<PAGE> 1
SCHEDULE 14A INFORMATION
(Rule 14a-101)
Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934
Filed by the Registrant [X]
Filed by a Party other than the Registrant [ ]
Check the appropriate box:
[ ] Preliminary Proxy Statement
[ ] Confidential, for Use of the Commission Only (as permitted by Rule
14a-6(e)(2))
[X] Definitive Proxy Statement
[ ] Definitive Additional Materials
[ ] Soliciting Material Pursuant to ss. 240.14a-11(c) or ss. 240.14a-12
PETROGLYPH ENERGY, INC.
- --------------------------------------------------------------------------------
(Name of Registrant as Specified in its Charter)
- --------------------------------------------------------------------------------
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
[X] No fee required.
[ ] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
1) Title of each class of securities to which transaction applies:
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2) Aggregate number of securities to which transaction applies:
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3) Per unit price or other underlying value of transaction computed
pursuant to exchange Act Rule 0-11 (set forth the amount on which the
filing fee is calculated and state how it was determined):
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4) Proposed maximum aggregate value of transaction:
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5) Total fee paid:
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[ ] Fee paid previously with preliminary materials.
[ ] Check box if any part of the fee is offset as provided by Exchange Act Rule
0-11(a)(2) and identify the filing for which the offsetting fee was paid
previously. Identify the previous filing by registration statement number,
or the Form or Schedule and the date of its filing.
1) Amount Previously Paid:
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4) Date Filed:
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<PAGE> 2
PETROGLYPH ENERGY, INC.
1302 NORTH GRAND
HUTCHINSON, KANSAS 67501
NOTICE OF SPECIAL MEETING OF STOCKHOLDERS
TO BE HELD ON FEBRUARY 15, 2000
To the Stockholders of PETROGLYPH ENERGY, INC.
Notice is hereby given that a special meeting of stockholders, or any
adjournment or postponement thereof, of Petroglyph Energy, Inc., a Delaware
corporation (the "Company"), will be held on Tuesday, February 15, 2000, at 9:00
a.m., local time, at the Kansas Cosmosphere & Space Center, 1100 North Plum
Street, Hutchinson, Kansas 67501, for the following purposes:
1. To approve the issuance of (a) 250,000 shares of Series A
Convertible Preferred Stock, par value $.01 per share (the "Preferred
Shares"), to III Exploration Company, an affiliate of the Company ("III
Exploration"), in exchange for certain oil and gas producing properties
primarily located in the Uinta Basin of Utah; and (b) shares of common
stock, par value $.01 per share (the "Common Stock"), upon the
potential conversion of the Preferred Shares.
2. To transact such other business as may properly come before
the meeting or any adjournment(s) thereof.
Only stockholders of record at the close of business on January 11,
2000 are entitled to notice of, and to vote at, the special meeting.
You are cordially invited and urged to attend the special meeting, but
if you are unable to attend, please sign and date the enclosed proxy and return
it promptly in the enclosed self-addressed stamped envelope. A prompt response
will be appreciated. If you attend the special meeting, you may vote in person,
if you wish, whether or not you have returned your proxy. In any event, a proxy
may be revoked at any time before it is exercised.
BY ORDER OF THE BOARD OF DIRECTORS
ROBERT C. MURDOCK
President, Chief Executive Officer
and Chairman of the Board
Hutchinson, Kansas
January 14, 2000
<PAGE> 3
PETROGLYPH ENERGY, INC.
1302 NORTH GRAND
HUTCHINSON, KANSAS 67501
PROXY STATEMENT
FOR
SPECIAL MEETING OF STOCKHOLDERS
TO BE HELD ON FEBRUARY 15, 2000
SOLICITATION OF PROXIES
SOLICITATION AND REVOCABILITY OF PROXIES
This proxy statement is furnished to holders of Petroglyph Energy, Inc.
("Petroglyph" or the "Company") common stock, $0.01 par value ("Common Stock"),
in connection with the solicitation of proxies on behalf of the Board of
Directors of the Company for use at a special meeting of stockholders of
Petroglyph, or any adjournment or postponement thereof, to be held on February
15, 2000, at 9:00 a.m., local time, at the Kansas Cosmosphere & Space Center,
1100 North Plum Street, Hutchinson, Kansas 67501, and at any adjournment(s)
thereof, for the purposes set forth in the accompanying Notice of Special
Meeting of Stockholders.
Shares represented by a proxy in the form enclosed, duly signed, dated
and returned to the Company and not revoked, will be voted at the meeting in
accordance with the directions given, but in the absence of directions to the
contrary, such shares will be voted (i) for the issuance of (a) 250,000 shares
of Series A Convertible Preferred Stock, par value $.01 per share (the
"Preferred Shares"), to III Exploration Company, an affiliate of the Company
("III Exploration"), in exchange for certain oil and gas producing properties
primarily located in the Uinta Basin of Utah, and (b) shares of Common Stock
upon the potential conversion of the Preferred Shares; and (ii) in accordance
with the best judgment of the persons voting on any other proposals that may
properly come before the meeting. The Board of Directors knows of no other
matters, other than those stated in the foregoing notice, to be presented for
consideration at the special meeting or any adjournment(s) thereof. If, however,
any other matters properly come before the special meeting or any adjournment(s)
thereof, it is the intention of the persons named in the enclosed proxy to vote
such proxy in accordance with their judgment on any such matters. The persons
named in the enclosed proxy may also, if it is deemed to be advisable, vote such
proxy to adjourn the meeting from time to time.
Any stockholder executing and returning a proxy has the power to revoke
it at any time before it is voted by delivering to the Secretary of the Company,
1302 North Grand, Hutchinson, Kansas 67501, a written revocation thereof or by
duly executing a proxy bearing a later date. Any stockholder attending the
special meeting of stockholders may revoke his proxy by notifying the Secretary
at such meeting and voting in person if he desires to do so. Attendance at the
annual meeting will not by itself revoke a proxy.
The approximate date on which this proxy statement and the form of proxy
are first sent to stockholders is January 14, 2000.
The cost of soliciting proxies will be borne by the Company. Solicitation
may be made, without additional compensation, by directors, officers and regular
employees of the Company in person or by mail, telephone or telegram. The
Company may also request banking institutions, brokerage firms, custodians,
trustees, nominees and fiduciaries to forward solicitation material to the
beneficial owners of the Common Stock held of record by such persons, and
Petroglyph will reimburse the forwarding expense. All costs of preparing,
printing and mailing the form of proxy and the material used in the solicitation
thereof will be borne by the Company.
RECENT EVENTS
Change of Control. On August 18, 1999, III Exploration completed the
purchase (the "Purchase") from Robert A. Christensen, a director and executive
officer of the Company, David R. Albin, a director of the Company, Kenneth A.
Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster, Bruce B.
Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural Gas
Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of Common Stock of the Company.
<PAGE> 4
According to the Schedule 13D filed with the Securities and Exchange
Commission by III Exploration on August 30, 1999, III Exploration is controlled
by Intermountain Industries, Inc., an Idaho corporation ("Intermountain"). The
Purchase was effected through a privately negotiated sale between the Sellers
and Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999, with a purchase price of $3.00 per share. The source of funds for
the Purchase came from working capital of Intermountain. As a result of the
Purchase, Intermountain, through its ownership of III Exploration, acquired
approximately 50.4% of the outstanding Common Stock of the Company.
Intermountain operates the largest natural gas distribution utility in
Idaho, the largest end-use natural gas marketing business in the northwest
United States and has producing oil and gas properties in the Rocky Mountain
region including the Uinta Basin of Utah.
In connection with the sale, David Albin, Kenneth Hersh and Robert
Christensen tendered their resignations from the Company's Board of Directors.
Mr. Christensen also resigned as an executive officer, but remained employed by
the Company as an engineering advisor until December 31, 1999. After discussing
the resignations with Intermountain, the remaining members of the Company's
Board of Directors nominated William C. Glynn, Richard Hokin and Eugene C.
Thomas, who are also members of Intermountain's Board of Directors, to fill the
vacancies created on the Board of Directors by the resignations.
Acquisition of Assets. On August 20, 1999, the Company acquired the
remaining 50% working interest in the Antelope Creek Field in the Uinta Basin of
Utah (the "Antelope Creek Property") from its non-operated working interest
partner, Williams Production Rocky Mountain Company ("Williams"), for a purchase
price of $6.9 million (the "Antelope Creek Acquisition"). The Antelope Creek
Acquisition, which was effective August 1, 1999, gives the Company a 100%
working interest in the Antelope Creek Property.
In order to finance the Antelope Creek Acquisition, the Company borrowed
$2.5 million on an existing revolving credit facility with The Chase Manhattan
Bank ("Chase") pursuant to Amendment No. 1 dated as of August 20, 1999 to the
Second Amended and Restated Credit Agreement by and between the Company and
Chase dated as of September 30, 1998.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III Exploration. The Notes also required the Company
to deliver to III Exploration a stock purchase warrant to acquire 150,000 shares
of Common Stock of the Company at an exercise price of $3.00 per share and
granted III Exploration the ability to obtain additional stock purchase warrants
over the life of the Notes. The number of future stock purchase warrants will be
based on the future stock price performance and the amount and duration of the
Notes outstanding. The maximum number of shares of Common Stock issuable under
the stock purchase warrants for any given period is limited to 250,000 shares in
any one year, 400,000 over the first three years and 750,000 over the five-year
life of the Notes. Petroglyph may redeem the Notes at par without penalty at any
time. Upon redemption of the Notes, any remaining unissued and unearned stock
purchase warrants will expire. The Company utilized proceeds from the Notes to
finance the remaining purchase price of the Antelope Creek Acquisition and for
working capital needs.
Private Placement. On December 28, 1999, the Company sold 1,000,000
shares of Common Stock to III Exploration in a privately negotiated sale at a
purchase price of $2.00 per share, for aggregate proceeds of $2.0 million (the
"Private Placement"). The Common Stock issued in the Private Placement has not
been registered under the Securities Act of 1933, as amended (the "Securities
Act"), and may not be offered or sold in the United States absent registration
or an applicable exemption from registration requirements. The Company intends
to use the proceeds from the Private Placement for working capital, to finance
existing operations and to finance a portion of the Company's 2000 development
plans for its Uinta Basin and Raton Basin properties. As a result of the Private
Placement, III Exploration's ownership interest in the Company's Common Stock
has increased to 59.07% (assuming the exercise of a warrant to purchase 150,000
shares of Common Stock).
RECORD DATE AND VOTING SECURITIES
The close of business on January 11, 2000 is the record date (the "Record
Date") for determination of stockholders entitled to notice of and to vote at
the special meeting or any adjournment(s) thereof. The only voting security of
the Company outstanding is the Common Stock, each share of which entitles the
holder thereof to one vote. At the Record Date, there were outstanding and
entitled to be voted 6,458,333 shares of Common Stock.
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QUORUM AND VOTING
The presence at the special meeting, in person or by proxy, of the
holders of a majority of the Common Stock issued and outstanding is necessary to
constitute a quorum to transact business. Each share represented at the special
meeting, in person or by proxy, including the shares held by III Exploration to
the extent represented at the meeting, will be counted for purposes of
determining whether a quorum is present. In deciding all matters, a holder of
Common Stock on the Record Date shall be entitled to cast one vote for each
share of Common Stock then registered in such holder's name.
