excess volume; or (2) tender such excess
volume to Transporter for transportation as Interruptible
volumes or as Authorized Overrun volumes. The rate for such
Interruptible and Authorized Overrun services shall be
$0.2877/Dth, plus fuel, L&U, GRI, if applicable, ACA and
all other surcharges applicable to Transporter's Rate
Schedules TI-1 and TF-1.
(2) Fuel Reimbursement shall be as stated on Transporter's Schedule of
Surcharges and Fees in the Tariff, as they may be changed from time
to time, unless otherwise agreed between the Parties.
2
<PAGE> 8
EXHIBIT "C"
Firm Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JULY 1, 1998
Geographic Area of Leases
<TABLE>
<S> <C>
T275S, R67W
T28S, R66W
T29S, R66W
T30S, R66W
T27S, R68W
T28S, R67W
T29S, R67W
T30S, R67W
T28S, R68W
T29S, R68W
T30S R68W
</TABLE>
All in Huerfano and Las Animas Counties, Colorado
1
<PAGE> 1
Exhibit 10.21
Contract No. 36174000
Interruptible Transportation Service Agreement
Rate Schedule TI-1
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JANUARY 1, 1999
<PAGE> 2
INTERRUPTIBLE TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TI-1
- -------------------------------------------------------------------------------
The Parties identified below, in consideration of their mutual promises,
agree as follows:
1. TRANSPORTER: COLORADO INTERSTATE GAS COMPANY
SHIPPER: PETROGLYPH ENERGY, INC.
2. APPLICABLE TARIFF: Transporter's FERC Gas Tariff, First Revised Volume No.
1, as the same may be amended or superseded from time to time ("the
Tariff").
3. TERM OF AGREEMENT: BEGINNING: January 1, 1999
ENDING: December 31, 1999
[X] Month to month with 30-Day written notification of termination by
either Party
4. This Agreement supersedes and cancels: None.
5. Adjustments to Rate Schedule and/or General Terms and Conditions: None
6. NOTICES, STATEMENTS, AND BILLS:
TO SHIPPER:
INVOICES FOR TRANSPORTATION:
Petroglyph Energy, Inc.
1302 North Grand
Hutchinson, Kansas 67501
Attention: Craig Saldin
ALL NOTICES:
Petroglyph Energy, Inc.
1302 North Grand
Hutchinson, Kansas 67501
Attention: Craig Saldin
7. PAYMENTS/NOTICES:
TO TRANSPORTER:
See Payments, Notices, Nominations, and Points of Contact sheets
in the Tariff.
8. POINTS OF RECEIPT AND DELIVERY: Systemwide
All Point(s) of Receipt and Delivery included on Transporter's master list
of Point(s) of Receipt and Delivery as posted on its electronic bulletin
board.
For each Point of Receipt and Delivery, data posted shall include a
description of the legal location of the Point, pressure information, the
identity of the interconnected party and the measuring party, and such
other data as Transporter may include from time to time. Transporter's
master list of Point(s) of Receipt and Delivery shall be updated from time
to time in order to add or delete Point(s) of Receipt or Delivery and in
order to modify data pertinent to Point(s) of Receipt and Delivery, all as
deemed appropriate by Transporter.
<PAGE> 3
9. Each month, Shipper shall pay Transporter for Transportation Service
provided hereunder at rates and surcharges set forth in Exhibit "A."
10. OTHER: Rates shall be as set forth in Exhibit "A."
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
TRANSPORTER: SHIPPER:
COLORADO INTERSTATE GAS COMPANY PETROGLYPH ENERGY, INC.
By /s/ Thomas L. Price By /s/ S.K. Smith
-------------------------------- ------------------------------------
Thomas L. Price
Vice President
S.K. Smith
---------------------------------------
(Print or type name)
Executive Vice President
---------------------------------------
(Print or type title)
2
<PAGE> 4
EXHIBIT "A"
Interruptible Transportation Service Agreement
between
COLORADO INTERSTATE GAS COMPANY
and
PETROGLYPH ENERGY, INC.
