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, 1997
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
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6209 North Highway 61
Hutchinson, Kansas 67502
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(Address of principal executive offices) (Zip Code)
(316) 665-8500
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
- ----------------------------------- --------------------------------------
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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 25, 1998, 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 25, 1998, as reported on the Nasdaq National Market, was
approximately $23,625,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1998 Annual
Meeting of Stockholders to be held on May 27, 1998, 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, 1997.
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TABLE OF CONTENTS
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Page
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PART I
Item 1. Business..............................................................1
Item 2. Properties............................................................6
Item 3. Legal Proceedings....................................................10
Item 4. Submission of Matters to a Vote of Security Holders..................11
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters..............................................................12
Item 6. Selected Financial Data..............................................13
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................14
Item 8. Financial Statements and Supplementary Data..........................25
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................26
PART III
Item 10. Directors and Executive Officers of the Registrant...................26
Item 11. Executive Compensation...............................................26
Item 12. Security Ownership of Certain Beneficial Owners and Management.......26
Item 13. Certain Relationships and Related Party Transaction..................26
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 10-K.....26
Glossary of Oil and Natural Gas Terms.........................................29
Signatures....................................................................32
Index to Combined Financial Statements.......................................F-1
i
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PETROGLYPH ENERGY, INC.
1997 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. Since its
inception in 1993, the Company has grown through leasehold acquisitions which,
together with associated development and exploratory drilling, have increased
the Company's proved reserves, production, revenue and cash flow. 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 $15
million in 1998 in connection with these projects. The Company has identified
several other formations in the Uinta Basin above and below the Lower Green
River formation that it believes have the potential to be commercially
productive. The Company recently acquired 63,000 gross and net acres in the
Raton Basin in Colorado and plans to spend up to $5.5 million in 1998 to
initiate a pilot coalbed methane project intended to determine the commercial
viability of development of this area. In addition, the Company has a 100%
working interest in 5,079 gross and net acres in the Helen Gohlke field located
within the Wilcox Trend in the Gulf Coast Region of South Texas. The Company is
currently reviewing the results of a 3-D seismic survey of this acreage and
intends to drill with an industry partner at least three gross (1.5 net) wells
on this acreage during 1998.
In November 1997, Petroglyph completed its initial public offering (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, with the balance of
the proceeds to be 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.
As of December 31, 1997, the Company had estimated net proved reserves of
approximately 9.5 MMBbls of oil and 20.7 Bcf of natural gas, or an aggregate of
12.9 MMBOE with a PV-10 of $43.4 million. Of the Company's estimated proved
reserves, 97% are located in the Uinta Basin. At December 31, 1997, the Company
had a total acreage position of approximately 116,000 gross (106,000 net) acres
and estimates that it had over 1,000 potential drilling locations based on
current spacing, approximately 80 of which are included in the Company's
independent petroleum engineers' estimate of proved reserves.
The Company's strategy is to increase its oil and natural gas reserves, oil
and natural gas production and cash flow per share 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 and (iv) the acquisition
of additional property interests.
1
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The Company was formed in 1997 for the purpose of becoming the holding
company for Petroglyph Gas Partners, L.P., pursuant to the terms of an exchange
agreement dated August 22, 1997. Petroglyph Gas Partners, L.P. was formed in
1993 and grew primarily through acquisition of oil and natural gas properties
and the development of such properties. Under the exchange agreement, effective
upon consummation of 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 Petroglyph Gas Partners, L.P. 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. owns, directly or indirectly, all the partnership interests in
Petroglyph Gas Partners, L.P. References to the "Company" are to Petroglyph
Energy, Inc. and its predecessors and subsidiaries, including Petroglyph Gas
Partners, L.P.
The Company is incorporated in the State of Delaware, its principal
executive offices are located at 6209 North Highway 61, Hutchinson, Kansas 67502
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, 1997, 1996 and 1995, the volumes sold under this
contract totaled approximately 74 MBbls, 61 MBbls and 101 MBbls, respectively,
at an average sales price per Bbl for each year of $14.80, $19.33 and $17.09,
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. In addition to the sales
contract discussed above, the purchaser has the option under an Oil Production
Call Agreement to purchase all or any portion of the oil produced from the
Antelope Creek field at the current market price. The option has no set
expiration date.
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 is effective until May 31, 1998 and
calls 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
73 MBbls at an average price of $14.50 for the year ended December 31, 1997.
Hedging Activities
The Company historically has used various financial instruments such as
collars, swaps and futures contracts in an attempt 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 that have been historically used by the Company have not had a
contractual obligation which requires or allows 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 309 MBbls of the Company's expected oil production through
December 31, 1999 is subject to collars with a NYMEX floor price of $17.00 and a
ceiling price of $20.75 based on NYMEX pricing.
2
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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
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, 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. In addition, recent heavy drilling activity by a number of
operators in the Uinta Basin may reduce or limit the availability of equipment
and supplies or reduce demand for the Company's production, either of which
would impact the Company more adversely than if the Company were geographically
diversified.
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.
3
<PAGE>
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.
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 and to actively recruit members of the Ute Indian Tribe
to work on the drilling operations.
4
<PAGE>
Environmental Matters. The Company's operations and properties are subject
to extensive and changing federal, state and local laws and regulations relating
to environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to safety and health. The recent trend in environmental legislation and
regulation generally is toward stricter standards, and this trend will likely
continue. These laws and regulations may (i) require the acquisition of a permit
or other authorization before construction or drilling commences and for certain
other activities; (ii) limit or prohibit construction, drilling and other
activities on certain lands lying within wilderness and other protected areas;
and (iii) impose substantial liabilities for pollution resulting from the
Company's operations. The permits required for various of the Company's
operations are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce their
regulations, and violations are subject to fines or injunctions, or both. In the
opinion of management, the Company is in substantial compliance with current
applicable environmental laws and regulations, and the Company has no material
commitments for capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws and
regulations or in interpretations thereof could have a significant impact on the
Company, as well as the oil and natural gas industry in general.
The Comprehensive Environmental, Response, Compensation, and Liability Act
("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. It is
not uncommon for the neighboring land owners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. The Federal Resource Conservation and
Recovery Act ("RCRA") and comparable state statutes govern the disposal of
"solid waste" and "hazardous waste" and authorize the imposition of substantial
fines and penalties for noncompliance. Although CERCLA currently excludes
petroleum from its definition of "hazardous substance," state laws affecting the
Company's operations impose clean-up liability relating to petroleum and
petroleum related products. In addition, although RCRA classifies certain oil
field wastes as "non-hazardous," such exploration and production wastes could be
reclassified as hazardous wastes thereby making such wastes subject to more
stringent handling and disposal requirements.
The Company has acquired leasehold interests in numerous properties that
for many years have produced oil and natural gas. Although the previous owners
of these interests may have used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties. In addition, some of the
Company's properties may be operated in the future by third parties over whom
the Company has no control. Notwithstanding the Company's lack of control over
properties operated by others, the failure of the operator to comply with
applicable environmental regulations may, in certain circumstances, adversely
impact the Company.
NEPA. The National Environmental Policy Act ("NEPA") is applicable to many
of the Company's activities and operations. NEPA is a broad procedural statute
intended to ensure that federal agencies consider the environmental impact of
their actions by requiring such agencies to prepare environmental impact
statements ("EIS") in connection with all federal activities that significantly
affect the environment. Although NEPA is a procedural statute only applicable to
the federal government, a large portion of the Company's Uinta Basin acreage is
located either on federal land or Ute tribal land jointly administered with the
federal government. The Bureau of Land Management's issuance of drilling permits
and the Secretary of the Interior's approval of plans of operation and lease
agreements all constitute federal action within the scope of NEPA. Consequently,
unless the responsible agency determines that the Company's drilling activities
will not materially impact the 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.
5
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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 production
in paying quantities prior to expiration of various time periods to avoid lease
termination.
Other Facilities
The Company currently leases approximately 3,300 square feet of office
space in Hutchinson, Kansas, where its principal offices are located. A
significant portion of the Company's principal offices are leased through Hutch
Realty LLC, an affiliate of the Company.
Employees
As of December 31, 1997, the Company had 48 full-time employees, none of
whom is represented by any labor union. Included in the total were 20 corporate
employees located in the Company's office in Hutchinson, Kansas.
The Company considers its relations with its employees to be good.
ITEM 2. PROPERTIES
General
The Company's primary 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'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.
The Company acquired 63,000 gross and net acres in the Raton Basin in
Colorado in 1997, where the Company plans to develop coalbed methane natural gas
reserves. Coalbed methane production is similar to 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.