The Nasdaq Stock Market requires stockholder approval, by a majority of
the shares of Common Stock of the Company present and entitled to vote, prior to
the issuance of the Preferred Shares, including approval for the issuance of
shares of Common Stock upon the potential conversion of the Preferred Shares.
The conditions to the Purchase and Sale Agreement (as defined below), pursuant
to which the Preferred Shares will be issued, also require the approval by a
majority of the outstanding shares of Common Stock of the Company present at the
Special Meeting and entitled to vote. Votes may be cast for or against the
proposal or stockholders may abstain from voting on the proposal. Intermountain
is not restricted from voting its shares of Common Stock in person or by proxy
at the special meeting. As a result, the Company believes that Intermountain
will vote its shares of Common Stock in favor of the proposal.
Brokers who hold shares in street name only have the authority to vote on
certain items when they have not received instructions from beneficial owners.
Any such "broker non-votes" will not be considered to be present and entitled to
vote and will have no effect on the proposal.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The table below sets forth information concerning (i) the only persons
known by the Company, based upon statements filed by such persons pursuant to
Section 13(d) or 13(g) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), to own beneficially in excess of 5% of the Common Stock as of
December 31, 1999 and (ii) the number of shares of Common Stock beneficially
owned, as of December 31, 1999, by each director of the Company, each executive
officer required to be named pursuant to Item 402 of Regulation S-K under the
Exchange Act and all executive officers and directors of the Company as a group.
Except as indicated, each individual has sole voting power and sole investment
power over all shares listed opposite his name.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY
OWNED
--------------- ----------------
NAME OF BENEFICIAL OWNER NUMBER PERCENT
--------------- ----------------
<S> <C> <C>
Directors and Named Executive Officers (1):
Wm. C. Glynn................................................................. -- *
Richard Hokin (2)............................................................ 3,903,392 59.07%
Eugene C. Thomas............................................................. -- *
A.J. Schwartz (3)............................................................ 9,710 *
Robert C. Murdock (4)........................................................ 272,043 4.12%
Robert A. Christensen (5).................................................... 150,000 2.27%
S. "Ken" Smith (6)........................................................... 191,198 2.90%
Executive Officers and Directors as a Group (8 persons) (7).................. 4,581,343 64.44%
Holders of 5% or More Not Named Above
III Exploration Company(2) .................................................. 3,903,392 59.07%
555 South Cole Road
Boise, Idaho 83709
Wellington Management Company, LLP (8) ...................................... 540,100 8.36%
75 State Street
Boston, MA 02109
</TABLE>
* Represents less than 1% of outstanding Common Stock.
(1) The business address of each director and executive officer is care of
Petroglyph Energy, Inc., 1302 North Grand, Hutchinson, Kansas 67501.
(2) Based upon information reported in a Schedule 13D dated August 18, 1999
filed by III Exploration, Century Partners -- Idaho Limited
Partnership, Richard Hokin and Intermountain Industries, Inc.
(collectively, the "Intermountain Parties"). The Intermountain Parties
share the power to dispose of or direct the disposition of all of such
shares of which they may be deemed beneficial owners. Includes 150,000
shares subject to a stock purchase warrant.
(3) Includes (i) 6,000 shares held by Mr. Schwartz's son and (ii) 1,825
shares held by affiliates of Mr. Schwartz.
(4) Includes (i) 122,043 shares held by Mr. Murdock and (ii) 150,000 shares
subject to stock options that are exercisable within 60 days.
(5) All of these shares are subject to stock options that are exercisable
within 60 days. Mr. Christensen has resigned as an executive officer
and director of the Company effective August 18, 1999.
(6) Includes (i) 45,198 shares held by Mr. Smith and (ii) 146,000 shares
subject to stock options that are exercisable within 60 days.
(7) Includes 651,000 shares subject to stock options and warrants that are
exercisable within 60 days.
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<PAGE> 7
(8) Based upon information reported in a Schedule 13G dated February 9,
1998 and a Schedule 13G/A dated February 10, 1999 filed by Wellington
Management Company, LLP ("WMC"). WMC holds such shares in its capacity
as an investment adviser which are owned of record by clients of WMC.
WMC shares the power to vote or direct the vote of 290,000 of such
shares and shares the power to dispose of or direct the disposition of
all 540,100 shares of which it may be deemed a beneficial owner.
PROPOSAL 1. APPROVAL OF THE ISSUANCE OF THE PREFERRED SHARES
AND THE ISSUANCE OF COMMON STOCK
UPON THE POTENTIAL CONVERSION OF THE PREFERRED SHARES
The Company is seeking stockholder approval, pursuant to Rule 4460 of
The Nasdaq Stock Market ("Rule 4460"), of:
(a) the issuance of 250,000 Preferred Shares to III Exploration in
exchange for certain oil and gas producing properties
primarily located in the Uinta Basin of Utah; and
(b) the issuance of shares of Common Stock upon the potential
conversion of the Preferred Shares.
When a company proposes to issue securities convertible into a number
of shares of common stock exceeding five percent of the number of common shares
outstanding prior to the transaction to a substantial security holder in
exchange for properties, Rule 4460 requires stockholder approval prior to the
issuance of such securities. Pursuant to the Purchase and Sale Agreement, dated
as of December 28, 1999 (the "Purchase and Sale Agreement"), between the Company
and III Exploration, described below, the Company will issue an aggregate of
250,000 Preferred Shares to III Exploration, a wholly-owned subsidiary of
Intermountain, the current majority stockholder of the Company. Three of the
members of the Company's Board of Directors are also on the Board of Directors
of Intermountain. The Preferred Shares will be convertible, beginning two years
from the date of issuance, into shares of Common Stock at a conversion price of
$3.50 per share of Common Stock, based on the preference amount of $10.00 per
Preferred Share. The Company has the option to redeem the Preferred Shares at
any time after the third anniversary of the Closing Date (as defined below) in
whole or in part at a redemption price of $12.00 per Preferred Share. The
issuance of the Preferred Shares to III Exploration is permissible under the
Delaware General Corporation Law without the necessity of any stockholder
action. The Company's Board of Directors approved the transaction pursuant to
which III Exploration became a substantial security holder of the Company prior
to such transaction as it related, and provided benefits, to the Company.
The following summary of the provisions of the Purchase and Sale
Agreement and the Certificate of Designations of Series A Convertible Preferred
Stock (the "Certificate of Designations") is qualified in its entirety by
reference to such documents which are incorporated herein by reference. The
Certificate of Designations is attached hereto as Exhibit "A." The Purchase and
Sale Agreement has been included as an exhibit to the Company's Current Report
on Form 8-K as filed with the Securities and Exchange Commission and a copy of
such document and the original Certificate of Designations can be obtained by
writing or calling Tim A. Lucas, Vice President, Petroglyph Energy, Inc., 1302
North Grand, Hutchinson, Kansas 67501, telephone (316) 665-8500.
GENERAL DESCRIPTION OF THE ISSUANCE OF THE PREFERRED SHARES
Pursuant to the Purchase and Sale Agreement, the Company has agreed to
issue the Preferred Shares to III Exploration in exchange for certain oil and
gas producing properties (the "Properties") primarily located in the Uinta Basin
of Utah (the "Transaction").
The purchase of the Properties and issuance and sale of the Preferred
Shares will take place at the closing (the "Closing") to be held on or before
the third business day after the conditions to the Closing have been satisfied
or waived or on such other date as the parties may agree (the "Closing Date").
At the Closing, subject to the terms and conditions set forth in the Purchase
and Sale Agreement, the Company will deliver to III Exploration the Preferred
Shares in exchange for the Properties.
The Preferred Shares are being issued pursuant to an exemption from the
registration requirement under the Securities Act and will be subject to
transfer restrictions imposed by the Securities Act.
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<PAGE> 8
Consummation of the Transaction is conditioned on the approval of the
issuance of the Preferred Shares by the Company's stockholders at the special
meeting. Based on its evaluation of the Transaction, the members of the
Company's Board of Directors that are not affiliated with III Exploration or
Intermountain have recommended that the Company's stockholders vote in favor of
the issuance to III Exploration of the Preferred Shares and the issuance of
shares of Common Stock upon the conversion of the Preferred Shares. In the event
that the Company does not obtain such stockholder approval, the Company is not
required to, and will not, consummate the Transaction. Intermountain is not
restricted from voting its shares of Common Stock in person or by proxy at the
special meeting. As a result, the Company believes that Intermountain will vote
its shares of Common Stock in favor of the proposal.
BACKGROUND OF THE TRANSACTION
In June 1999, members of Petroglyph's management began discussions with
representatives of certain institutional investors, including III Exploration,
with the purpose of locating interested investors willing to buy Petroglyph
Common Stock in the open market. Simultaneously, Natural Gas Partners, L.P.,
Natural Gas Partners II, L.P. and Natural Gas Partners III, L.P. (collectively,
"NGP") held discussions with members of Petroglyph's management about possible
ways to increase NGP's liquidity and provide other exit strategies for NGP. In
July 1999, William C. Glynn, President of Intermountain and III Exploration,
contacted Robert C. Murdock, Petroglyph's President, Chief Executive Officer and
Chairman, to discuss the possibility of III Exploration acquiring a significant
ownership position in Petroglyph. Mr. Murdock referred Mr. Glynn to
representatives of NGP, who then began negotiating a transaction that led to the
acquisition by III Exploration of approximately 50.4% of the outstanding Common
Stock of Petroglyph from NGP and certain of its affiliates.
Following the consummation of the transaction between III Exploration
and NGP, Kenneth A. Hersh and David R. Albin, affiliates of NGP, and Robert A.
Christensen, an executive officer of Petroglyph who participated in the sale to
III Exploration, tendered their resignations from Petroglyph's Board of
Directors. William C. Glynn, Richard Hokin and Eugene C. Thomas, who are members
of Intermountain's Board of Directors, were appointed to fill the vacancies
created on Petroglyph's Board of Directors.
After the sale of NGP's interest to III Exploration, the continuing
members of Petroglyph's Board of Directors began discussing with the new members
of the board the Company's capital expenditure budget for the remainder of 1999
and 2000. In addition, management presented estimated cash flow information for
the Company for the same period. According to management estimates, the Company
needed to increase cash flow from its existing properties, sell a portion of its
Raton Basin project or obtain additional equity or debt financing in order to
maintain its current level of operations and to fund future development. As a
result of this information, the board began discussing possible transactions
that would improve the Company's cash flow. During September 1999, Mr. Murdock
suggested that the Company evaluate a group of producing oil and gas properties
owned by III Exploration located primarily in the Uinta Basin of Utah, one of
the Company's core operating areas. During the months of October and November
1999, several members of Petroglyph's financial and technical staff reviewed and
evaluated the Properties' proved producing oil and gas reserve data and
historical results of operations.