Dated: JANUARY 1, 1999
<TABLE>
<CAPTION>
POINT(S) OF POINT(S) OF COMMODITY FUEL
RECEIPT DELIVERY RATE TERM OF RATE REIMBURSEMENT SURCHARGES
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
All All (Note 1) 01/01/99 (Note 2) (Note 3)
through
12/31/99
Evergreen
</TABLE>
NOTES: (1) Unless otherwise agreed by the Parties in writing, the
Commodity Rate for service shall be Transporter's then-effective
maximum rate for service under Rate Schedule TI-1 or other
superseding Rate Schedule, as such rates may be changed from
time to time.
(2) Fuel Reimbursement shall be as stated on Transporter's Schedule
of Surcharges and Fees in The Tariff, as they may be changed
from time to time, unless otherwise agreed between the Parties.
(3) Surcharges, If Applicable:
All applicable surcharges, unless otherwise specified, shall be
the maximum surcharge rate as stated in the Schedule of
Surcharges and Fees in The Tariff, as such surcharges may be
changed from time to time.
GQC:
The Gas Quality Control Surcharge shall be assessed pursuant
to Article 20 of the General Terms and Conditions as set
forth in The Tariff.
GRI:
The GRI Surcharge shall be assessed pursuant to Article 18 of
the General Terms and Conditions as set forth in The Tariff.
HFS:
The Hourly Flexibility Surcharge will be assessed pursuant to
Article 20 of the General Terms and Conditions as set forth
in The Tariff.
ORDER NO. 636 TRANSITION COST MECHANISM:
Surcharge(s) shall be assessed pursuant to Article 21 of the
General Terms and Conditions as set forth in The Tariff.
ACA:
The ACA Surcharge shall be assessed pursuant to Article 19 of
the General Terms and Conditions as set forth in The Tariff.
<PAGE> 1
Exhibit 10.22
SEVERANCE AGREEMENT
This Severance Agreement ("Agreement") is made and entered into as of
December 1, 1998, by and between Petroglyph Energy, Inc., a Delaware corporation
(the "Company"), and [individual listed on Exhibit A], an individual currently
residing in Hutchinson, Kansas ("Employee").
RECITALS
The Board of Directors of the Company (the "Board") has determined that
it is in the best interest of the Company to assure that the Company will have
the continued dedication of Employee, notwithstanding the possibility, threat or
occurrence of a Change of Control (as defined below). The Board believes it is
imperative to diminish the inevitable distraction of Employee by virtue of the
personal uncertainties and risks created by a pending or threatened Change of
Control, to encourage Employee's full attention and dedication to the Company
currently and in the event of any threatened or pending Change of Control, and
to provide Employee with compensation and benefit arrangements upon a Change of
Control which insures that such compensation and benefits are competitive with
other corporations.
AGREEMENT
Now, therefore, in consideration of Employee's continued employment by
the Company, as well as the promises, covenants and obligations contained
herein, the Company and Employee agree as follows:
1. Payment of Severance Amount. Upon the occurrence of a Termination
Event (as defined in paragraph 2), the Company shall:
(a) pay Employee an amount equal to (i) Employee's Base Annual
Salary (as defined in paragraph 2) multiplied by the Employment Term
Factor (as defined in paragraph 2), less (ii) the amount of salary and
bonus payments received by Employee during the period from the Change
of Control until the Termination Event, payable as a lump sum cash
payment within 30 business days after the date of the termination
constituting such Termination Event (the "Termination Date");
(b) (i) provide Employee with life and disability insurance
and (ii) pay Employee an amount equal to the cost of medical insurance
coverage at the level provided as of the Termination Date, both for a
period following the Termination Date equal to (A) eighteen months less
(B) the number of months (rounded to the nearest whole month) during
the period from the Change of Control until the Termination Event, or,
if earlier with respect to clause (ii) above only, until Employee shall
obtain substantially equivalent insurance coverage from a subsequent
employer. Employee shall immediately notify the Company upon obtaining
any insurance from a subsequent employer and shall provide all
information required by the Company regarding such insurance to enable
the Company to make a determination of whether such insurance is
substantially equivalent;
(c) for a period of twelve months from and after such
Termination Event, or until such earlier time as Employee obtains other
employment, provide Employee (at no cost to Employee) with outplacement
services of a firm of Employee's choice; and
(d) pay all reasonable legal fees and expenses incurred by
Employee in seeking to obtain or enforce any right or benefit provided
by this Agreement.