The Company has a 100% working interest in 5,079 gross and net acres in the
Helen Gohlke field located within the Wilcox Trend in the Gulf Coast Region of
South Texas. The Company is currently reviewing the results of a 3-D seismic
survey of this acreage and intends to drill with an industry partner at least
three gross (1.5 net) wells on this acreage during 1998.
6
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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, 1997,
1996 and 1995:
<TABLE>
As of December 31,
--------------------------------------------------------------
1997 1996 1995
------------------ ------------------ ------------------
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............. 4,620 9,202 568 1,600 870 1,219
Other............ 122 1,637 297 1,410 691 5,440
------ ------ ------ ------ ------ ------
Total......... 4,742 10,839 865 3,010 1,561 6,659
------ ------ ------ ------ ------ ------
Proved undeveloped:
Utah............. 4,714 9,856 5,262 15,802 -- --
------ ------ ------ ------ ------ ------
Total......... 4,714 9,856 5,262 15,802 -- --
------ ------ ------ ------ ------ ------
Total proved.. 9,456 20,695 6,127 18,812 1,561 6,659
====== ====== ====== ====== ====== ======
</TABLE>
The following table sets forth the future net cash flows from the Company's
estimated proved reserves:
As of December 31,
1997 1996 1995
---------- ---------- ----------
(In thousands)
Future net cash flow before income taxes:
Utah.................................... $ 96,768 $ 117,101 $ 10,019
Other................................... 2,469 6,699 12,412
---------- ---------- ----------
Total............................... $ 99,237 $ 123,800 $ 22,431
========== ========== ==========
Future net cash flow before income taxes, discounted at 10%:
Utah.................................... $ 41,631 $ 59,447 $ 7,421
Other................................... 1,798 4,656 7,553
---------- ---------- ----------
Total............................... $ 43,429 $ 64,103 $ 14,974
========== ========== ==========
The reserve estimates for 1997 were prepared by Lee Keeling and Associates
Inc., the Company's independent petroleum engineers. The reserve estimates
reflected above for 1996 and 1995 were prepared by the Company.
7
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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 represents 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 drilling 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.
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, 1997, the Company
was in the process of completing 8 gross (4 net) wells as producers.
Year Ended December 31,
--------------------------------------------------------------
1997 1996 1995
------------------ ------------------ ------------------
Gross Net Gross Net Gross Net
------- --------- ------ ---------- ------- ---------
Exploratory:
Oil.............. 2 2.0 -- -- -- --
Natural gas...... 2 1.0 -- -- -- --
Nonproductive.... -- -- -- -- 3 2.5
------- --------- ------ ---------- ------- ---------
Total........ 4 3.0 -- -- 3 2.5
======= ========= ====== ========== ======= =========
Development:
Oil.............. 52 26.0 38 19.0 9 4.5
Natural gas...... -- -- -- -- 2 1.0
Nonproductive.... -- -- -- -- -- --
------- --------- ------ ---------- ------- ---------
Total........ 52 26.0 38 19.0 11 5.5
======= ========= ====== ========== ======= =========
Total:
Productive....... 56 29.0 38 19.0 11 5.5
Nonproductive.... -- -- -- -- 3 2.5
------- --------- ------ ---------- ------- ---------
Total....... 56 29.0 38 19.0 14 8.0
======= ========= ====== ========== ======= =========
As a result of 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.
8
<PAGE>
Productive Well Summary
The following table sets forth the Company's ownership interest as of
December 31, 1997 in productive oil and natural gas wells in the development
areas indicated.
<TABLE>
Oil Natural Gas Total
----------------- ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Area
- ----
Utah:
Antelope Creek Field..... 116 58 -- -- 116 58
Duchesne Field........... 6 6 -- -- 6 6
Natural Buttes Extension. -- -- -- -- -- --
-------- -------- -------- -------- -------- --------
Total............... 122 64 -- -- 122 64
Colorado................. -- -- -- -- -- --
Other.................... 8 8 7 7 15 15
-------- -------- -------- -------- -------- --------
Total............... 130 72 7 7 137 79
======== ======= ======= ======== ======== ========
</TABLE>
In addition, as of December 31, 1997, the Company had 22 gross (11 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>
Year Ended December 31,
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Net production (1):
Oil (Bbls).................... 251,631 262,910 182,704
Natural gas (Mcf)............. 537,466 553,770 659,202
Oil equivalent (BOE).......... 341,209 355,205 292,571
Average sales price (2):
Oil (per Bbl):
Utah (3).................. $14.37 $ 15.82 $ 18.34
Other..................... 18.94 20.35 16.30
Weighted average (4)...... 14.84 16.96 17.61
Natural gas (per Mcf):
Utah...................... $ 1.91 $ 1.64 $ 1.40
Other..................... 2.37 1.96 1.69
Weighted average.......... 1.99 1.80 1.54
Average lease operating expenses including
production and property taxes (per BOE):
Utah.......................... $ 3.67 $ 5.21 $ 6.06
Other......................... 15.08 11.99 11.68
Weighted average.............. 5.09 7.37 8.37
- -----------------------------------
</TABLE>
9
<PAGE>
(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 $15.12, $20.18 and $17.03 for the years
ended December 31, 1997, 1996 and 1995, 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
$15.52, $20.22 and $16.77 for the years ended December 31, 1997, 1996 and
1995, respectively.
Development, Exploration and Acquisition Expenditures
The following table sets forth the costs incurred by the Company in its
development, exploration and acquisition activities during the periods
indicated.
Year Ended December 31,
-----------------------
1997 1996 1995
------------- -------------- -----------
Acquisition costs:
Unproved properties..... $ 1,721,636 $ 490,487 $ 8,206
Proved properties....... 147,387 -- 4,718,201
Development costs............ 10,003,468 6,983,715 3,448,972
Exploration costs............ -- -- 316,089
Improved recovery costs...... 895,317 327,027 154,023
------------- -------------- -----------
Total............... $ 12,767,808 $ 7,801,229 $ 8,645,491
============= ============== ===========
Acreage
The following table sets forth, as of December 31, 1997, the gross and net
acres of developed and undeveloped oil and natural gas leases which the Company
holds or has the right to acquire.
Developed Undeveloped Total
---------------- ---------------- -----------------
Area Gross Net Gross Net Gross Net
- ---- ------- ------- ------- ------- ------- --------
Utah:
Antelope Creek Field...... 5,600 2,880 15,383 9,823 20,983 12,703
Duchesne Field............ 1,240 1,240 10,779 10,155 12,019 11,395
Natural Buttes Extension.. -- -- 13,253 13,253 13,253 13,253
------- ------- ------- ------- ------- --------
Total................ 6,840 4,120 39,415 33,231 46,255 37,351
------- ------- ------- ------- ------- -------
Colorado.................. -- -- 63,000 63,000 63,000 63,000
Other..................... 6,279 5,663 -- -- 6,279 5,663
------- ------- ------- ------- ------- --------
Total................ 13,119 9,783 102,415 96,231 115,534 106,014
======= ======= ======= ======= ======= ========
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any material legal proceedings.
10
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the Company's security holders between
October 20, 1997, the effective date of the Company's initial public offering,
and December 31, 1997.
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, 1997:
Name Age Position
---- --- --------
Robert C. Murdock.... 40 President, Chief Executive Officer and Chairman
of the Board
Robert A. Christensen 51 Executive Vice President, Chief Technical
Officer and Director
Sidney Kennard Smith. 55 Executive Vice President, Chief Operating
Officer and Secretary
Tim A. Lucas......... 33 Vice President, Chief Financial Officer and
Treasurer
Set forth below is a description of the backgrounds of each executive
officer of the Company, including employment history for at least the last five
years.
Robert C. Murdock has served as President, Chief Executive Officer and
Chairman of the Board of the Company since its inception in 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.
Sidney Kennard 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.
11
<PAGE>
Tim A. Lucas has served as Vice President, Chief Financial Officer and
Treasurer of the Company since July 1997. From 1994 through 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 1989 to
1994, Mr. Lucas worked in the energy group of the audit division of Arthur
Andersen LLP. Mr Lucas is a Certified Public Accountant and a member of the
American Institute of Certified Public Accountants and the Oklahoma Society of
Certified Public Accountants.
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 under the symbol "PGEI" since the Company's initial public offering
effective October 20, 1997. The high and low closing sales prices of the Common
Stock as reported by the Nasdaq National Market from October 20, 1997 to
December 31, 1997 were $13.875 and $6.75, respectively.
As of March 18, 1998, the Company estimates that there were more than 400
stockholders (including brokerage firms and other nominees) of the Company's
Common Stock.