In November 1999, Mr. Murdock and Mr. Glynn met to discuss a proposed
transaction that would involve the issuance of a new series of preferred stock,
convertible into Common Stock, to III Exploration in exchange for III
Exploration's interest in the Properties. The parties reviewed the Company's
reserve values, cash flow, production, debts and liabilities and potential
future projects and prospects. The parties then reviewed an analysis of the
value of the Properties' reserves prepared for III Exploration by Ryder Scott
Company - Petroleum Engineers ("Ryder Scott") and the corresponding cash flow,
production and future prospects. At the end of this review period, the two
companies' representatives concurred that the sale of the Properties for 250,000
shares of preferred stock convertible into approximately 714,000 shares of
Common Stock of Petroglyph warranted further discussion. On November 30, 1999,
the Company and III Exploration entered into a letter of intent with respect to
the purchase of the Properties.
During late November and early December 1999, representatives of
Petroglyph and III Exploration discussed reserves, operations, pending projects
and other due diligence issues related to the Properties. At the same time,
representatives of the companies and their legal advisors began to work on
documentation for the proposed transaction.
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<PAGE> 9
On
Between December 17 and 21, 1999, the Petroglyph Board of Directors met
on several occasions to discuss the proposed transaction. On December 21, 1999,
the disinterested members of the board approved the Purchase and Sale Agreement
and the underlying issuance of Preferred Shares, subject to the negotiation of a
definitive agreement and Petroglyph stockholder approval. In addition, the board
considered the Company's liquidity position and proposed 2000 capital spending
plan, including $6.0 million of projected capital necessary to develop the
Antelope Creek Field, and concluded that the Company needed to obtain additional
equity financing in order to initiate its 2000 development plans and fund its
current level of operations. As a result, the board considered a private equity
sale to III Exploration in order to address the Company's immediate liquidity
needs. III Exploration offered to acquire 1,000,000 shares of Common Stock at a
purchase price of $2.00 per share, which represented the current market price,
for an aggregate of $2.0 million. See "Recent Developments -- Private
Placement." The Private Placement and the Transaction are not related
transactions, and neither transaction is contingent on the closing of the other
transaction.
The Purchase and Sale Agreement was signed on December 28, 1999, and it
was announced in a press release that afternoon.
REASONS FOR THE TRANSACTION
The Petroglyph Board of Directors considered various factors, including
the following, in unanimously approving the Transaction:
1. An Increase in Cash Flow -- The Properties consist of
proved, producing oil and gas reserves that Petroglyph anticipates will
provide additional cash flow of approximately $900,000 during the first
year.
2. An Increase in Proved Producing Oil and Gas Reserves --
Petroglyph expects that its proved developed producing reserves will
increase 15% or 400,000 BOE from current internally estimated levels as
a result of the Transaction.
3. A Broader Portfolio of Opportunities -- Petroglyph
currently has operations in the Uinta Basin in Utah. The combination of
III Exploration's assets with Petroglyph's assets in this area
strengthens Petroglyph's position in one of its established core areas.
The addition of the Properties provides Petroglyph with a broader range
of acquisition opportunities.
In determining to recommend approval of the Transaction, the Petroglyph
board considered the matters set forth above in the context of the Company's
current financial situation, which required additional cash flow to maintain
existing operations and develop its core areas. At September 30, 1999, the
Company had cash and cash equivalents of $274,000 and long term debt of $15.5
million compared to cash and cash equivalents of $2.0 million and long term debt
of $7.5 million at December 31, 1998. With the consummation of the Private
Placement, the Company has addressed a current liquidity problem and obtained
sufficient capital to initiate its 2000 development plan. Petroglyph's
management believes that the acquisition of the Properties will provide the
Company, together with the cash proceeds from the Private Placement, the
additional cash flow necessary to finance the Company's existing operations for
at least the next 12 months. Management believes that the continued development
of the Company's core areas should further increase cash flow and improve the
Company's liquidity. However, to ultimately accomplish the Company's 2000
capital spending plan, additional capital in the form of increases in borrowing
availability, operating cash flow or private equity will be required.
For purpose of the board's analysis, the board made certain assumptions
with respect to the performance and cash flow of the Properties, the Company's
ability to develop the Uinta and Raton Basin properties, general industry,
business, economic, market and financial conditions and other matters beyond its
control and the control of the Company. Actual conditions may differ
significantly from those assumed. Accordingly, such analysis and estimates are
inherently subject to substantial uncertainty.
In evaluating the Transaction, the board (i) reviewed a reserve report
prepared for III Exploration by Ryder Scott in arriving at a range of values for
the Properties; (ii) reviewed an internal evaluation of the Properties prepared
by the Company; (iii) reviewed the structure and rights of the Preferred Shares
to be issued as consideration for the Properties; (iv) valued the Preferred
Shares in comparison to the estimated value of the
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<PAGE> 10
Properties; (v) reviewed the potential pro forma impact of the Transaction on
Petroglyph's earnings per share and cash flow; (vi) reviewed the Purchase and
Sale Agreement and related documents; and (vii) reviewed the Company's financial
condition and liquidity position.
VALUATION OF THE PROPERTIES
In arriving at a value for the Properties, the board relied on the
Company's internal evaluation of the properties and on the reserve report
prepared by Ryder Scott. Ryder Scott made certain assumptions to create a
10-year projection of future cash flows associated with the Properties.
Utilizing various discount rates ranging from 10% to 20%, Ryder Scott then
discounted these projected cash flows to their present value to arrive at a
current valuation. Using an average realized price of $17.50 per barrel of oil
and $2.14 per Mcf of gas, this valuation ranged from $2.3 million to $2.8
million.
VALUATION OF THE PREFERRED SHARES
Comparable Public Company Convertible Preferred Stock Analysis. As part
of its analysis, the board considered management's comparison of certain
structural characteristics and features inherent in the Preferred Shares to be
issued as consideration for the Properties with certain characteristics and
features of other convertible preferred stock issued by a group of similar
exploration and production companies. These companies included several mid to
small capitalization exploration and production companies including but not
limited to Cabot Oil & Gas Corp., Callon Petroleum Company, Chesapeake Energy
Corp., Magnum Hunter Resources, Inc. and Mallon Resources Corp. The board
concluded that the structural characteristics of and the features inherent in
the Preferred Stock were comparable to the preferred stock of the other
companies.
Valuation of the Convertible Preferred Stock. Based on the Purchase and
Sale Agreement, the total consideration to be paid by Petroglyph for the
Properties is $2.5 million of Preferred Shares. Utilizing various valuation
techniques, the board attempted to value the Preferred Shares to ensure that its
value on the date issued was similar to the agreed upon consideration of $2.5
million. To value the Preferred Shares, the board measured the components that
make up its value, including the value of the Preferred Shares without regard to
the conversion option, the value of the holder's convert option and the value of
Petroglyph's redemption option.
REVIEW OF PRO FORMA RESULTS
The board considered the pro forma impact of the Transaction on
earnings per share and cash flow per share for Petroglyph for the calendar years
ending 1999 and 2000. The pro forma analysis also took into account the
anticipated cash flow expected to be derived from the Properties as estimated by
management and the impact from the additional shares from the issuance of the
Preferred Shares. Management believes that the Transaction would be accretive to
both earnings per share and cash flow per share in 2000. The closing date of the
Transaction will be subsequent to 1999. Therefore, consistent with applicable
accounting standards, any cash flow benefit that would have been derived from
the properties related to 1999 will be settled in cash to the Company at Closing
and reflected as a reduction of the purchase price.
CONCLUSION
Based on these and other factors the members of the Petroglyph's board
deemed relevant, the disinterested members of the board unanimously approved the
Purchase and Sale Agreement and the Transaction.
The disinterested members of Petroglyph's board believe that the
acquisition of the Properties in exchange for the Preferred Shares is in the
best interests of the Petroglyph stockholders and recommend that the Petroglyph
stockholders approve the acquisition of the Properties and the issuance of the
Preferred Shares to III Exploration.
The above discussion of the information and factors considered and
given weight by the Petroglyph board is not intended to be exhaustive. However,
the discussion is believed to include all material factors considered by the
Petroglyph board. In reaching the decision to approve and recommend approval to
Petroglyph's stockholders of the Purchase and Sale Agreement and the issuance of
the Preferred Shares, the Petroglyph board did not assign any relative or
specific weights to the factors considered. In addition, individual directors
may have given differing weights to different factors.
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The board realizes that there are risks associated with the
Transaction. These risks include the prospect that some of the potential
benefits set forth above may not be realized or that there may be high costs
associated with realizing those benefits. However, the board believes that the
expected benefits should outweigh any potential detriments, although it can give
no assurances in this regard.
TERMS OF THE PREFERRED SHARES
Set forth below is a summary of certain terms of the Preferred Shares.
This summary is not complete and is qualified in its entirety by reference to
the Certificate of Designations for the Preferred Shares.
Ranking. With respect to distributions upon the liquidation, winding-up
and dissolution of the Company, the Preferred Shares will rank (i) senior to all
classes of Common Stock of the Company, (ii) on a parity with any additional
shares of preferred stock issued by the Company in the future and any other
class of capital stock or series of preferred stock established after December
28, 1999, the terms of which expressly provide that such class or series will
rank on a parity with the Preferred Shares as to dividend distributions and
distributions upon the liquidation, winding-up and dissolution of the Company,
and (iii) junior to each class of capital stock or series of preferred stock
issued by the Company or established after December 28, 1999, the terms of which
expressly provide that such class or series will rank senior to the Preferred
Shares as to dividend distributions and/or distributions upon the liquidation,
winding-up and dissolution of the Company.
Liquidation Preference. Upon any voluntary or involuntary liquidation,
dissolution or winding-up of the Company, each holder of Preferred Shares will
be entitled to payment out of the assets of the Company available for
distribution of an amount equal to $10.00 per Preferred Share held by such
holder (the "Liquidation Preference"), plus accrued and unpaid dividends, if
any, to the date fixed for liquidation, dissolution or winding-up, before any
distribution is made on the Common Stock or any other securities junior to the
Preferred Shares. After payment in full of the Liquidation Preference and such
dividends, if any, to which holders of Preferred Shares are entitled, such
holders will not be entitled to any further participation in any distribution of
assets of the Company.
Dividends. The Preferred Shares will have a stated dividend at a fixed
rate of 8% of the aggregate Liquidation Preference per annum with cumulative
quarterly dividends being paid in additional Preferred Shares for the first two
years after the issuance of the Preferred Shares and paid in cash for all
subsequent periods.
Restriction on Dividends on Junior Securities. At any time in which the
Preferred Shares remain outstanding, the Company shall be prohibited from
declaring or paying any dividend (other than dividends payable in Common Stock)
with respect to any security junior to the Preferred Shares, including the
Common Stock, unless the Company has declared and paid in all quarterly
dividends on the Preferred Shares required to be paid through such date.
Conversion Rights. At any time after the second anniversary of the
issuance of the Preferred Shares, the Preferred Shares will be convertible, at
the option of the holders, into shares of Common Stock at a conversion price of
$3.50 per share of Common Stock, based on the preference amount of $10.00 per
Preferred Share.