<PAGE> 2
2. Definitions.
(a) A "Termination Event" shall be deemed to have occurred if:
(i) at any time within 180 days following a Change of
Control:
(A) the Company or any successor thereto
shall terminate Employee's employment for any reason
other than for Cause; or
(B) Employee shall voluntarily terminate his
employment with the Company or any successor thereto
for "Good Reason." For purposes of this Agreement,
"Good Reason" shall mean any of the following
(without Employee's express written consent):
(1) A material change in the nature
or scope of Employee's duties from those
engaged in by Employee immediately prior to
the date on which a Change of Control
occurs;
(2) A reduction in Employee's base
salary from that provided to him immediately
prior to the date the Change of Control
occurs;
(3) A material diminution in
Employee's eligibility to participate in or
in benefits provided to Employee under
bonus, stock option or other incentive
compensation plans or employee welfare and
pension benefit plans (including medical,
dental, life insurance, retirement and
long-term disability plans) from that
provided to him immediately prior to the
date the Change in Control occurs; or
(4) Any required relocation of
Employee of more than thirty miles from the
location where Employee was based and
performed services on the date of this
Agreement (including any required business
travel in excess of the greater of 90 days
per year or the level of business travel of
Employee for the year prior to the most
recent Change of Control); or
(ii) Employee and the Company, or any successor
thereto, shall fail to reach an agreement on or prior to the
date of closing of a transaction that constitutes a Change of
Control as to the terms of Employee's employment following
such Change of Control, which terms are acceptable to Employee
in his sole discretion.
(b) A "Change of Control" shall be deemed to have occurred if:
(i) individuals who, as of the date hereof,
constitute the Board (the "Incumbent Board") cease for any
reason to constitute at least fifty percent (50%) of the
Board, provided that any person becoming a director subsequent
to the date hereof whose election, or nomination for election
by the Company's stockholders was approved by a vote of at
least a majority of the directors then comprising the
Incumbent Board shall be, for purposes of this Agreement,
considered as though such person were a member of the
Incumbent Board; or
-2-
<PAGE> 3
(ii) the stockholders of the Company shall approve a
reorganization, merger or consolidation, in each case, with
respect to which persons who were the stockholders of the
Company immediately prior to such reorganization, merger or
consolidation do not, immediately thereafter, own more than
fifty percent (50%) of the combined voting power entitled to
vote generally in the election of directors of the
reorganized, merged or consolidated company's then outstanding
voting securities, or of a liquidation or dissolution of the
Company or of the sale of all or substantially all of the
assets of the Company; or
(iii) the stockholders of the Company shall approve a
sale of all or substantially all of the assets of the Company;
or
(iv) a stock sale, reorganization, merger or
consolidation of the Company takes place and the Company
and/or its subsidiaries do not, immediately thereafter, own
more than 50% of the combined voting power entitled to vote
generally in the election of directors of the sold,
reorganized, merged or consolidated company's then outstanding
voting securities; or
(v) all or substantially all of the assets of the
Company are sold.
(c) "Employment Factor" is the factor shown on the attached
Exhibit A, which is incorporated herein by this reference for all
purposes.
(d) "Base Annual Salary", as determined on the Termination
Date, shall be equal to the greater of (i) Employee's annual salary on
the date of the earliest Change of Control to occur during the
eighteen-month period prior to the Termination Date plus any bonuses or
special incentive payments received in the twelve-month period prior to
such Change of Control or (ii) Employee's annual salary on the
Termination Date plus any bonuses or special incentive payments
received in the twelve-month period prior to the Termination Date.