No dividends have been declared or paid on the Company's Common Stock to
date. For the foreseeable future, the Company intends to retain any earnings for
the development of its business.
12
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected combined financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's combined financial
statements and related notes included in "Item 8. Combined Financial Statements
and Supplementary Data."
<TABLE>
Year Ended December 31,
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(in thousands, except per share amounts and operating data)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data:
Operating revenues:
Oil sales.....................................$ 3,735 $ 4,459 $ 3,217 $ 1,644 $ 224
Natural gas sales............................. 1,070 999 1,016 796 182
Other......................................... 61 -- 36 45 86
-------- -------- -------- --------- --------
Total operating revenues.................. 4,866 5,458 4,269 2,485 492
-------- -------- -------- --------- --------
Operating expenses:
Lease operating............................... 1,560 2,369 2,260 1,601 238
Production taxes.............................. 179 299 188 89 9
Exploration costs............................. -- 69 376 70 --
Depreciation, depletion and amortization...... 1,852 2,806 2,302 1,977 153
Impairments................................... -- -- 109 -- --
General and administrative.................... 1,300 902 1,064 956 278
-------- -------- -------- --------- --------
Total operating expenses.................. 4,891 6,395 6,299 4,693 678
-------- -------- -------- --------- --------
Operating loss.................................... (25) (937) (2,030) (2,208) (186)
Other income (expenses):
Interest income (expense), net................ 114 40 (216) (93) --
Gain (loss) on sales of property and
equipment, net............................ 12 1,384 (138) 44 63
-------- -------- -------- --------- --------
Net income (loss) before income taxes............. 101 487 (2,384) (2,257) (123)
Income tax expense (1)............................ (2,514) (190) -- -- --
-------- -------- -------- --------- --------
Net income (loss).................................$ (2,413) $ 297 $(2,384) $ (2,257) $ (123)
======== ======== ======== ========= ========
Supplemental pro forma earnings (loss) per
common share (2)..................................$ (.73) $ .11 $ (.84)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities..........................$ 1,633 $ 4,129 $ 347 $ (67) $ 4
Investing activities.......................... (15,514) 303 (9,580) (8,131) (1,084)
Financing activities.......................... 28,982 (3,930) 10,049 8,119 1,418
Other Financial Data:
Capital expenditures..............................$ 16,260 $ 8,665 $10,443 $ 8,277 $ 1,136
Adjusted EBITDA (3)............................... 1,839 3,322 619 (117) 30
Operating cash flow (4)........................... 1,896 2,024 608 (233) (33)
Balance Sheet Data:
Cash and cash equivalents.........................$ 16,679 $ 1,578 $ 1,075 $ 258 $ 338
Working capital................................... 14,872 (541) 1,133 113 359
Total assets...................................... 46,714 17,470 17,598 9,685 2,392
Total long-term debt.............................. -- 52 3,900 1,800 --
Total stockholders' equity........................ 39,498 12,695 12,207 6,592 2,218
</TABLE>
(1) Income tax expense was computed at the federal statutory rate of 35% and
an average of the state statutory rates for those states in which the
company has operations of 4% for each period presented. Tax information
for 1996 is shown as pro forma to reflect income tax expense as if
Partnership income were subject to federal income tax.
13
<PAGE>
(2) Weighted average common shares outstanding used in the calculation of
earnings (loss) per common share for the years ended December 31, 1997,
1996 and 1995 were 3,326,826 for 1997 and 2,833,333 (pro forma) shares
for 1996 and 1995.
(3) Adjusted EBITDA (as used herein) is calculated by adding interest, income
taxes, depreciation, depletion and amortization, impairments and
exploration costs to net income (loss). Interest includes interest
expense accrued and amortization of deferred financing costs. The Company
did not incur impairment expense for any period reported except for
$109,000 for the year ended December 31, 1995. Exploration costs were
zero, $69,000, $376,000, $70,000 and zero for each of the years ended
December 31, 1997, 1996, 1995, 1994 and 1993. 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.
Management believes that the recent increases in Adjusted EBITDA are
indicative of the increased production volumes and decreased operating
costs experienced by the Company. 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:
Year Ended December 31,
1997 1996 1995
-------- -------- --------
Production Data(1):
Oil (Bbls)................................ 251,631 262,910 182,704
Natural Gas (Mcf)......................... 537,466 553,770 659,202
Total (BOE).......................... 341,209 355,205 292,571
Average Sales Price Per Unit(2):
Oil (per Bbl)(3).......................... $ 14.84 $ 16.96 $ 17.61
Natural Gas (per Mcf)..................... 1.99 1.80 1.54
BOE....................................... 14.08 15.36 14.47
Costs Per BOE:
Lease operating expense................... $ 4.57 $ 6.67 $ 7.73
Production and property taxes............. .52 0.70 0.64
General and administrative................ 3.81 2.54 3.64
Depreciation, depletion and amortization.. 5.43 7.90 7.87
Average finding costs(4).................. 3.00 2.86 10.96
(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.
14
<PAGE>
(3) Excluding the effects of crude oil hedging transactions and amortization
of deferred revenue, the weighted average sales price per Bbl of oil was
$15.52, $20.22 and $16.77 for the years ended December 31, 1997, 1996 and
1995, respectively.
(4) The calculation of average finding costs for the years ended December 31,
1997 and 1996 includes future development costs of $2.7 million and $16.5
million, respectively. Average finding costs per BOE excluding these
amounts were $2.37 and $.85 for the years ended December 31, 1997 and
1996, respectively. Future development costs were insignificant in 1995.
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, 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.
15
<PAGE>
Operating Expenses
Lease operating expenses decreased 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.
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 deferred tax liabilities and income tax
expense on the date of the Conversion.
16
<PAGE>
Year Ended December 31, 1996 Compared to December 31, 1995
Operating Revenues
Oil revenues increased by 39% to $4,459,000 in 1996 as compared to
$3,217,000 in 1995 primarily as a result of an increase in the Company's oil
production volume of approximately 80,000 Bbls in 1996. The increase in
production volume is primarily the result of the Company's aggressive drilling
program on its Utah properties during the last six months of 1996. This increase
was partially offset by a decline in average oil sales prices from $17.61 per
Bbl in 1995 to $16.96 per Bbl in 1996. The decline in the average oil sales
price was due to a reduction in demand for the Company's Utah oil production
during the second half of 1996 as a result of a temporary shutdown for major
maintenance of one of the refineries which is a primary purchaser of the
Company's Utah production, a crude oil hedge loss of $128,000 and amortization
of deferred revenue of $524,000. The Company's average 1996 sales price of oil
excluding the effects of the hedge loss and amortization of deferred revenue was
$20.22 per Bbl.
Natural gas revenues declined by 2% to $999,000 in 1996 as compared to
$1,016,000 in 1995 primarily due to a decline in natural gas sales production to
553,770 Mcf in 1996 as compared to 659,202 Mcf in 1995. The decline in natural
gas sales production is attributable to disposition of certain nonstrategic
natural gas properties during 1996 and reduced gas production volumes from the
Utah properties due to inception of the secondary oil recovery program. The
decrease in natural gas production volumes was partially offset by an increase
in average sales prices of natural gas to $1.80 per Mcf in 1996 as compared to
$1.54 per Mcf in 1995.
Operating Expenses
Lease operating expenses increased to $2,369,000 in 1996 as compared to
$2,260,000 in 1995 primarily as a result of an increase in the number of
producing wells in which the Company has an interest due to the 1996 drilling
program, partially offset by a reduction in lease operating expenses per BOE to
$6.67 in 1996 as compared to $7.73 in 1995. The 14% decrease in lease operating
expenses on a per BOE basis is primarily due to a decline in production costs of
the Utah properties due to the Company's continued focus on reduction of
operating costs through improved efficiencies. This decrease is partially offset
by an increase in per BOE production costs of the Company non-Utah properties.
Production taxes increased by 33%, or $61,000, from 1995 to 1996. This
increase is due primarily to a 29% increase in the Company's oil and natural gas
revenues during 1996 as compared to 1995.
Depreciation, depletion and amortization expense increased by 22% to
$2,806,000 in 1996 as compared to $2,302,000 in 1995, primarily as a result of
increased production volumes due to 1996 drilling activity. Depreciation,
depletion and amortization expense increased slightly to $7.90 per BOE in 1996
as compared to $7.87 per BOE in 1995.
Exploration costs declined by 82% to $69,000 in 1996 as compared to
$376,000 in 1995 due to a reduction in dry hole costs in 1996.