The Certificate of Designations provides that the conversion price and
the number and kind of securities or rights into which the Preferred Shares are
convertible are subject to certain anti-dilution adjustments upon the occurrence
of any of the following events:
- a distribution in the form of Common Stock is made on any class of
capital stock of the Company (see subsection 9(b) of the
Certificate of Designations);
- the outstanding shares of Common Stock are subdivided into a
greater number of shares of Common Stock or combined into a smaller
number of shares of Common Stock (see subsection 9(b) of the
Certificate of Designations); or
- a consolidation or merger of the Company, the sale or transfer of
all or substantially all of the assets of the Company, or a capital
reorganization or reclassification, conversion or exchange of
shares of Common Stock (see subsection 9(b) of the Certificate of
Designations).
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<PAGE> 12
Redemption or Automatic Conversion. The Company has no obligation to
redeem or repurchase the Preferred Shares.
Redemption at the Option of the Company. At any time after the third
anniversary of the issuance of the Preferred Shares, the Company may, at its
election, redeem, in whole or in part, the then outstanding Preferred Shares at
a redemption price in cash of $12.00 per Preferred Share.
Voting. Except as otherwise required by Delaware law, the holders of
the Preferred Shares shall not have any right or power to vote (or act by
written consent) with respect to any matter submitted to the stockholders of the
Company for a vote (or for action).
TRANSFER RESTRICTIONS
The Preferred Shares will not be registered under federal or state
securities laws and will bear a legend to such effect. Under such laws, the
Preferred Shares may not be offered, sold or transferred except (i) pursuant to
an exemption from registration under the Securities Act and such other
applicable laws, or (ii) pursuant to an effective registration statement under
the Securities Act.
CONDITIONS TO THE PURCHASERS' OBLIGATION TO CLOSE
The obligation of III Exploration to purchase the Preferred Shares at
the Closing is subject to the satisfaction or waiver of the following
conditions:
- The representations and warranties of the Company contained in the
Purchase and Sale Agreement shall be true and correct when made
and at the time of the Closing;
- The Company shall have performed and complied in all material
respects with all covenants, agreements and conditions contained
in the Purchase and Sale Agreement required to be performed or
complied with by it prior to or at the Closing;
- No suit, action or other proceeding shall, on the date of Closing,
be pending or threatened before any court or governmental agency
seeking to restrain, prohibit or obtain damages or other relief in
connection with the consummation of the transactions contemplated
by the Purchase and Sale Agreement; and
- The transactions contemplated by the Purchase and Sale Agreement
shall have been approved by the board of directors of III
Exploration.
VOTE REQUIRED
TO APPROVE THE ISSUANCE OF PREFERRED SHARES AND THE ISSUANCE OF COMMON
STOCK UPON THE CONVERSION OF THE PREFERRED SHARES, THE AFFIRMATIVE VOTE OF A
MAJORITY OF THE SHARES OF COMMON STOCK PRESENT IN PERSON OR REPRESENTED BY PROXY
AND ENTITLED TO VOTE ON THE MATTER IS REQUIRED. THE DISINTERESTED MEMBERS OF THE
BOARD OF DIRECTORS UNANIMOUSLY RECOMMEND A VOTE "FOR" THIS PROPOSAL. PROXY CARDS
EXECUTED AND RETURNED WILL BE VOTED FOR THIS PROPOSAL UNLESS CONTRARY
INSTRUCTIONS ARE INDICATED THEREON.
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<PAGE> 13
STOCKHOLDERS' PROPOSALS
Stockholders' proposals were eligible for consideration for inclusion
in the proxy statement for the 2000 annual meeting pursuant to Rule 14a-8 under
the Exchange Act, if such proposals were received by Petroglyph before the close
of business on December 22, 1999. Notices of stockholders' proposals submitted
outside the processes of Rule 14a-8 will be considered timely, pursuant to the
advance notice requirement set forth in Petroglyph's bylaws, if such notices are
delivered to or mailed and received by Petroglyph not less than 60 nor more than
120 days prior to the meeting. Any such proposal or notice should be directed to
the attention of the President, Robert C. Murdock.
SEC rules set forth standards for the exclusion of some shareholder
proposals from a proxy statement for an annual meeting.
ACCOUNTANTS
Representatives of Arthur Andersen LLP, the Company's principal
accountants, are not expected to attend the special meeting.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The SEC allows the Company to incorporate by reference to documents
previously filed with the SEC. All information incorporated by reference is
considered a part of this Proxy Statement and this Proxy Statement should be
read in connection with all such incorporated information. The following
documents previously filed with the SEC are hereby incorporated by reference
into this Proxy Statement:
- Item 6 - Selected Financial Data, Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations,
Item 7A - Quantitative and Qualitative Disclosure About Market
Risk, Item 8 - Consolidated Financial Statements and Supplementary
Data, and Item 9 - Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure included in the Company's
Annual Report for the fiscal year ended December 31, 1998.
- Item 7 - Financial Statements of the Antelope Creek Acquisition
included in the Company's Current Report on Form 8-K/A (Date of
Event: August 18, 1999).
- Item 1 - Financial Statements, Item 2 - Management's Discussion
and Analysis of Financial Condition and Results of Operations and
Item 3 - Quantitative and Qualitative Disclosures About Market
Risk included in the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1999.
The portions of the Company's Annual Report for the fiscal year ended
December 31, 1998, the Company's Current Report on Form 8-K/A (Date of Event:
August 18, 1999) and the Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1999 are included with this Proxy Statement as Appendices I,
II and III, respectively. Any documents subsequently filed by the Company
pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of
1934, as amended, after the date of this Proxy Statement and prior to the date
of the Special Meeting shall also be deemed to be incorporated herein by
reference and to be a part hereof from the date of filing such documents.
By Order of the Board of Directors
Robert C. Murdock
President, Chief Executive Officer
and Chairman of the Board
January 14, 2000
Hutchinson, Kansas
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<PAGE> 14
EXHIBIT A
CERTIFICATE OF DESIGNATIONS
OF
SERIES A CONVERTIBLE PREFERRED STOCK
(PAR VALUE $.01 PER SHARE)
OF
PETROGLYPH ENERGY, INC.
----------------------------
PURSUANT TO SECTION 151
OF THE GENERAL CORPORATION LAW OF THE STATE OF DELAWARE
----------------------------
Petroglyph Energy, Inc., a corporation organized and existing under the
laws of the State of Delaware (the "Corporation"), DOES HEREBY CERTIFY that,
pursuant to the authority conferred on the Board of Directors of the Corporation
by the Certificate of Incorporation of the Corporation and in accordance with
Section 151 of the General Corporation Law of the State of Delaware, the Board
of Directors of the Corporation on December 21, 1999 duly adopted the following
preamble and resolution establishing and creating a series of 292,915 shares of
Preferred Stock, par value $.01 per share, of the Corporation:
RESOLVED, that pursuant to the authority vested in the Board of
Directors of the Corporation (the "Board of Directors") in accordance
with the provisions of its Certificate of Incorporation, as amended, a
series of Preferred Stock, par value $.01 per share, of the Corporation
is hereby created, and that the designation and number of shares
thereof and the preferences, limitations and relative rights thereof
are as follows:
SECTION 1. DESIGNATION AND NUMBER OF SHARES OF SERIES A CONVERTIBLE
PREFERRED STOCK. There is hereby authorized and established a series of
Preferred Stock that shall be designated as "Series A Convertible Preferred
Stock" (hereinafter referred to as "Series A Preferred"), and the number of
shares constituting such series shall be 292,915. Such number of shares may be
increased or decreased, but not to a number less than the number of shares of
Series A Preferred then issued and outstanding, by resolution adopted by the
full Board of Directors.
SECTION 2. DEFINITIONS. In addition to the definitions set forth
elsewhere herein, the following terms shall have the meanings indicated:
"Business Day" shall mean any day other than a Saturday, Sunday or a
day on which banking institutions in Hutchinson, Kansas are authorized or
obligated by law or executive order to close.
"Common Stock" shall mean the common stock, par value $0.01 per share,
of the Corporation.
"Conversion Price" shall mean $3.50 per share of Common Stock, subject
to adjustment pursuant to the provisions hereof.
"Dividend Payment Date" shall mean each March 15, June 15, September
15, and December 15, beginning with March 15, 2000, for so long as any shares of
Series A Preferred remain outstanding.
"Effective Date" shall mean November 1, 1999.
<PAGE> 15
"Junior Securities" means the Common Stock or any other series of stock
issued by the Corporation ranking junior as to the Series A Preferred upon
liquidation, dissolution or winding up of the Corporation.
"Original Issue Date" shall mean the date on which shares of the Series
A Preferred are first issued.
"Parity Security" means any class or series of stock issued by the
Corporation ranking on a parity with the Series A Preferred upon liquidation,
dissolution or winding up of the Corporation.
"Person" means any individual, corporation, association, partnership,
joint venture, limited liability company, trust, estate, or other entity or
organization, other than the Corporation, any subsidiary of the Corporation, any
employee benefit plan of the Corporation or any subsidiary of the Corporation,
or any entity holding shares of Common Stock for or pursuant to the terms of any
such plan.
"Preference Amount" shall mean the amount per share of Preferred Stock
payable in the event of the liquidation, dissolution or winding up of the
Corporation (in connection with the bankruptcy or insolvency of the Corporation
or otherwise. The Preference Amount is Ten Dollars and No Cents ($10.00).
"Senior Securities" means any class or series of stock issued by the
Corporation ranking senior to the Series A Preferred upon liquidation,
dissolution or winding up of the Corporation.
SECTION 3. CERTAIN COVENANTS AND RESTRICTIONS.
(a) So long as any shares of Series A Preferred are outstanding;
(i) The Corporation shall at all times reserve and keep
available for issuance upon the conversion of the shares of
Series A Preferred such number of its authorized but unissued
shares of Common Stock as will be sufficient to permit the
conversion of all outstanding shares of Series A Preferred,
and all other securities and instruments convertible into
shares of Common Stock, and shall take all reasonable action
within its power required to increase the authorized number of
shares of Common Stock necessary to permit the conversion of
all such shares of Series A Preferred and all other securities
and instruments convertible into shares of Common Stock.
(ii) The Corporation represents, warrants and agrees that
all shares of Common Stock that may be issued upon exercise of
the conversion rights of shares of Series A Preferred will,
upon issuance, be fully-paid and nonassessable.
(iii) The Corporation shall pay all taxes and other
governmental charges (other than any income or franchise
taxes) that may be imposed with respect to the issue or
delivery of shares of Common Stock upon conversion of Series A
Preferred as provided herein. The Corporation shall not be
required, however, to pay any tax or other charge imposed in
connection with any transfer involved in the issue of any
certificate for shares of Common Stock in any name other than
that of the registered holder of the shares of the Series A
Preferred surrendered in connection with the conversion
thereof, and in such case the Corporation shall not be
required to issue or deliver any stock certificate until such
tax or other charge has been paid, or it has been established
to the Corporation's satisfaction that no tax or other charge
is due.
SECTION 4. LIQUIDATION PREFERENCE.