(e) "Cause" as used herein with respect to Employee's
termination of employment shall include any of the following: (A)
Employee's conviction of, or plea of nolo contendere to, any felony or
to any crime or offense causing substantial harm to the Company or its
affiliates or involving acts of theft, fraud, embezzlement, moral
turpitude or similar conduct; (B) malfeasance in the conduct of
Employee's duties, including, but not limited to, (1) willful and
intentional misuse or diversion of funds of the Company, or its
affiliates, that constitutes willful misconduct or gross negligence on
the part of Employee, (2) embezzlement, or (3) fraudulent or willful
and material misrepresentations or concealments on any written reports
submitted to the Company or its affiliates; or (C) Employee's material
failure to perform the duties of Employee's employment or material
failure to follow or comply with the reasonable and lawful written
directives of the Board of Directors of the Company, in either case
after Employee shall have been informed, in writing, of such material
failure and given a period of not more than 60 days to remedy same. For
purposes of this paragraph, no act, or failure to act, on Employee's
part shall be considered "willful" unless done, or omitted to be done,
by Employee not in good faith and without reasonable belief that
Employee's action or omission was in the best interest of the Company.
Notwithstanding the foregoing, Employee shall not be deemed to have
been terminated for cause unless and until there shall have been
delivered to Employee a copy of a notice of termination from the Chief
Executive Officer of the Company or the Board of Directors, after
reasonable notice to Employee and an opportunity for Employee, together
with Employee's counsel, to be heard before the Board of Directors,
finding that, in the good faith opinion of the Board, Employee was
guilty of conduct set forth above in clauses (A), (B) or (C) of the
first sentence of this subparagraph and specifying the particulars
thereof in detail.
-3-
<PAGE> 4
3. Parachute Payment Limitations. Any other provision of this Agreement
to the contrary notwithstanding, if the total amount of payments and benefits to
be paid or provided to Employee under this Agreement which are considered to be
"parachute payments" within the meaning of Section 280G of the Internal Revenue
Code of 1986, as amended (the "Code"), when added to any other such "parachute
payments" received by Employee from the Company or from a member of the
Company's affiliated group (as provided in Code Section 280G(d)(5)), whether or
not under this Agreement, are in excess of the amount Employee can receive
without causing the Company to lose its deduction with respect to all or any
portion of such total amount on account of Code Section 280G, the amount of
payments and benefits to be paid or provided to Employee under this Agreement
which are parachute payments shall be reduced to the highest amount which will
not cause the Company to lose its deduction with respect to any such payments
and benefits on account of Code Section 280G. In the event that payments or
benefits to be provided under this Agreement are required to be reduced under
this Section, the Company shall notify Employee in writing of the amount of such
reduction (the "Reduction Notice") within 15 business days following Employee's
Termination Date. Employee shall have the right to elect which payments and/or
benefits hereunder shall be reduced within 15 business days following the date
on which Employee receives the Reduction Notice. If no such election is received
by the Company within such 15-business-day period, the reduction shall be made
from such payments or benefits as the Company shall determine in its discretion.
4. Notices. For purposes of this Agreement, notices and all other
communications provided for herein shall be in writing and shall be deemed to
have been duly given when personally delivered or when mailed by United States
registered or certified mail, return receipt requested, postage prepaid,
addressed as follows:
If to the Company to: Petroglyph Energy, Inc.
1302 North Grand
Hutchinson, Kansas 67501
or
Petroglyph Energy, Inc
P.O. Box 1839
Hutchinson, Kansas 67504-1839
If to Employee to: [Address of Employee]
or to such other address as either party may furnish to the other in writing in
accordance herewith, except that notices of changes of address shall be
effective only upon receipt.
5. Applicable Law. This contract is entered into under, and shall be
governed for all purposes by, the laws of the State of Kansas.
6. Severability. If a court of competent jurisdiction determines that
any provision of this Agreement is invalid or unenforceable, then the invalidity
or unenforceability of that provision shall not affect the validity or
enforceability of any other provision of this Agreement, and all other
provisions shall remain in full force and effect.
7. Counterparts. This Agreement may be executed in one or more
counterparts, each of which shall be deemed to be an original, but all of which
together will constitute one and the same Agreement.
-4-
<PAGE> 5
8. Withholding of Taxes. The Company may withhold from any benefits
payable under this Agreement all federal, state, city or other taxes as may be
required pursuant to any law or governmental regulation or ruling.
9. No Employment Agreement. Nothing in this Agreement shall give
employee any rights (or impose any obligations) to continued employment by the
Company or any subsidiary thereof or successor thereto, nor shall it give the
Company any rights (or impose any obligations) with respect to continued
performance of duties by Employee for the Company or any subsidiary thereof or
successor thereto.