General and administrative expenses decreased by 15% to $902,000 in 1996
as compared to $1,064,000 in 1995. This decline was due to an increase in
overhead charges billed to non-operating partners of $484,000 as a result of
increased activity on the Utah properties during 1996 due to the significant
number of wells drilled in the second half of 1996. This decline was partially
offset by an increase in engineering and administrative staff as a result of the
increased development activity.
Other Income (Expenses)
Interest income (expense), net, improved by $256,000 as compared to 1995
to $40,000 of income in 1996 primarily as a result of a reduction in average
outstanding debt and an increase in interest capitalized of $44,000 on the
Company's Utah properties development project.
Gain on sale of assets was $1,384,000 in 1996 as compared to a loss of
$138,000 in 1995. The gain in 1996 is primarily due to a gain of $1,314,000
recognized on the sale of the 50% interest in the Utah properties in June 1996.
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.
17
<PAGE>
The following table sets forth costs incurred by the Company in its
exploration, development and acquisition activities during the periods
indicated.
Year Ended December 31,
1997 1996 1995
------------ ------------ ------------
Acquisition costs:
Unproved properties... $ 1,721,636 $ 490,487 $ 8,206
Proved properties..... 147,387 -- 4,718,201
Development costs............ 10,003,468 6,983,715 3,448,972
Exploration costs............ -- -- 316,089
Improved recovery costs...... 895,317 327,027 154,023
------------ ------------ ------------
Total........................ $ 12,767,808 $ 7,801,229 $ 8,645,491
============ ============ ============
During 1998, the Company plans to focus its efforts on the continued
development of its improved recovery projects in the Uinta Basin in Utah and its
coal-bed methane project in the Raton Basin in Colorado.
The Company plans to drill up to 65 gross (38.5 net) wells in the Uinta
Basin during 1998 at a projected cost of up to $15 million. In addition, the
Company plans to drill up to 20 pilot wells in the Raton Basin at an estimated
cost of up to $5.5 million during the same time period. Finally, the Company
plans to drill with an industry partner at least three gross (1.5 net) wells in
Victoria and DeWitt Counties in South Texas.
Cash Flow and Working Capital
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, $10,000,000 of its revolving line of credit
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 are expected to be utilized to develop production and reserves in the
Company's core Uinta Basin and Raton Basin development properties and for other
working capital needs.
During 1996, the Company generated cash flow from operating activities of
$4,129,000 and received proceeds from sales of oil and natural gas properties of
$8,968,000. During the same period, the Company incurred $8,665,000 in capital
expenditures and repaid $5,909,000 of outstanding debt.
The Company believes that cash flow from operations, availability under
the Credit Agreement and the remaining proceeds from the Offering will be
adequate to support its budgeted working capital and capital expenditure
requirements for at least the next 12 months. The Company believes that after
1998 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 properties in accordance with its planned schedule.
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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 includes a $20.0 million combination credit
facility with a two-year revolving credit facility with an original borrowing
base of $7.5 million to be redetermined semi-annually ("Tranche A"), which
expires on September 15, 1999, at which time all balances outstanding under
Tranche A will convert to a term loan expiring on September 15, 2002.
Additionally, the Credit Agreement contains a separate revolving facility of
$2.5 million ("Tranche B"), which expires on March 15, 1999, at which time all
balances outstanding become immediately payable. Prior to the completion of the
Offering, the Company had total outstanding obligations under the Credit
Agreement of $10.0 million. The Company utilized a portion of the proceeds from
the Offering to eliminate all outstanding amounts under the Credit Agreement on
October 24, 1997. With the repayment of the Tranche B indebtedness, the $2.5
million under that portion of the Credit Agreement is not longer available to
the Company. Interest on borrowings outstanding under Tranche A 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 tranche.
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
In the past, the Company has 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 historically 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 which have been historically used by the Company
have not had a contractual obligation which requires or allows the future
physical delivery of the hedged products.
The Company had one open hedging contract at December 31, 1997, which is
a crude oil collar on 309,000 Bbls of oil with a floor price of $17.00 per Bbl
and a ceiling price of $20.75 per Bbl indexed to the NYMEX light crude future
settlement price. See Note 7 to the Notes to Combined Financial Statements. This
contract covers 309,000 Bbls of oil over the next two years as follows:
Year Bbls
---- -------
1998.......................... 150,000
1999 ......................... 159,000
Total ...................... 309,000
=======
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Information System Issues
During 1997, the Company implemented a new accounting and operations
system and simultaneously resolved any "Year 2000" issues. All associated costs
of the system implementation are included in the Company's combined balance
sheet as of December 31, 1997. Future costs associated with the continued
implementation are projected by the Company's management to be immaterial.
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 Prospectus 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.
20
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Estimates of oil and natural gas reserves, by necessity, are projections
based on engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. In particular, given the early stage of the
Company's development programs, the ultimate effect of such programs is
difficult to ascertain. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
improved recovery techniques such as the enhanced oil recovery techniques
utilized by the Company, the assumed effects of regulations by governmental and
tribal agencies and assumptions concerning future oil and natural gas prices,
future operating costs, severance and excise taxes, development costs and
workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net cash flows expected therefrom may vary
substantially. Any significant variance in the assumptions could materially
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. In addition, the Company's expansion
has placed significant demands on its administrative, operational and financial
resources and the Company is in the process of implementing a new accounting
system. Any future growth of the Company's oil and natural gas reserves,
production and operations would place significant further demands on the
Company's financial, operational and administrative resources.
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 $25,000 in 1997. 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. During
1997, the Company incurred an operating loss and a net loss of approximately
$25,000 and $2.4 million, respectively. The Company's net loss for the year
ended December 31, 1997 was due to a one-time $2.5 million non-cash provision
for 1997 income taxes resulting from the Company's conversion from a partnership
to a corporation. Although the Company expects its results of operations to
improve as it completes additional Uinta Basin wells and develops its Raton
Basin acreage, there is no assurance that the Company will achieve, or be able
to sustain, profitability.
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Early Stages of Development Activities. The Company's development plan
includes (i) the drilling of development and exploratory wells in the Uinta
Basin, together with injection wells that are intended to repressurize producing
reservoirs in the Lower Green River formation, (ii) subject to the evaluation of
the results of a pilot program, the drilling of exploratory 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, 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.
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 85% of the Company's 1997 capital expenditures of approximately
$16.3 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. In addition, recent
heavy drilling activity by a number of operators in the Uinta Basin may increase
the cost to acquire additional acreage in this area, reduce or limit the
availability of drilling and service rigs, equipment and supplies, or reduce
demand for the Company's production, any of which would impact the Company more
adversely than if the Company were more geographically diversified.
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 scheduled maintenance at one of the Salt
Lake City refineries, the increase in supply of Uinta Basin "black wax"
production resulting from the recent drilling activity or the reaction to the
potential 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.
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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. 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.
Dependence on Third Party Expertise. Based on its limited operating
experience in the Raton Basin, the Company intends to engage independent
contractors in connection with its coalbed methane natural gas development
activities. There can be no assurance that such technological expertise will be
available to the Company on commercially reasonable terms or at all.
Water Disposal. The Company believes that the water produced 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.
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Substantial Capital Requirements. The Company's current 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 anticipates
that the net proceeds from the Offering in October 1997, together with cash flow
from operations and availability under the Credit Agreement, will be sufficient
to meet its estimated capital expenditure requirements for 1998. The Company
believes that 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 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 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
other pollutants into the air, soil or water may give rise to significant
liabilities on the part of the Company to the government and third parties and
may require the Company to incur substantial costs of remediation. Moreover, the
Company has agreed to indemnify sellers of properties purchased by the Company
against certain liabilities for environmental claims associated with such
properties. No assurance can be given that existing environmental laws or
regulations, as currently interpreted or reinterpreted in the future, or future
laws or regulations will not materially adversely affect the Company's results
of operations and financial condition or that material indemnity claims will not
arise against the Company with respect to properties acquired by the Company.
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Reserve Replacement Risk. The Company's future success depends upon its
ability to find, develop or acquire additional oil and natural gas reserves that
are economically recoverable. The proved reserves of the Company will generally
decline as reserves are depleted, except to the extent that the Company conducts
successful exploration or development activities, enhanced oil recovery
activities or acquires properties containing proved reserves. Approximately 49%
of the Company's total proved reserves at December 31, 1997 were undeveloped. In
order to increase reserves and production, the Company must continue its
development and exploitation drilling programs or undertake other replacement
activities. The Company's current development plan includes increasing its
reserve base through continued drilling, development and exploitation of its
existing properties. There can be no assurance, however, that the Company's
planned development and exploitation projects will result in significant
additional reserves or that the Company will have continuing success drilling
productive wells at anticipated finding and development costs.