(a) In the event of any liquidation, dissolution or winding up of the
Corporation (in connection with the bankruptcy or insolvency of the Corporation
or otherwise), whether voluntary or involuntary, before any payment or
distribution of the assets of the Corporation (whether capital or surplus) shall
be made to or set apart for the holders of shares of any Junior Securities, the
holders of the shares of Series A Preferred shall be entitled to receive an
amount equal to the Preference Amount, plus the amount of any accrued and unpaid
dividends on the Series A Preferred, multiplied by the number of shares of
Series A Preferred held by them. To the extent the available assets are
insufficient to fully satisfy such amounts, then the holders of the Series A
Preferred shall share ratably in such distribution in the proportion that the
number of each holder's Series A Preferred Shares bears to the total number of
shares of Series A Preferred outstanding. No further payment on account of any
such liquidation,
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<PAGE> 16
dissolution or winding up of the Corporation shall be paid to the holders of the
shares of Series A Preferred or the holders of any Parity Securities unless
there shall be paid at the same time to the holders of the shares of Series A
Preferred and the holders of any Parity Securities proportionate amounts
determined ratably in proportion to the full amounts to which the holders of all
outstanding shares of Series A Preferred and the holders of all such outstanding
Parity Securities are respectively entitled with respect to such distribution.
For purposes of this Section, neither a consolidation or merger of the
Corporation with one or more partnerships, corporations or other entities nor a
sale, lease, exchange or transfer of all or any substantial part of the
Corporation's assets for cash, securities or other property shall be deemed to
be a liquidation, dissolution or winding-up of the Corporation, whether
voluntary or involuntary.
(b) After the payment of all amounts owing to the holders of any Senior
Security, the Series A Preferred and any Parity Security, all stockholders shall
share ratably in the distribution of the remaining available assets of the
Corporation in the proportion that each holder's shares bears to the total
number of shares of capital stock of the Corporation outstanding.
(c) Written notice of any liquidation, dissolution or winding up of the
Corporation, stating the payment date or dates when and the place or places
where the amounts distributable in such circumstances shall be payable, shall be
given by first class mail, postage prepaid, not less than 15 days prior to any
payment date stated therein, to the holders of record of the shares of Series A
Preferred at their respective addresses as the same shall appear in the records
of the Corporation.
SECTION 5. DIVIDENDS. Holders of the Series A Preferred will be
entitled to receive, when, as and if declared by the Board of Directors, out of
funds legally available therefor, dividends payable at a rate per annum (the
"Dividend Rate") of 8% of the aggregate Preference Amount of the Series A
Preferred payable in additional shares of Series A Preferred having an aggregate
Preference Amount equal to the amount of such dividends due on any Dividend
Payment Date ("PIK Stock"); provided, however, that after the eighth Dividend
Payment Date, the dividends payable on any subsequent Dividend Payment Date on
each share of Series A Preferred shall be paid in cash. Dividends will be
cumulative and will accrue from the Effective Date and be payable quarterly in
arrears as provided in the immediately preceding sentence on each Dividend
Payment Date. Dividends, whether or not declared, will cumulate until declared
and paid, when declaration and payment may be for all or part of the
then-accumulated dividends. Each dividend shall be payable to Series A Preferred
holders of record as they appear on the stock books of the Corporation on each
Dividend Record Date. Accumulated and unpaid dividends payable in Series A
Preferred will accrue dividends from the relevant Dividend Payment Date and be
payable quarterly to the same extent as issued shares of Series A Preferred.
Dividends shall cease to accrue with respect to shares of the Series A Preferred
on any Redemption Date with respect to such shares of Series A Preferred
redeemed on any such date.
When dividends are not paid in full upon the Series A Preferred, all
dividends declared upon shares of the Series A Preferred shall be declared pro
rata. Unless all dividends required to be paid pursuant to the first sentence of
Section 5 shall have been declared and paid, no dividends (other than dividends
payable in Common Stock) shall be declared or paid or set apart for payment or
other distribution upon any Junior Securities, nor shall any Junior Securities
be redeemed, purchased or otherwise acquired by the Corporation for any
consideration (or any payment made to or available for a sinking fund for the
redemption of any shares of such stock) by the Corporation.
SECTION 6. OPTIONAL REDEMPTION BY THE CORPORATION. The outstanding
shares of Series A Preferred are subject to redemption in accordance with the
following provisions:
(a) Subject to the terms hereof, the Corporation may at its option, so
long as it has sufficient funds legally available therefor, elect to redeem, in
whole or in part, the outstanding shares of Series A Preferred at any time after
the third anniversary of the Original Issue Date.
(b) The redemption price per share for Series A Preferred redeemed on
any optional redemption date (the "Redemption Price") shall be $12.00. The
Redemption Price shall be paid in cash from any source of funds legally
available therefor.
(c) Not less than 30 nor more than 60 days prior to the date fixed for
any redemption of any shares of Series A Preferred, a notice specifying the time
(the "Redemption Date") and place of such redemption and the number of shares to
be redeemed shall be given by first class mail, postage prepaid, to the holders
of record of the
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<PAGE> 17
shares of Series A Preferred to be redeemed at their respective addresses as the
same shall appear on the books of the Corporation (but no failure to mail such
notice or any defect therein shall affect the validity of the proceedings for
redemption except as to the holder to whom the Corporation has failed to mail
such notice or except as to the holder whose notice was defective), calling upon
each such holder of record to surrender to the Corporation on the Redemption
Date at the place designated in such notice such holder's certificate or
certificates representing the then outstanding shares of Series A Preferred held
by such holder being redeemed by the Corporation. On or after the Redemption
Date, each holder of shares of Series A Preferred called for redemption shall
surrender such holder's certificate or certificates for such shares to the
Corporation at the place designated in the redemption notice and shall thereupon
be entitled to receive payment of the Redemption Price. From and after the
Redemption Date, unless there shall have been a default in payment of the
Redemption Price, all rights of the holders of Series A Preferred designated for
redemption (except the right to receive the Redemption Price without interest
upon surrender of their certificate or certificates) shall cease with respect to
such shares, and such shares shall not thereafter be transferred on the books of
the Corporation or be deemed to be outstanding for any purpose whatsoever.
SECTION 7. REACQUIRED SHARES. Any shares of Series A Preferred
repurchased, redeemed, converted or otherwise acquired by the Corporation shall
be retired and canceled promptly after the acquisition thereof. All such shares
shall upon their cancellation become authorized but unissued shares of Preferred
Stock, without designation as to series.
SECTION 8. VOTING RIGHTS.
(a) Except as otherwise required by law and as specified in this
Section, the holders of shares of Series A Preferred shall not have any right or
power to vote on or consent with respect to any matter or in any proceeding or
to be represented at any meeting of stockholders of the Corporation. On any
matters on which the holders of shares of Series A Preferred shall be entitled
to vote, they shall be entitled to one vote for each share held.
(b) So long as any shares of Series A Preferred remain outstanding, the
affirmative vote or consent of the holders of a majority of the shares of Series
A Preferred outstanding at the time, given in person or by proxy, either in
writing or at a meeting, shall be necessary to permit, effect or validate (i)
the authorization, creation or issuance, or any increase in the authorized or
issued amount, of any class or series of Senior Security or (ii) the amendment,
alteration or repeal of any of the provisions of the Certificate of
Incorporation, as amended, of the Corporation which would materially and
adversely affect any right, preference, privilege or voting power of shares of
Series A Preferred or of the holders thereof. The increase in the amount of
authorized Preferred Stock of the Corporation or the creation and issuance, or
increase in amount of authorized shares of other series of Parity Security or
Junior Security shall not be deemed to affect materially and adversely such
rights, preferences, privileges or voting power.
SECTION 9. CONVERSION RIGHTS. Holders of shares of Series A Preferred
shall have the right to convert, in whole or in part and without the payment of
any additional consideration by the holder, any or all of such shares into
Common Stock, as follows:
(a) At any time after the second anniversary of the Original Issue
Date, each share of Series A Preferred shall be convertible at the option of the
holder thereof into fully paid, non-assessable shares of Common Stock. The
number of shares of Common Stock deliverable upon conversion of each share of
Series A Preferred shall be determined by dividing the Preference Amount of such
share of Series A Preferred by the Conversion Price.
(b) In case at any time the Corporation shall (i) subdivide the
outstanding shares of Common Stock into a greater number of shares, (ii) combine
the outstanding shares of Common Stock into a smaller number of shares or (iii)
pay a dividend in Common Stock on its outstanding shares of Common Stock, then
the Conversion Price in effect immediately prior thereto shall be multiplied by
the fraction obtained:
by dividing
(X), which is the numerator equal to the total number of issued and
outstanding shares of Common Stock immediately prior to the
effectiveness of such action by the Corporation,
by
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<PAGE> 18
(Y), which is the denominator that equals the actual total number of
issued and outstanding shares of Common Stock immediately after such
effectiveness.
Such adjustment shall become effective immediately after the effective date of a
subdivision, combination or stock dividend. In the event of a consolidation or
merger of the Corporation with or into another corporation or entity as a result
of which a greater or lesser number of shares of common stock of the surviving
corporation or entity are issuable to holders of capital stock of the
Corporation in respect of the number of shares of its capital stock outstanding
immediately prior to such consolidation or merger, then the Conversion Price in
effect immediately prior to such consolidation or merger shall be adjusted in
the same manner as though there were a subdivision or combination of the
outstanding shares of capital stock of the Corporation. The Corporation shall
not effect any such consolidation or merger unless prior to or simultaneously
with the consummation thereof the successor (if other than the Corporation)
resulting from such consolidation or merger shall expressly assume, by written
instrument executed and delivered (and satisfactory in form) to the Series A
Preferred holders, (i) the obligation to deliver to such holders such stock as,
in accordance with the foregoing provisions, such holders may be entitled to
purchase and (ii) all other obligations of the Corporation hereunder.
(c) In the event that the Corporation proposes to take any action
specified in this Section 9 which requires any adjustment of the Conversion
Price, then and in each such case the Corporation shall at least 30 days prior
to any such event, and within five business days after it has knowledge of any
such pending transaction, provide to the Series A Preferred holders written
notice of the date on which the books of the Corporation shall close or a record
shall be taken for such dividend or for determining rights to vote in respect of
any such consolidation or merger. Such notice shall also specify, as applicable,
the date on which the holders of capital stock shall be entitled thereto or the
date on which the holders of capital stock shall be entitled to exchange their
stock for securities deliverable upon such consolidation or merger, as the case
may be. Such notice shall also state that the action in question or the record
date is subject to the effectiveness of a registration statement under the
Securities Act of 1933, as amended, or to a favorable vote of security holders,
if either is required. Furthermore, any notice shall state the Conversion Price
resulting from such adjustment and the increase or decrease, if any, in the
number of shares obtainable at such price upon exercise, setting forth in
reasonable detail the method of calculation and the facts upon which such
calculation is based.
(d) The conversion of any share of Series A Preferred may be effected
by the holder thereof by the surrender of the certificate or certificates
therefor, duly endorsed, at the principal offices of the Corporation or to such
agent or agents of the Corporation as may be designated by the Board of
Directors and by giving written notice to the Corporation that such holder
elects to convert the same.