10. Assignment.
(a) This Agreement is personal in nature and neither of the
parties hereto shall, without the consent of the other, assign or
transfer this Agreement or any rights or obligations hereunder, except
as provided in the remainder of this paragraph 10. Without limiting the
foregoing, Employee's right to receive payments hereunder shall not be
assignable or transferable, whether by pledge, creation of a security
interest or otherwise, other than a transfer by his will or by the laws
of descent or distribution, and in the event of any attempted
assignment or transfer contrary to this paragraph 10 the Company shall
have no liability to pay any amount so attempted to be assigned or
transferred. This Agreement shall inure to the benefit of and be
enforceable by Employee's personal or legal representatives, executors,
administrators, successors, heirs, distributees, devisees and legatees.
(b) The Company may: (x) as long as it remains obligated with
respect to this Agreement, cause its obligations hereunder to be
performed by a subsidiary or subsidiaries for which Employee performs
services, in whole or in part; (y) assign this Agreement and its rights
hereunder in whole, but not in part, to any corporation with or into
which it may hereafter merge or consolidate or to which it may transfer
all or substantially all of its assets, if said corporation shall by
operation of law or expressly in writing assume all liabilities of the
Company hereunder as fully as if it has been originally named the
Company herein; but may not otherwise assign this Agreement or its
rights hereunder. Subject to the foregoing, this Agreement shall inure
to the benefit of and be enforceable by the Company's successors and
assigns.
11. Modifications. This Agreement shall not be varied, altered,
modified, canceled, changed or in any way amended except by mutual agreement of
the parties in a written instrument executed by the parties hereto or their
legal representatives.
-5-
<PAGE> 6
IN WITNESS WHEREOF, the parties have caused this Agreement to be
executed and delivered as of the day and year first above written.
PETROGLYPH ENERGY, INC.
By:
----------------------------------------
Name: Robert C. Murdock
Title: President
EMPLOYEE
-------------------------------------------
Name:
-6-
<PAGE> 7
EXHIBIT A
<TABLE>
<CAPTION>
Employee Factor
- ---------------- ------
<S> <C>
Robert C. Murdock 2.00
Robert A. Christensen 1.75
S. Kennard Smith 1.75
Tim A. Lucas 1.20
</TABLE>
<PAGE> 1
EXHIBIT 21
<TABLE>
<CAPTION>
Subsidiary Jurisdiction
- ----------------------------------- ------------
<S> <C>
Petroglyph Operating Company, Inc. Kansas
Rio Cucharas Pipeline Company, Inc. Colorado
</TABLE>
<PAGE> 1
Exhibit 23.1
[LEE KEELING AND ASSOCIATES, INC. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
Lee Keeling and Associates, Inc. ("Lee Keeling") hereby consents to
references to Lee Keeling as expert and to its reserve reports and to
information depicted in the Annual Report on Form 10-K for the year ended
December 31, 1998 for Petroglyph Energy, Inc., a Delaware corporation, that was
derived from our reserve reports.
LEE KEELING AND ASSOCIATES, INC.
By: /s/ Kenneth Renberg
---------------------------------------
Kenneth Renberg, Vice President
Tulsa, Oklahoma
March 25, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<EXCHANGE-RATE> 1,000
<CASH> 2,008
<SECURITIES> 0
<RECEIVABLES> 1,233
<ALLOWANCES> 0
<INVENTORY> 1,234
<CURRENT-ASSETS> 4,723
<PP&E> 52,288
<DEPRECIATION> (11,590)
<TOTAL-ASSETS> 46,035
<CURRENT-LIABILITIES> 2,771
<BONDS> 0
0
0
<COMMON> 55
<OTHER-SE> 35,257
<TOTAL-LIABILITY-AND-EQUITY> 46,035
<SALES> 4,278
<TOTAL-REVENUES> 4,468
<CGS> 11,181
<TOTAL-COSTS> 11,181
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 407
<INCOME-PRETAX> (6,247)
<INCOME-TAX> 2,061
<INCOME-CONTINUING> (4,186)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4,186)
<EPS-PRIMARY> (0.77)
<EPS-DILUTED> (0.77)
</TABLE>