In addition to the development of its existing proved reserves, the
Company expects that its inventory of unproved drilling locations will be the
primary source of new reserves, production and cash flow over the next few
years. The Company's properties in the Uinta Basin constitute the majority of
the Company's existing inventory. Approximately 69% of the Company's fiscal year
1998 capital expenditure budget is expected to be associated with drilling and
acreage acquisition activity in the Uinta Basin. 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 Operating Officer, and a limited number of other senior
management and technical personnel. Loss of the services of Mr. Murdock, Mr.
Christensen, Mr. Smith 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 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Combined Financial Statements required by this item are
included on the pages immediately following the Index to Combined Financial
Statements appearing on page F-1.
25
<PAGE>
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 "1998
Proxy Statement") for its annual meeting of stockholders to be held on May 27,
1998. The 1998 Proxy Statement will be filed with the Securities and Exchange
Commission (the "Commission") not later than 120 days subsequent to December 31,
1997.
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 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTION
The information required by this item is incorporated herein by reference
to the 1998 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1997.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-K
(a) 1. Combined Financial Statements:
See Index to Combined Financial Statements on page F-1.
2. Financial Statement Schedules:
See Index to Combined Financial Statements on page F-1.
3. Exhibits: The following documents are filed as exhibits to this
report:
26
<PAGE>
Exhibit
Number Description of Document
- -------- ------------------------
2 Exchange Agreement (filed as Exhibit 2 to the Company's Registration
Statement on Form S-1, Registration No. 333-34241, and incorporated herein
by reference).
3.1 Certificate of Incorporation (filed as Exhibit 3.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241,
and incorporated herein by reference).
3.2 Bylaws (filed as Exhibit 3.2 to the Company's Registration Statement on
Form S-1, Registration No.333-34241, and incorporated herein by reference)
4 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
Registrant 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 Registrant 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).
10.8 Asset Purchase and Sale Agreement, dated as of June 1, 1996, by and
between Petroglyph Gas Partners, L.P., and CoEnergy Enhanced Production,
Inc. (filed as Exhibit 10.10 to the Company's Registration Statement on
Form S-1, Registration No. 333-34241, and incorporated herein by
reference).
10.9 Assignment of mining lease dated June 26, 1996 by Petroglyph Gas Partners,
L.P. to CoEnergy Enhanced Production, Inc. (filed as Exhibit 10.11 to
the Company's Registration Statement on Form S-1, Registration No.
333-34241, and incorporated herein by reference).
10.10 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).
27
<PAGE>
10.11 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).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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).
10.17 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).
10.18 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).
10.19 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).
10.20 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).
21 Subsidiaries of the Registrant (filed as Exhibit 21 to the Company's
Registration Statement on Form S-1, Registration No. 333-34241, and
incorporated herein by reference).
23.2 Consent of Arthur Andersen LLP, independent public accounts
27 Financial Data Schedule.
(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.
28
<PAGE>
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 of 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.
29
<PAGE>
Mcf. One thousand cubic feet of natural gas.
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.
30
<PAGE>
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 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.
31
<PAGE>
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
32
<PAGE>
INDEX TO FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF PETROGLYPH ENERGY, INC.
PAGE
Report of Independent Public Accountants.....................................F-2
Combined Balance Sheets as of December 31, 1997 and 1996.....................F-3
Combined Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995........................................F-4
Combined Statements of Change in Stockholders' Equity for the Years Ended
December 31, 1997, 1996 and 1995........................................F-5
Combined Statements of Cash Flows for the Years Ended December 31, 1997,
1996 and 1995...........................................................F-6
Notes to Combined Financial Statements.......................................F-7
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Petroglyph Energy, Inc.:
We have audited the accompanying combined balance sheets of Petroglyph Energy,
Inc. (a Delaware corporation) and subsidiary as of December 31, 1997 and 1996,
and the related combined statements of operations, changes in stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1997. 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 combined financial position of Petroglyph Energy,
Inc. and subsidiary as of December 31, 1997 and 1996 and the results of its
operations and cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Dallas, Texas,
February 27, 1998
F-2
<PAGE>
<TABLE>
PETROGLYPH ENERGY, INC.
COMBINED BALANCE SHEETS
December 31,
------------------------------
1997 1996
------------- ------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents................... $ 16,678,655 $ 1,577,632
Accounts receivable:
Oil and natural gas sales............... 665,214 1,178,287
Joint interest billing.................. 463,400 152,118
Other................................... 144,684 85,037
------------- ------------
1,273,298 1,415,442
Inventory................................... 1,376,737 1,064,802
Prepaid expenses............................ 246,193 125,045
------------- ------------
Total Current Assets........... 19,574,883 4,182,921
------------- ------------
Property and equipment, successful
efforts method at cost:
Proved properties........................... 23,317,886 13,266,674
Unproved properties......................... 2,957,707 1,269,873
Pipelines, gas gathering and other.......... 6,901,300 3,429,985
------------- ------------
33,176,893 17,966,532
Less--Accumulated depreciation, depletion,
and amortization....................... (6,607,487) (5,083,655)
------------ ------------
Property and equipment, net............. 26,569,406 12,882,877
------------- ------------
Note receivable from directors................... 246,500 246,500
Other assets, net................................ 323,189 157,809
------------- ------------
Total Assets................... $ 46,713,978 $17,470,107
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade................................... $ 3,608,144 $ 3,768,143
Oil and natural gas sales............... 735,343 657,287
Deferred revenue........................ -- 45,860
Current portion of long-term debt....... 36,598 24,697
Accrued taxes payable................... 172,411 157,667
Other................................... 149,771 70,019
------------ -------------
Total Current Liabilities...... 4,702,267 4,723,673
------------ -------------
Long term debt .................................. -- 51,800
------------ -------------
Deferred tax liability........................... 2,514,154 --
------------ -------------
Stockholders' Equity:
Partners' Capital........................... $ -- $ 12,694,634
Common Stock, par value $.01 per share;
25,000,000 shares authorized
5,458,333 shares issued and outstanding 54,583 --
Paid-in capital............................. 43,659,457 --
Retained earnings (deficit)................. (4,216,483) --
------------- -------------
Total Stockholders' Equity..... 39,497,557 12,694,634
------------ -------------
Total Liabilities and Stockholders' Equity....... $ 46,713,978 $ 17,470,107
============ =============
The accompanying notes are an integral part of these financial statements.
</TABLE>
F-3
<PAGE>
<TABLE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF OPERATIONS
Year Ended December 31,
-----------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Operating Revenues:
Oil sales........................ $ 3,734,856 $ 4,458,769 $ 3,216,901
Natural gas sales................ 1,070,195 998,920 1,015,863
Other............................ 60,847 -- 36,050
------------ ------------ ------------
Total operating revenues... 4,865,898 5,457,689 4,268,814
------------ ------------ ------------
Operating Expenses:
Lease operating.................. 1,559,885 2,368,973 2,260,303
Production taxes................. 178,822 248,848 187,563
Exploration costs................ -- 68,818 375,649
Depreciation, depletion,
and amortization............... 1,852,296 2,805,693 2,302,515
Impairments...................... -- -- 109,209
General and administrative....... 1,299,851 902,409 1,063,708
------------ ------------ ------------
Total operating expenses... 4,890,854 6,394,741 6,298,947
------------ ------------ ------------
Operating Loss........................ (24,956) (937,052) (2,030,133)
Other Income (Expenses):
Interest income (expense), net... 114,036 40,580 (215,669)
Gain (loss) on sales of
property and equipment, net.... 12,440 1,383,766 (138,614)
------------ ------------ ------------
Net income (loss) before income taxes. 101,520 487,294 (2,384,416)
------------ ------------ ------------
Income Tax Expense (Benefit):
Current.......................... (463,238) -- --
Deferred......................... 2,977,392 -- --
Pro forma........................ -- 190,044 --
------------ ------------ ------------
Total Income Tax Expense .. 2,514,154 190,044 --
------------ ------------ ------------
Net Income (Loss)..................... $(2,412,634) $ 297,250 $(2,384,416)
============ ============ ============
Earnings(Loss) per Common Share,
Basic and Diluted................ $ (.73) $ .11 $ (.84)
============ ============ ============
Weighted Average Common Shares
Outstanding (Note 4)
Actual........................... 3,326,826 -- --
Pro forma........................ -- 2,833,333 2,833,333
============ ============ ============
The accompanying notes are an integral part of these
financial statements.