(e) As promptly as practicable after the surrender of shares of Series
A Preferred for conversion, the Corporation shall (i) issue and deliver or cause
to be issued and delivered to the holder of such shares certificates
representing the number of fully paid and non-assessable shares of Common Stock
into which such shares of Series A Preferred have been converted in accordance
with the provisions of this Section and (ii) pay to the holder of such shares
all accrued and unpaid dividends (whether or not earned or declared) to the date
of such surrender. Subject to the following provisions of this Section, such
conversion shall be deemed to have been made as of the close of business on the
date on which the shares of Series A Preferred shall have been surrendered for
conversion in the manner herein provided, so that the rights of the holder of
the shares of Series A Preferred so surrendered shall cease at such time, and
the person or persons entitled to receive the shares of Common Stock upon
conversion thereof shall be treated for all purposes as having become the record
holder or holders of such shares of Common Stock at such time; provided,
however, that any such surrender on any date when the stock transfer books of
the Corporation are closed shall be deemed to have been made, and shall be
effective to terminate the rights of the holder or holders of the shares of
Series A Preferred so surrendered for conversion and to constitute the person or
persons entitled to receive such shares of Common Stock as the record holder or
holders thereof for all purposes, at the opening of business on the next
succeeding day on which such transfer books are open.
(f) The Corporation shall not be required to issue fractional shares of
stock upon the conversion of the Series A Preferred. As to any final fraction of
a share which the holder of one or more shares of Series A Preferred would
otherwise be entitled to receive upon conversion, the Corporation shall, in lieu
of issuing any fractional share, pay the holder otherwise entitled to such
fraction a sum in cash equal to the same fraction of the Conversion Price on the
day of conversion.
5
<PAGE> 19
(g) In case the Corporation shall be a party to any transaction
(including without limitation, a merger, consolidation, statutory share
exchange, sale of all or substantially all of the Corporation's assets or
recapitalization of the Common Stock), in each case as a result of which shares
of Common Stock shall be converted into the right to receive stock, securities
or other property (including cash or any combination thereof) (each of the
foregoing transactions being referred to as a "Fundamental Change Transaction"),
then the shares of Series A Preferred remaining outstanding will thereafter no
longer be subject to conversion into Common Stock pursuant to this Section, but
instead each share shall be convertible into the kind and amount of stock and
other securities and property receivable (including cash) upon the consummation
of such Fundamental Change Transaction by a holder of that number of shares of
Common Stock into which one share of Series A Preferred was convertible
immediately prior to such Fundamental Change Transaction (including an immediate
adjustment of the Conversion Price if by reason of or in connection with such
merger, consolidation, statutory share exchange, sale or recapitalization any
securities are issued or event occurs which would, under the terms hereof,
require an adjustment of the Conversion Price), assuming such holder of Series A
Preferred has failed to elect to have all or a part of such holder's shares
redeemed or otherwise acquired. The provisions of this paragraph shall similarly
apply to successive Fundamental Change Transactions.
SECTION 9. RANKING. For purposes of the distribution of assets upon
liquidation, dissolution or winding up of the Corporation, (i) the Junior
Securities shall rank junior to the Series A Preferred and (ii) the Parity
Securities shall rank on a parity with the Series A Preferred.
SECTION 10. RECORD HOLDERS. The Corporation may deem and treat the
record holder of any shares of Series A Preferred as the true and lawful owner
thereof for all purposes, and the Corporation shall not be affected by any
notice to the contrary.
SECTION 11. NOTICE. Except as may otherwise be provided by law or
provided for herein, all notices referred to herein shall be in writing, and all
notices hereunder shall be deemed to have been given upon receipt, in the case
of a notice of conversion given to the Corporation, or, in all other cases, upon
the earlier of receipt of such notice or three Business Days after the mailing
of such notices sent by Registered Mail (unless first-class mail shall be
specifically permitted for such notice under the terms hereof) with postage
prepaid, addressed: If to the Corporation, to its principal executive offices or
to any agent of the Corporation designated as permitted hereby; or if to a
holder of the Series A Preferred, to such holder at the address of such holder
of the Series A Preferred as listed in the stock record books of the
Corporation, or to such other address as the Corporation or holder, as the case
may be, shall have designated by notice similarly given.
SECTION 12. SUCCESSORS AND TRANSFEREES. The provisions applicable to
shares of Series A Preferred shall bind and inure to the benefit of and be
enforceable by the Corporation, the respective successors to the Corporation,
and by any record holder of shares of Series A Preferred.
RESOLVED FURTHER, that the appropriate officers of the
Corporation be, and they are hereby, authorized and directed from
time to time to execute such certificates, instruments or other
documents and do all such things as may be necessary or advisable
in their discretion in order to carry out the terms hereof,
including the filing with the Secretary of State for the State of
Delaware of a copy of the foregoing resolution executed by an
officer of the Corporation.
Dated: January 14, 2000
PETROGLYPH ENERGY, INC.
By: /s/ Robert C. Murdock
---------------------------------------
Name: Robert C. Murdock
Title: Chairman of the Board, President
and Chief Executive Officer
6
<PAGE> 20
APPENDIX I
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's consolidated financial
statements and related notes included in "Item 8. Consolidated Financial
Statements and Supplementary Data."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(in thousands, except per share amounts and operating data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil sales ........................................... $ 2,912 $ 3,735 $ 4,459 $ 3,217 $ 1,644
Natural gas sales ................................... 1,366 1,070 999 1,016 796
Other ............................................... 190 61 -- 36 45
-------- -------- -------- -------- --------
Total operating revenues ........................ 4,468 4,866 5,458 4,269 2,485
-------- -------- -------- -------- --------
Operating expenses:
Lease operating ..................................... 1,927 1,560 2,369 2,260 1,601
Production taxes .................................... 218 179 249 188 89
Exploration costs ................................... 193 -- 69 376 70
Depreciation, depletion and amortization ............ 1,866 1,852 2,806 2,302 1,977
Impairments ......................................... 4,848 -- -- 109 --
General and administrative .......................... 2,129 1,300 902 1,064 956
-------- -------- -------- -------- --------
Total operating expenses ........................ 11,181 4,891 6,395 6,299 4,693
-------- -------- -------- -------- --------
Operating loss .......................................... (6,713) (25) (937) (2,030) (2,208)
Other income (expenses):
Interest income (expense), net ...................... 407 114 40 (216) (93)
Gain (loss) on sales of property and
equipment, net .................................. 59 12 1,384 (138) 44
-------- -------- -------- -------- --------
Net income (loss) before income taxes ................... (6,247) 101 487 (2,384) (2,257)
Income tax benefit (expense) (1) ........................ 2,062 (2,514) (190) -- --
-------- -------- -------- -------- --------
Net income (loss) ....................................... $ (4,185) $ (2,413) $ 297 $ (2,384) $ (2,257)
======== ======== ======== ======== ========
Supplemental earnings (loss) per
common share (2) ........................................ $ (.77) $ (.73) $ .11 $ (.84) $ (.80)
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in):
Operating activities ................................ $ (1,467) $ 1,633 $ 4,129 $ 347 $ (67)
Investing activities ................................ (20,535) (15,514) 303 (9,580) (8,131)
Financing activities ................................ 7,331 28,982 (3,930) 10,049 8,119
OTHER FINANCIAL DATA:
Capital expenditures .................................... $ 20,623 $ 16,260 $ 8,665 $ 10,443 $ 8,277
Adjusted EBITDA (3) ..................................... 253 1,839 3,322 619 (117)
Operating cash flow (4) ................................. 601 1,896 2,024 608 (233)
BALANCE SHEET DATA:
Cash and cash equivalents ............................... $ 2,008 $ 16,679 $ 1,578 $ 1,075 $ 258
Working capital ......................................... 1,952 14,873 (541) 1,133 113
Total assets ............................................ 46,035 46,714 17,470 17,598 9,685
Total long-term debt .................................... 7,500 -- 52 3,900 1,800
Total stockholders' equity .............................. 35,312 39,498 12,695 12,207 6,592
</TABLE>
(1) Tax information for 1996 is shown as pro forma to reflect income tax
expense as if Partnership income were subject to federal income tax.
(2) Weighted average common shares outstanding used in the calculation of
earnings (loss) per common share for each of the five years ended December
31, 1998 were 5,458,333 for 1998, 3,326,826 for 1997 and 2,833,333 (pro
forma) shares for 1996, 1995 and 1994.
14
<PAGE> 21
(3) Adjusted EBITDA (as used herein) is calculated by adding interest, income
taxes, depreciation, depletion and amortization, impairments and
exploration costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. The Company did not
incur impairment expense for any period reported except for $4,848,000 for
the year ended December 31, 1998 and $109,000 for the year ended December
31, 1995. Exploration costs were $193,000, zero, $69,000, $376,000 and
$70,000 for each of the years ended December 31, 1998, 1997, 1996, 1995 and
1994, respectively. Adjusted EBITDA is presented not as a measure of
operating results, but rather as a measure of the Company's operating
performance and ability to service debt. Adjusted EBITDA is not intended to
represent cash flows for the period; nor has it been presented as an
alternative to net income (loss) or operating income (loss); nor as an
indicator of the Company's financial or operating performance. Management
believes that Adjusted EBITDA provides supplemental information about the
Company's ability to meet its future requirements for debt service, capital
expenditures and working capital. Management monitors trends in Adjusted
EBITDA, as well as the trends in revenues and net income (loss), to aid it
in managing its business. Adjusted EBITDA should not be considered in
isolation, as a substitute for measures of performance prepared in
accordance with generally accepted accounting principles or as being
comparable to other similarly titled measures of other companies, which are
not necessarily calculated in the same manner. (4) Operating cash flow is
defined as net income plus adjustments to net income to arrive at net cash
provided by operating activities before changes in working capital.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The following table sets forth certain operating data of the Company for
the periods presented:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
PRODUCTION DATA(1):
Oil (Bbls).......................................................... 261,817 251,631 262,910
Natural Gas (Mcf)................................................... 679,992 537,466 553,770
Total (BOE)..................................................... 375,149 341,209 355,205
AVERAGE SALES PRICE PER UNIT(2):
Oil (per Bbl)(3).................................................... $ 11.12 $ 14.84 $ 16.96
Natural Gas (per Mcf)............................................... 2.01 1.99 1.80
BOE................................................................. 11.40 14.08 15.36
COSTS PER BOE:
Lease operating expense............................................. $ 5.14 $ 4.57 $ 6.67
Production and property taxes....................................... 0.58 .52 0.70
General and administrative.......................................... 5.67 3.81 2.54
Depreciation, depletion and amortization............................ 4.97 5.43 7.90
Average finding costs(4)............................................ 0.85 3.00 2.86
</TABLE>
- --------------------
(1) The Company's 1997 oil and gas production volumes include the effect of the
sale of a 50% interest in its Antelope Creek properties in June 1996 and
the sale of certain non-strategic properties in late 1996 and early 1997.
(2) Before deduction of production taxes.
(3) Excluding the effects of crude oil hedging transactions and amortization of
deferred revenue, the weighted average sales price per Bbl of oil was
$9.65, $15.52 and $20.22 for the years ended December 31, 1998, 1997 and
1996, respectively.