</TABLE>
F-4
<PAGE>
<TABLE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, 1995
Retained
Common Partners' Paid In Earnings Total
Stock Capital Capital (Deficit) Equity
-------- ------------ ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1994......... $ -- $ 8,973,044 $ -- $(2,381,288) $ 6,591,756
Contributions...................... -- 8,000,000 -- -- 8,000,000
Net loss before income taxes....... -- -- -- (2,384,416) (2,384,416)
-------- ------------ ------------ ------------ -------------
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 26,250 -- 29,189,307 -- 29,215,557
stock, net of offering costs....
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 $ 43,659,457 $(4,216,483) $ 39,497,557
======== ============ ============ ============ =============
The accompanying notes are an integral part of these financial statements.
</TABLE>
F-5
<PAGE>
<TABLE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF CASH FLOWS
Year Ended December 31,
------------------------------------------------
1997 1996 1995
-------------- -------------- --------------
<S> <C> <C> <C>
Operating Activities:
Net income (loss)........................................... $ (2,412,634) $ 487,294 $ (2,384,416)
Adjustments to reconcile net income (loss) to net cash
used in operating activities:
Depreciation, depletion, and amortization........... 1,852,296 2,805,693 2,302,515
(Gain) loss on sales of property and equipment, net. (12,440) (1,383,766) 138,614
Amortization of deferred revenue.................... (45,860) (524,140) --
Impairments......................................... -- -- 109,209
Exploration costs................................... -- -- 316,089
Property abandonments............................... -- 68,818 59,560
Amortization of financing costs..................... -- -- 66,255
Deferred Taxes...................................... 2,514,154 -- --
Proceeds from deferred revenue...................... -- 570,000 --
Changes in assets and liabilities--
(Increase) decrease in accounts receivable............. 142,144 (481,169) (100,937)
Increase in inventory.................................. (311,935) (579,257) (275,151)
(Increase) decrease in prepaid expenses................ (113,945) 3,561 (82,715)
Increase in accounts payable and accrued liabilities... 20,819 3,162,406 197,759
-------------- -------------- -------------
Net cash provided by operating activities........... 1,632,599 4,129,440 346,782
Investing Activities:
Proceeds from sales of property and equipment............... 745,712 8,968,274 805,869
Additions to oil and natural gas properties, including
exploration costs...................................... (12,767,808) (7,801,229) (8,645,491)
Additions to pipelines, gas gathering and other............. (3,491,853) (863,911) (1,797,955)
Maturity of certificates of deposit......................... -- -- 57,925
-------------- -------------- -------------
Net cash provided by (used in) investing activities.... (15,513,949) 303,134 (9,579,652)
Financing Activities:
Proceeds from issuance of equity securities................. 30,515,625 -- --
Contributions by partners................................... -- -- 8,000,000
Proceeds from issuance of, and draws on, notes payable...... 10,085,381 2,085,024 7,400,000
Payments on note payable.................................... (10,133,545) (5,908,527) (5,300,000)
Payments for organization and financing costs............... (1,485,088) (106,375) (50,620)
-------------- -------------- -------------
Net cash provided by (used in) financing activities.... 28,982,373 (3,929,878) 10,049,380
-------------- -------------- -------------
Net increase in cash and cash equivalents...................... 15,101,023 502,696 816,510
Cash and cash equivalents, beginning of period................. 1,577,632 1,074,936 258,426
-------------- -------------- -------------
Cash and cash equivalents, end of period...................... $ 16,678,655 $ 1,577,632 $ 1,074,936
============== ============== =============
The accompanying notes are an integral part of these financial statements.
</TABLE>
F-6
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996, AND 1995
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 is a Delaware limited partnership, which was
organized on April 15, 1993 to acquire, explore for, produce and sell oil,
natural gas, and related hydrocarbons. The general partner is Petroglyph Energy,
Inc., a Kansas corporation ("PEI"). Petroglyph Gas Partners II, L.P. ("PGP II")
is a Delaware limited partnership, which was organized on April 15, 1995 to
acquire, explore for, produce and sell oil, natural gas and related
hydrocarbons. The general partner of PGP II is PEI (1% interest) and the limited
partner is 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 will result in no change in carrying values of these assets
and liabilities.
The accompanying combined 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. PGP owned a
99% interest in PGP II as of December 31, 1997, 1996 and 1995. POCI is a
subchapter C corporation. POCI is the designated operator of all wells for which
PGP 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 combined 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 1997, 1996 and 1995 totaled $325,000,
$250,000, and $266,000, respectively. The Company did not make any cash payments
for income taxes during 1997, 1996 or 1995 based on its partnership structure in
effect during those periods.
F-7
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
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, 1997 and 1996.
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 $109,209 in 1995. 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 a field water
distribution system and a natural gas gathering system located in the Uinta
Basin, field building and land, office equipment, furniture and fixtures and
automobiles. The gathering system and the field water distribution system are
amortized on a unit-of-production basis
F-8
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:--(CONTINUED)
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.
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
$61,895, $49,459 and $28,012 at December 31, 1997, 1996 and 1995, respectively.
Amortization of $12,436, $21,447, and $14,610 is included in depreciation,
depletion and amortization expense in the accompanying combined statements of
operations for the years ended December 31, 1997, 1996 and 1995, 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 $66,255 are included in interest expense
in the accompanying statements of operations for the year ended December 31,
1995.
INTEREST INCOME (EXPENSE)
For the years ended December 31, 1997 and 1996, interest income is
presented net of interest expense of $198,519 and $106,715, respectively. For
the year ended December 31, 1995, interest expense is presented net of interest
income of $33,311.
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 $127,000, $195,000 and $114,000 for
the years ended December 31, 1997, 1996 and 1995, respectively.
REVENUE RECOGNITION AND NATURAL GAS BALANCING
The Company utilizes the entitlements method of accounting for
recording revenues 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, 1997 and 1996.
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
F-9
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:--(CONTINUED)
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 combined statements of operations and in Note 6, reflects the
income tax expense (benefit), net income (loss) and net income (loss) per common
share as if all 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, 1997
and December 31, 1996, there is no impact from adoption of APB No. 25 or 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 February 1994, the Company purchased a 50% working interest in the
existing Antelope Creek and Duchesne fields in the Uinta Basin for $4.5 million.
In September 1995, the Company acquired for total consideration of $5.6 million
the remaining 50% interest of its joint venture partners, Inland Resources, in
the Utah properties. The consideration consisted of $3.1 million in cash plus
assumption of Inland's outstanding debt of $2.5 million, which was specifically
collateralized by Inland's investment in the Utah properties. The assumption of
outstanding debt is not reflected on the accompanying statement of cash flows as
it is a noncash transaction.
These acquisitions were accounted for using the purchase method of accounting.
F-10
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
3. ACQUISITIONS AND DISPOSITIONS:--(CONTINUED)
Effective September 1, 1994, the Company acquired Southwest Oil and
Land's interest in the Victoria properties in Victoria and DeWitt counties
located in Texas for approximately $1.6 million.
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 have
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 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.
The following unaudited Pro Forma Condensed Combined Statements of
Operations for the years ended December 31, 1996 and 1995 give effect to the
Antelope Creek disposition as if the sale had been consummated at January 1,
1996 and 1995. A pro forma combined balance sheet at December 31, 1996 is not
necessary as the historical combined balance sheet at December 31, 1996 includes
the effect of the disposition. The unaudited pro forma data is presented for
illustrative purposes only and is not necessarily indicative of the operating
results that would have occurred had the transaction been consummated at the
dates indicated, nor are they necessarily indicative of future operating
results.
F-11
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
3. ACQUISITIONS AND DISPOSITIONS:--(CONTINUED)
Pro Forma Condensed Combined Statements of Operations
(unaudited)
<TABLE>
Year Ended December 31,
-----------------------------
1996 1995
-------------- -------------
<S> <C> <C>
Oil and natural gas revenues $ 4,400,689 $ 3,678,764
Other revenues -- 36,050
-------------- -------------
Total Revenues 4,400,689 3,714,814
Lease operating expenses 1,953,973 2,085,303
Production taxes 204,848 143,563
Exploration costs 68,818 335,649
Depreciation, depletion, and amortization 2,358,693 1,920,515
Impairments -- 109,209
General and administrative expenses 902,409 1,063,708
-------------- -------------
Total Expenses 5,488,741 5,657,947
Interest income (expense), net 147,580 (147,669)
Gain (loss) on sale of assets 69,766 (138,614)
-------------- -------------
Net loss $ (870,706) $ (2,229,416)
============== =============
</TABLE>
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 9,000 net mineral acres were
acquired by December 31, 1997 from various parties for a total of 63,000 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 is obligated to pay an
additional $35,000 by July 1999. Additionally, the Company assumed an obligation
for delinquent property taxes of approximately $135,000, which were paid in
November of 1997.