(4) The calculation of average finding costs for the years ended December 31,
1997 and 1996 includes a change in future development costs of $2.7 million
and $16.5 million, respectively. Average finding cost per BOE excluding
these amounts were $2.37 and $.85 for the years ended December 31, 1997 and
1996, respectively. The calculation of average finding cost for the year
ended December 31, 1998 includes a reduction in future
15
<PAGE> 22
development costs of $13.3 million as a result of a decline in the
Company's proved undeveloped reserves due to low year-end oil prices. 1998
average finding cost excluding future development cost is not meaningful.
The Company uses the successful efforts method of accounting for its oil
and natural gas activities. Costs to acquire mineral interests in oil and
natural gas properties, to drill and equip exploratory wells that result in
proved reserves, and to drill and equip development wells are capitalized. Costs
to drill exploratory wells that do not result in proved reserves, geological,
geophysical and seismic costs, and costs of carrying and retaining properties
that do not contain proved reserves are expensed. Costs of significant
nonproducing properties, wells in the process of being drilled and development
projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined.
The Company's predecessor was classified as a partnership for federal
income tax purposes. Therefore, no income taxes were paid or provided for by the
Company prior to the Conversion. Future tax amounts, if any, will be dependent
upon several factors, including but not limited to the Company's results of
operations.
RESULTS OF OPERATIONS
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
OPERATING REVENUES
Oil revenues decreased by $823,000 (22%) to $2,912,000 for the year ended
December 31, 1998 as compared to $3,735,000 for 1997 primarily as a result of a
$3.72 (25%) decline in average oil sales prices from $14.84 per Bbl in 1997 to
$11.12 in 1998. The average oil sales price of $11.12 per Bbl includes the
effects of a crude oil hedge gain of $386,000. The Company's average oil sales
price for the year ended December 31, 1998, excluding the effects of the hedge
gain, was $9.65 per Bbl.
Natural gas revenues increased by $296,000 (28%) to $1,366,000 for the year
ended December 31, 1998 as compared to $1,070,000 for 1997 primarily as a result
of an increase in the gas sales volumes of 143,000 Mcf (27%). The increase in
gas sales volumes is attributable to successful drilling activities in Utah and
Texas during the year, offset by normal production declines on existing wells.
OPERATING EXPENSES
Lease operating expenses increased $367,000 (24%) to $1,927,000 for the
year ended December 31, 1998 as compared to $1,560,000 for the year ended
December 31, 1997. This increase is a result of an increase in the average
number of operated wells and facilities between 1997 and 1998, a 10% increase in
allowable overhead charges per well, and an increase in expensed remediation
charges from unsuccessful workovers on the Company's Texas properties. In
addition, the Company's lease operating expenses on a per BOE basis increased by
$0.57 (12%) to $5.14 per BOE during 1998 as compared to $4.57 per BOE for 1997
as a result of the overhead increases and remediation charges mentioned above.
Depreciation, depletion and amortization expense declined $0.46 (8%) on a
per BOE basis to $4.97 for the year ended December 31, 1998, as compared to
$5.43 for the year ended December 31, 1997. The decline is a result of
increasing reserves in proved developed categories between periods.
Exploration costs increased to $193,000 for the year ended December 31,
1998 from zero for the year ended December 31, 1997, as two exploratory wells
drilled during the year, one in the Raton Basin and one on the Company's Texas
acreage, were plugged and abandoned. This compares to 1997 when all of the
Company's exploratory drilling activities were successful and no geological and
geophysical work was performed.
General and administrative expenses increased by $829,000 (64%) to
$2,129,000 for the year ended December 31, 1998, as compared to $1,300,000 for
the year ended December 31, 1997. This increase was the result of an increase in
engineering, geological and administrative staff as the Company prepared for
increased development activity and increased accounting staff necessary to meet
the reporting requirements associated with being a public company. The
16
<PAGE> 23
increase was enhanced by severance and related items incurred in the fourth
quarter of 1998 as the Company implemented staff reductions brought on by
reduced drilling activity and low commodity prices.
OTHER INCOME (EXPENSES)
Interest income (expense) net, for the year ended December 31, 1998,
increased $293,000 to $407,000 as compared to $114,000 for the year ended
December 31, 1997 primarily as a result of increased interest earned on the
invested proceeds from the Offering.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
OPERATING REVENUES
Oil revenues decreased by 16% to $3,735,000 for the year ended December 31,
1997 as compared to $4,459,000 for 1996 primarily as a result of an 11,000 Bbl
decrease in the Company's oil production volume and a decline in average oil
sales prices from $16.96 per Bbl in 1996 to $14.84 in 1997. The decline in the
Company's oil production is due to the sale of a 50% interest in the Utah
properties in June 1996 and the sale of certain other non-strategic properties
between the third quarter of 1996 and the first quarter of 1997, partially
offset by increased production volume from the Company's remaining 50% interest
in the Utah properties as a result of the Company's aggressive drilling program
on its Utah properties beginning in the second half of 1996. The decline in
average oil sales price of $2.12 per Bbl was due to a reduction in demand for
the Company's production as a result of a temporary maintenance shutdown during
1996 and early 1997 of one of the refineries which is a primary user of the
Company's Utah production, a crude oil hedge loss of $132,000 and amortization
of deferred revenue of $46,000. The Company's average oil sales price for the
year ended December 31, 1997, excluding the effects of the hedge loss and
amortization of deferred revenue was $15.52 per Bbl.
Natural gas revenues increased by 7% to $1,070,000 for the year ended
December 31, 1997, as compared to $999,000 for 1996 primarily as a result of an
increase in the average natural gas sales price to $1.99 per Mcf during the year
ended December 31, 1997, as compared to $1.80 per Mcf for 1996. The increase in
natural gas prices was partially offset by a decline in natural gas production
of 16,000 Mcf primarily due to dispositions of certain non-strategic natural gas
properties during 1996, the sale of a 50% interest in the Utah properties in
June 1996 and the inception of the secondary oil recovery program on the
Company's Utah properties in mid-1996. These declines in natural gas production
volumes were offset by increased natural gas production volumes related to the
Company's remaining 50% interest in the Utah properties as a result of the
Company's aggressive drilling program on the properties beginning in the second
half of 1996.
OPERATING EXPENSES
Lease operating expenses decreased by 34% to $1,560,000 for the year ended
December 31, 1997, as compared to $2,369,000 for 1996 primarily as a result of
the sale of a 50% interest in the Company's Utah properties in June 1996 and the
sale of certain other non-strategic oil and natural gas properties between the
third quarter of 1996 and the first quarter of 1997, partially offset by an
increase in the number of producing wells in which the Company has an interest
due to the aggressive drilling program on the Company's Utah properties, which
began in the second half of 1996. In addition, the Company's lease operating
expenses on a per BOE basis declined by 31% to $4.57 per BOE during 1997 as
compared to $6.67 per BOE for 1996. This decline in lease operating expenses per
BOE is due to the benefits of improved economies of scale from increasing
production volumes from the Utah properties and the Company's continued focus on
reduction of operating costs through improved efficiencies. This decline was
partially offset by a significant increase in per BOE production costs of the
Company's non-Utah properties due to several workovers performed during 1997.
Depreciation, depletion and amortization expense decreased by 34% to
$1,852,000 for the year ended December 31, 1997, as compared to $2,806,000 for
1996 primarily as a result of a significant increase in proved reserves in 1997
as a result of the Company's aggressive drilling program which began in the
second half of 1996, the sale of the 50% interest in the Company's Utah
properties in June 1996 and the sale of certain other non-strategic oil and
natural gas properties in the third quarter of 1996 through the first quarter of
1997. These items were partially offset by increased production from the
Company's remaining interest in the Utah properties.
17
<PAGE> 24
Exploration costs declined to zero for the year ended December 31, 1997 from
$69,000 for 1996, as all of the Company's exploratory drilling activities were
successful during the period and no geological and geophysical work was
performed.
General and administrative expenses increased by 44% to $1,300,000 for the
year ended December 31, 1997, as compared to $902,000 for 1996. This increase
was the result of an increase in engineering, geological and administrative
staff necessary for the increased development activity and increased accounting
staff needed to meet the increased reporting requirements associated with being
a public company.
OTHER INCOME (EXPENSES)
Interest income (expense) net, for the year ended December 31, 1997,
increased to $114,000 as compared to $40,000 in 1996 primarily as a result of
interest earned on the proceeds from the Offering, partially offset by an
increase in average outstanding debt during 1997.
Gain on sales of property and equipment declined to $12,000 for the year
ended December 31, 1997, as compared to $1,384,000 for 1996 due to gains
recognized from the sale of a 50% interest in the Company's Utah properties in
June 1996 and sales of non-strategic oil and gas properties in the third quarter
of 1996.
INCOME TAX EXPENSE
Income tax expense increased for the year ended December 31, 1997 to
$2,514,000 as compared to the pro forma amount of $190,000 for the same period
in 1996. This increase is due to the impact of a one-time, non-cash charge
associated with the adoption of SFAS No. 109, "Accounting for Income Taxes."
SFAS No. 109 required that the net deferred tax liabilities of the Company on
the date of the Conversion be recognized as a component of income tax expense.
The Company recognized $2,475,000 in net deferred tax liabilities and income tax
expense on the date of the Conversion.
LIQUIDITY AND CAPITAL RESOURCES
Capital Expenditures
The Company requires capital primarily for the exploration, development and
acquisition of oil and natural gas properties, the repayment of indebtedness and
general working capital purposes.
The following table sets forth costs incurred by the Company in its
exploration, development and acquisition activities during the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties ............. $ 7,141,142 $ 1,721,636 $ 490,487
Proved properties ............... 42,533 147,387 --
Development costs ...................... 10,123,616 10,003,468 6,983,715
Exploration costs ...................... 192,526 -- --
Improved recovery costs ................ -- 895,317 327,027
----------- ----------- -----------
Total .................................. $17,499,817 $12,767,808 $ 7,801,229
=========== =========== ===========
</TABLE>
Due to continued low oil prices, in the second quarter of 1998, the Company
shifted its focus from developing its Uinta Basin oil reserves to drilling and
exploiting its Raton Basin methane gas properties. The Company's 1999 waterflood
development plans in the Uinta Basin are limited by low oil prices and the
resulting cash flow constraints to maximizing injected water volumes through a
series of injector well conversions. The Company does not anticipate drilling
new producing wells in the Uinta Basin in 1999, but rather intends to convert up
to 17 gross (8.5 net) wells at a projected cost of up to $1.5 million, in order
to enhance injected water rates and reduce the time required to repressurize the
reservoir
18
<PAGE> 25
on a field-wide basis. Additionally, the Company plans to aggressively withdraw
water from 17 pilot coalbed methane wells in the Raton Basin. If the dewatering
process is successful in reducing water levels and pressures within the
reservoir to the point where commercial quantities of gas are produced from
several wells within the pilot area, the Company intends to drill up to 10
additional wells in 1999 at an estimated cost of up to $2.5 million. Finally, in
cooperation with an industry partner, the Company plans to drill at least four
gross (3 net) wells in Victoria and DeWitt Counties in South Texas.