4. 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, with the balance of
the proceeds expected to be 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.
F-12
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
4. EQUITY--(CONTINUED)
EARNINGS PER SHARE INFORMATION
Effective December 31, 1997, the Company adopted the provisions of
Statement of Financial Accounting Standards ("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 years ended
December 31, 1996 and 1995 are presented as if the Conversion had occurred,
resulting in common stock outstanding as of the beginning of each of the two
respective years. The computation of basic and diluted EPS were identical for
the years ended December 31, 1997, 1996 and 1995 due to the following reasons:
Options to purchase 337,000 shares of common stock at $12.50 per share
were outstanding since November 1, 1997, but were not included in the
computation of diluted EPS because the options' exercise price was
greater than the average market price of the common shares. The
options, which expire on November 1, 2007, were still outstanding at
December 31, 1997.
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,
1997. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1997.
As the Company completed the Offering in 1997, there were no equity
securities, nor any potentially dilutive equity securities outstanding
at either December 31, 1996 or 1995.
5. TRANSACTIONS WITH AFFILIATES:
The Company had notes receivable from certain executive officers
aggregating $246,500 at December 31, 1997, 1996 and 1995. These notes bear
interest at a rate of 9% and have no set maturity date.
The Company leases its office building from an affiliate. Rentals paid
to the affiliate for such leases during 1997, 1996 and 1995 totaled $34,800,
$34,800 and $39,200, respectively. These rentals are included in general and
administrative expense in the accompanying financial statements.
In August 1997, the Company and NGP entered into a financial advisory
services agreement whereby NGP has agreed to provide financial advisory services
to the Company for a quarterly fee of $13,750. In addition, NGP will be
reimbursed for its out of pocket expenses incurred in performing such services.
The agreement is for a one year term and can be terminated by NGP at the end of
any fiscal quarter. Under the agreement, NGP will assist the Company in managing
its public and private financing activities, its public financial reporting
obligations, its budgeting and planning processes, and its investor relations
program, as well as provide ongoing strategic advice. NGP will not receive any
other transaction-related compensation for its advisory assistance. Advisory
fees paid to NGP during 1997 totaled $10,163.
For the years ended December 31, 1997 and 1996, the Company paid legal
fees of $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.
F-13
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
6. LONG-TERM DEBT:
The Company negotiated a $10,000,000 loan facility with Texas Commerce
Bank National Association ("TCB") of Dallas, Texas, as agent for a group of
financial institutions, in May 1995. The loan facility is collateralized by the
Company's oil and natural gas properties located in Utah and contains certain
financial covenants with which the Company was in compliance at December 31,
1997 and 1996. The loan facility is a combination credit facility with a
revolving credit agreement, which expired on May 25, 1997, at which time all
balances outstanding under the revolving credit agreement were to convert to a
term loan, expiring on October 1, 1999. The revolving loan facility was
redetermined at $7.5 million on July 2, 1997. This effectively allowed the
Company to continue to borrow on the facility in place until September 15, 1997,
when the Company amended the Original Agreement and entered into the Amended and
Restated Loan Agreement with The Chase Manhattan Bank ("Chase") (as amended, the
"Credit Agreement"). As part of the Credit Agreement, the agent was changed from
TCB to Chase; however, the group of lenders remains unchanged. The Credit
Agreement includes a $20.0 million combination credit facility with a two-year
revolving credit facility with an original borrowing base of $7.5 million to be
redetermined semi-annually ("Tranche A"), which expires on September 15, 1999,
at which time all balances outstanding under Tranche A will convert to a term
loan expiring on September 15, 2002. Additionally, the Credit Agreement contains
a separate revolving facility of $2.5 million ("Tranche B"), which was to expire
on March 15, 1999, at which time all balances outstanding would have become
immediately payable. The Company had an outstanding obligation under the Credit
Agreement of $10.0 million at October 24, 1997. The Company utilized a portion
of the net proceeds from the Offering to eliminate all outstanding amounts under
the Credit Agreement on October 24, 1997. With the repayment of the Trance B
indebtedness, the $2.5 million under that portion of the Credit Agreement is no
longer available to the Company. Interest on borrowings outstanding under
Tranche A 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 tranche. There are no outstanding amounts under the Credit
Agreement at December 31, 1997.
In July 1996, the Company used proceeds received from the sale of oil
and gas properties to pay in full the outstanding balance of $5.9 million on the
revolver. The revolver was still open at December 31, 1996, although there is no
outstanding balance due as of that date. The availability to the Company under
this revolver at December 31, 1996 was $7.5 million. The Company pays a
commitment fee of three-eighths of 1% on the unused portion of the available
borrowings under the Revolver. There were no outstanding amounts under this line
of credit at December 31, 1996.
In September 1996, the Company entered into a term loan with a local
lender covering four vehicles. The principal balance was $85,000 and bore
interest at an annual rate of 7.5%. The loan was to mature on September 16, 1999
and was secured by the four vehicles. At December 31, 1996, the outstanding
balance was $76,497, $51,800 of which is presented as long-term debt in the
accompanying Combined Statement of Assets, Liabilities and Owners' Equity. The
loan was paid in full in December 1997.
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 and
1995 combined 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.
F-14
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
7. INCOME TAXES:--(CONTINUED)
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the periods shown below:
Year Ended December 31,
-----------------------------------------------
1997 1996 1995
--------------- --------------- ------------
(pro forma) (pro froma)
Income tax expense (benefit)
at the federal
statutory rate of 35%.... $ 35,532 $ 170,552 $ (834,546)
State income tax expense
(benefit)................ 4,061 19,492 (95,377)
Deferred tax liabilities
recorded upon the
Offering................. 2,474,561 -- --
Net operating loss
utilized by partners..... -- -- 929,923
------------ ----------- ------------
$ 2,514,154 $ 190,044 $ --
=========== =========== ============
Components of income tax expense (benefit) are as follows:
Year Ended December 31,
-----------------------------------------------
1997 1996 1995
--------------- ---------------- ------------
(proforma) (pro forma)
Current................. $ (463,238) $ (222,169) --
Deferred................ 2,977,392 412,213 --
--------------- ---------------- ------------
Total.... $ 2,514,154 $ 190,044 --
=============== ================ ============
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, 1997 and 1996, are summarized below:
December 31,
------------------------------
1997 1996
-------------- --------------
(pro forma)
Deferred Tax Assets:
Net operating loss carryforwards............ $ 496,232 --
-------------- --------------
Total Deferred Tax Assets................ 496,232 --
-------------- --------------
Deferred Tax Liabilities:
Inventory and other......................... (32,994) (53,820)
Property and equipment...................... (2,977,392) (1,267,728)
-------------- ---------------
Total Deferred Tax Liabilities........... (3,010,386) (1,321,548)
-------------- --------------
Total Net Deferred Tax Liability......... $ (2,514,154) $ (1,321,548)
============== ===============
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.
F-15
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
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 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. Losses incurred during
1995 were not significant.
In August 1994, the Company entered into a financial swap arrangement
covering the sale of 549,000 barrels of oil production from January 1996 to
December 1999, at a floor price of $17.00 per Bbl and a ceiling price of $20.75
per Bbl. This agreement was terminated in October of 1995, for which the Company
received a premium of $170,000. This premium is included in oil revenue for the
year ended December 31, 1995 in the accompanying combined statement of
operations.
In January 1995, the Company entered into an additional swap
arrangement covering the sale of 4,000 Bbls per month from February 1995 to
January 1996, at a floor price of $17.00 per Bbl and a ceiling price of $19.00
per Bbl. This agreement was terminated in October 1995. 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 floor price of $17.00 per Bbl and a ceiling
price of $20.75 per Bbl. At December 31, 1997, this contract was outstanding and
calls for the remaining sale of 309,000 barrels of oil over the next two years
as follows:
YEAR BBLS
---- ----
1998.................................... 150,000
1999.................................... 159,000
--------
Total............................... 309,000
========
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 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, 1997, 1996
and 1995 the volumes sold under this contract totaled 74,499, 60,633, and
101,115 Bbls, respectively, at an average sales price per Bbl for each year of
$14.80, $19.33, and $17.09.
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 59,048 Bbls 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 $2.00 per Bbl 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
F-16
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
8. DERIVATIVES, SALES CONTRACTS, AND SIGNIFICANT CUSTOMERS:--(CONTINUED)
proper notice. For the year ended December 31, 1997, the Company sold 70,204
Bbls under this contract at an average price of $16.58 per Bbl.
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 is effective until May 31, 1998 and calls 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. This contract replaces a contract the
Company had with Purchaser "D" for the month of April 1997. Volumes sold under
this contract totaled 73 MBbls at an average price of $14.50 for the year ended
December 31, 1997.
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 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. Oil sales to
one purchaser in 1995 were approximately 43% of total 1995 oil and natural gas
revenues.
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, 1997 and 1996. 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, 1997 or 1996. The
fair value of the Company's outstanding oil price swap arrangement, described in
the preceding note, has an estimated fair value of $182,000 and $170,000 at
December 31, 1997 and 1996, respectively. These estimates are based on quoted
market values.
F-17
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
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. An aggregate of 375,000 shares of Common Stock have been authorized and
reserved for issuance pursuant to the 1997 Incentive Plan. As of December 31,
1997, options have been granted to the participants under the 1997 Incentive
Plan to purchase a total of 337,000 shares of Common Stock to participants at an
exercise price per share equal to $12.50 per share. One-third of these options
will vest each year commencing on November 1, 1998. No options had been
exercised as of December 31, 1997.
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, 1997.
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 1997, as if stock-based compensation had been
recorded at the estimated fair value of stock awards at the grant date, as
prescribed by SFAS 123, Accounting for Stock-Based Compensation (Note 2):
Year Ended
December 31, 1997
-----------------
Loss available to common stock
As reported $(2,412,634)
Pro forma $(2,492,007)
Loss per common share
As reported, basic and diluted $ (.73)
Pro forma, basic and diluted $ (.75)
There is no impact of adoption of APB No. 25 or SFAS No. 123 for the years
ended December 31, 1996 or 1995, as no stock options, warrants or grants had
been issued at such dates.
F-18
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
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, 1997, total
minimum future lease payments for all non-cancelable lease agreements is
$39,261.
Amounts incurred by the Company under operating leases (including
renewable monthly leases) were $53,383, $41,548, and $50,543, in 1997, 1996 and
1995, respectively.
LITIGATION
The Company and its subsidiary are involved in certain litigation and
certain 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
In December 1996, the Company entered into an agreement with an
industry partner whereby the industry partner would pay for the costs of a 3-D
seismic survey on the Company's leasehold interests in the Helen Gohlke field,
located in Victoria and DeWitt Counties of South Texas. In exchange for such
costs, the industry partner has the right to earn a 50% interest in the
leasehold rights of the Company in the Helen Gohlke field. The industry partner
is required to pay 50% of the costs to drill and complete any wells in the area
covered by the seismic survey, and, in exchange, will earn a 50% interest in the
well and in certain acreage surrounding the well. The amount of such surrounding
acreage in which the industry partner will earn an interest is to be determined
based upon the depth of the well drilled.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to environmental
protection, including the generation, storage, handling, emission,
transportation and discharge of materials into the environment, and relating to
safety and health. The recent trend in environmental legislation and regulating
generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction of drilling commences and for certain other
activities; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness and other protected areas; and impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various of the Company's operations are subject to
revocation, modification and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations, and
violations are subject to fines or injunction, or both. In the opinion of
management, the Company is in substantial compliance with current applicable
environmental laws and regulations, and the Company has no material commitments
for capital expenditures to comply with existing environmental requirements.
Nevertheless, changes in existing environmental laws and regulations or in
interpretations thereof could have a significant impact on the Company, as well
as the oil and natural gas industry in general.
F-19
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING ACTIVITIES:
COSTS INCURRED RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
Year Ended December 31,
--------------------------------------------------
1997 1996 1995
--------------- --------------- ---------------
Acquisition
Unproved Properties. $ 1,721,636 $ 490,487 $ 8,206
Proved Properties... 147,387 -- 4,718,201
Development.............. 10,003,468 6,983,715 3,448,972
Exploration.............. -- -- 316,089
Improved recovery costs.. 895,317 327,027 154,023
--------------- --------------- ---------------
Total............... $ 12,767,808 $ 7,801,229 $ 8,645,491
=============== =============== ===============
PROVED RESERVES
Independent petroleum engineers have estimated the Company's proved oil
and natural gas reserves as of December 31, 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 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.
F-20
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS
PRODUCING ACTIVITIES:--(CONTINUED)
<TABLE>
Oil Natural Gas
(Bbls) (Mcf)
-------------- ---------------
<S> <C> <C>
Proved Reserves (Unaudited):
December 31, 1994................................ 1,204,969 7,307,359
Revisions............................... (295,013) (698,765)
Extensions, additions and discoveries... 291,097 181,797
Production.............................. (182,704) (659,202)
Purchases of reserves................... 628,789 694,187
Sales in place.......................... (86,046) (166,216)
-------------- ---------------
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
=============== ===============
Proved Developed Reserves:
December 31,1994................................. 1,204,969 7,307,359
=============== ===============
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
=============== ===============
</TABLE>
F-21
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1997, 1996, AND 1995
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING
ACTIVITIES:--(CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves (Unaudited)
<TABLE>
December 31,
------------------------------------------------
1997 1996 1995
-------------- -------------- ----------------
<S> <C> <C> <C>
Future cash inflows...... $ 169,302,079 $ 184,248,490 $ 40,419,081
Future costs:
Production...... (50,913,842) (43,993,010) (17,987,575)
Development..... (19,151,264) (16,455,901) --
-------------- -------------- -------------
Future net cash flows
before income tax... 99,236,973 123,799,579 22,431,506
Future income tax........ (22,247,206) (32,657,687) (3,032,875)
-------------- -------------- ---------------
Future net cash flows.... 76,989,767 91,141,892 19,398,631
10% annual discount...... (42,836,688) (43,117,804) (6,027,926)
-------------- -------------- ---------------
Standardized Measure..... $ 34,153,079 $ 48,024,088 $ 13,370,705
============== ============== ===============
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
<TABLE>
December 31,
------------------------------------------------------
1997 1996 1995
-------------- -------------- --------------
<S> <C> <C> <C>
Standardized Measure,
Beginning of Period..... $ 48,024,088 $ 13,370,705 $ 10,360,642
Revisions:
Prices and costs........ (26,476,631) 4,839,954 (525,763)
Quantity estimates...... 380,840 6,000,942 (989,701)
Accretion of discount... 6,484,830 1,484,547 1,169,449
Future development cost. (1,869,101) (15,068,164) --
Income tax.............. (7,508,139) (14,604,066) (269,251)
Production rates
and other............. (8,545,510) 1,901,254 (1,227,766)
-------------- -------------- --------------
Net revisions... (22,517,433) (15,445,533) (1,843,032)
Extensions, additions
and discoveries. 12,757,280 56,781,465 3,728,389
Production................ (3,372,040) (2,390,023) (1,156,297)
Development costs......... -- -- --
Purchases in place........ 397,644 -- 2,609,642
Sales in place............ (1,136,460) (4,292,526) (328,639)
-------------- -------------- --------------
Net change........... (13,871,009) 34,653,383 3,010,063
Standardized Measure,
End of Period..........$ 34,153,079 $ 48,024,088 $ 13,370,705
============== ============== ==============
</TABLE>
Year-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $13.46, $19.50, and
$18.00 per Bbl at December 31, 1997, 1996, and 1995, respectively. Year-end
weighted average gas prices were $2.03, $3.37, and $1.85 per Mcf at December 31,
1997, 1996, and 1995, respectively. Price and cost revisions are primarily the
net result of changes in period-end prices, based on beginning of period reserve
estimates.
F-22
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
Year ended December 31, 1997.
</LEGEND>
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 16,678,655
<SECURITIES> 0
<RECEIVABLES> 1,273,298
<ALLOWANCES> 0
<INVENTORY> 1,376,737
<CURRENT-ASSETS> 19,574,883
<PP&E> 33,176,893
<DEPRECIATION> (6,607,487)
<TOTAL-ASSETS> 46,713,978
<CURRENT-LIABILITIES> 4,702,267
<BONDS> 0
0
0
<COMMON> 54,583
<OTHER-SE> 39,442,974
<TOTAL-LIABILITY-AND-EQUITY> 46,713,978
<SALES> 4,805,051
<TOTAL-REVENUES> 4,865,898
<CGS> 3,591,003
<TOTAL-COSTS> 4,890,854
<OTHER-EXPENSES> (12,440)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> (114,036)
<INCOME-PRETAX> 101,520
<INCOME-TAX> 2,514,154
<INCOME-CONTINUING> (2,412,634)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (2,412,634)
<EPS-PRIMARY> (0.73)
<EPS-DILUTED> (0.73)
</TABLE>