The funding of additional capital expenditures beyond the first quarter of
1999 will be dependent upon the Company's ability to realize proceeds from
future asset sales and increased operating cash flow, whether as result of
successful operations in the Raton Basin, improvements in prevailing commodity
prices or otherwise. While the Company anticipates receiving funds from these
sources during 1999, to the extent such funds are not available in the amounts
or at the times needed, additional 1999 capital expenditures will likely be
curtailed and the Company may be required to take further measures to reduce the
size and scope of its business.
Cash Flow and Working Capital
Cash used in operating activities was $1,467,000 for the year ended
December 31, 1998. The Company used cash on hand, proceeds from sales of
property and equipment of $88,000, draws on its revolving line of credit of
$7,500,000 and the remaining Offering proceeds to finance $20,623,000 of capital
spending to drill 40 and complete 36.5 net wells, convert 15 gross (7.5 net)
wells to injector status, acquire additional undeveloped acreage and build a gas
gathering and water distribution system in the Raton Basin.
Cash provided by operating activities was $1,633,000 for the year ended
December 31, 1997. The Company used cash on hand, proceeds from sales of
property and equipment of $746,000, draws on its revolving line of credit of
$10,000,000 and a portion of the Offering proceeds to finance $16,260,000 of
capital spending to drill and complete 29 net wells, acquire the Raton Basin
acreage and pipeline and complete the water distribution system in the Company's
Antelope Creek Field. Additionally, the Company incurred $1,485,000 in
organization and financing costs associated with the Offering and renewing the
Credit Agreement. During the fourth quarter of 1997, the Company completed its
initial public offering of 2,625,000 shares of common stock at $12.50 per share,
including 125,000 shares of the underwriters' over-allotment option, resulting
in net proceeds to the Company of $30,516,000. Approximately $10,000,000 of the
net proceeds were used to eliminate all outstanding amounts under the Credit
Agreement. As a result of this activity, the Company's working capital increased
from a deficit of ($541,000) to a positive of $14,872,000. The balance of the
proceeds was utilized to develop production and reserves in the Company's core
Uinta Basin and Raton Basin development properties and for other working capital
needs.
The Company believes that cash on hand, proceeds from future asset sales,
revenues and availability under the Credit Agreement, if any, will be adequate
to support its budgeted working capital and capital expenditure requirements for
at least the next 12 months. The Company anticipates that proceeds from sales of
assets will provide additional capital to fund its debt reduction plans and
position the Company to better take advantage of acquisition opportunities and
fund its discretionary capital budget. The Company believes that after 1999 it
will require a combination of additional financing and cash flow from operations
to implement its future development plans. The Company currently does not have
any arrangements with respect to, or sources of, additional financing other than
the Credit Agreement, and there can be no assurance that any additional
financing will be available to the Company on acceptable terms, if at all. In
the event sufficient capital is not available, the Company may be unable to
develop its Uinta Basin and Raton Basin properties in accordance with its
planned schedule.
Financing
In September 1997, the Company entered into the Amended and Restated Loan
Agreement with the Chase Manhattan Bank ("Chase"), (as amended, the "Credit
Agreement"). The Credit Agreement included a $20.0 million combination credit
facility with a two-year revolving credit facility and an original borrowing
base of $7.5 million to be redetermined semi-annually ("Tranche A"), which was
set to expire on September 15, 1999, at which time all balances outstanding
under Tranche A would have converted to a term loan expiring on September 15,
2002. Additionally, the Credit Agreement contained a separate revolving facility
of $2.5 million ("Tranche B"), which was set to expire on March 15, 1999. The
Company utilized a portion of the proceeds from the Offering to eliminate all
outstanding amounts
19
<PAGE> 26
under the Credit Agreement in October, 1997. With the repayment of the Tranche B
indebtedness, the $2.5 million under that portion of the Credit Agreement was no
longer available to the Company. Effective September 30, 1998, the Company
amended the Credit Agreement with Chase, (the "Amendment"). The Amendment
increased the credit facility to $50.0 million with a two-year revolving credit
facility and an original borrowing base of $15.0 million to be redetermined
quarterly beginning December 31, 1998. The next scheduled borrowing base
redetermination date is March 31, 1999. Because of historically low crude oil
prices, management expects the borrowing base amount available under the Credit
Agreement will decline from the current level of $15.0 million. Although the
borrowing base amount ultimately determined by Chase is outside of the Company's
control, management believes the borrowing base amount will not be reduced below
the current outstanding balance of $8.5 million. The revolving credit facility
expires on September 30, 2000, at which time all outstanding balances will
convert to a term loan expiring on September 30, 2003. Interest on outstanding
borrowings is calculated, at the Company's option, at either Chase's prime rate
or the London Interbank Offer Rate plus a margin determined by the amount
outstanding under the facility.
INFLATION AND CHANGES IN PRICES
The Company's revenue and the value of its oil and natural gas properties
have been, and will continue to be, affected by levels of and changes in oil and
natural gas prices. The Company's ability to obtain capital through borrowings
and other means is also substantially dependent on prevailing and anticipated
oil and natural gas prices. Oil and natural gas prices are subject to
significant seasonal and other fluctuations that are beyond the Company's
ability to control or predict. In an attempt to manage this price risk, the
Company periodically engages in hedging transactions.
Currently, annual inflation in terms of the decrease in the general
purchasing power of the dollar is running much below the general annual
inflation rates experienced in the past. While the Company, like other
companies, continues to be affected by fluctuations in the purchasing power of
the dollar, such effect is not currently considered significant.
HEDGING TRANSACTIONS
The Company has historically entered into hedging contracts of various
types in an attempt to manage price risk with regard to a portion of the
Company's crude and natural gas production. While use of these hedging
arrangements limit the downside risk of price declines, such arrangements may
also limit the benefits which may be derived from price increases.
The Company has used various financial instruments such as collars, swaps
and futures contracts in an attempt to manage its price risk. Monthly
settlements on these financial instruments are typically based on differences
between the fixed prices specified in the instruments and the settlement price
of certain future contracts quoted on the NYMEX or certain other indices. The
instruments used by the Company for oil hedges have not contained a contractual
obligation which requires or allows the future physical delivery of the hedged
products.
The Company had two open hedge contracts at December 31, 1998, which are
crude oil collars on 159,000 Bbls of oil during 1999 and 72,000 Bbls of oil
during 2000, with floor prices of $17.00 and $14.00 per Bbl, respectively, and
ceiling prices of $22.00 and $16.00 per Bbl, respectively, indexed to the NYMEX
light crude future settlement price. See Note 8 to the Notes to Consolidated
Financial Statements. During March 1999, the Company liquidated the hedge
contract covering 72,000 Bbls in the year 2000 for approximately $16,000.
YEAR 2000 ISSUES
The Company is aware of the date sensitivity issues associated with the
programming code in many existing computer systems and devices with embedded
technology. The "Year 2000" problem concerns the inability of information and
technology-based operating systems to properly recognize and process
date-sensitive information beyond December 31, 1999. The risk is that computer
systems will not properly recognize "00" in date sensitive information when the
year changes to 2000, which could cause system failures or miscalculations,
resulting in the potential disruption of business.
The management of the Company believes it is appropriately addressing the
Company's business and financial risk associated with the Year 2000 issue. In
response to the potential impact of the Year 2000 issue on the Company's
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business and operations, the Company has formed a Year 2000 Team (the "Team"),
consisting of members of senior management and the Information Systems Manager.
The Team is developing a program around the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and governmental
entities
The information technology and systems of the Company are believed to be
Year 2000 compliant. Activity in this area included installing and testing
software upgrades and service releases supplied by vendors and testing the
processing ability of hardware and computer equipment with embedded technology.
Most of these upgrades were system replacements conducted in 1996 and 1997 to
improve business efficiencies and functionality and were not undertaken solely
to address Year 2000 issues. As such, management believes the Year 2000 issues
with respect to the Company's information technology and systems will not have a
significant potential effect on the Company's financial position or operations.
The process controls and embedded technology area is in the assessment
phase with approximately 70% of the evaluation process in the remediation and
verification phases. Field level processors, meters and equipment utilized by
the Company are not expected to contain embedded technology such as
microprocessors. However, the Company continues to conduct internal evaluations
and hold discussions with suppliers to ensure appropriate measures are taken to
minimize the impact to operations caused by any unidentified company or third
party Year 2000 issues. The Company also relies on non-information technology
systems such as telephones, facsimile machines, security systems and other
equipment which may have embedded technology such as micro-processors, which may
or may not be Year 2000 compliant. Management believes any such disruption is
not likely to have a significant effect on the Company's financial position or
operations. Management anticipates a complete evaluation of this area by the end
of the second quarter 1999.
The third-party suppliers, vendors, partners, customers and governmental
entities area is currently in the assessment phase with approximately 50% in the
remediation and verification phase. Formal communications have been initiated
with vendors, suppliers, customers and others with whom the Company has
significant business relationships. The Company continues to evaluate responses
and make additional inquiries as needed. Since the Company is in the process of
collecting this information from third parties, management cannot currently
determine whether third party compliance issues will materially affect its
operations. However, the Company is not currently aware of any third party
issues that would cause a significant business disruption. Management
anticipates a complete evaluation of this area to conclude by the end of the
second quarter 1999.
The total cost of the Company's Year 2000 program is not expected to be
material to the Company's financial position. Not including the cost of
replacing its information systems between 1996 and 1997, the Company anticipates
spending a total of $75,000 during the remainder of 1999 for Year 2000 related
modifications and testing. Expenditures during 1998 for computers and peripheral
hardware and software and software support were approximately $160,000. These
expenditures were made in the normal course of business and not necessarily for
the purpose of resolving Year 2000 problems.
The company is developing contingency plans in the unlikely event that
portions of its Year 2000 program are inadequate. The Company believes that the
most likely worst case Year 2000 scenarios are as follows: (i) unanticipated
Year 2000 induced failures in information systems could cause a reliance on
manual contingency procedures and significantly reduce efficiencies in the
performance of certain normal business activities; (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
considered to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company. The Company's contingency plans should be completed by
the end of the third quarter 1999.
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CAUTIONARY STATEMENTS FOR PURPOSE OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
Petroglyph or its representatives may make forward looking statements, oral
or written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells the Company anticipates drilling in specified periods and the Company's
financial position, business strategy and other plans and objectives for future
operations. Although the Company believes that the expectations reflected in
these forward looking statements are reasonable, there can be no assurance that
the actual results or developments anticipated by the Company will be realized
or, even if substantially realized, that they will have the expected effects on
its business or operations. Among the factors that could cause actual results to
differ materially from the Company's expectations are risks inherent in drilling
and other development activities, the timing and event of changes in commodity
prices, unforeseen engineering and mechanical or technological difficulties in
drilling wells and implementing enhanced oil recovery programs, the
availability, proximity and capacity of refineries, pipelines and processing
facilities, shortages or delays in the delivery of equipment and services, land
issues, federal and state regulatory developments and other factors set forth
among the risk factors noted below or in the description of the Company's
business in Item 1 of this report. All subsequent oral and written forward
looking statements attributable to the Company or persons acting on its behalf
are expressly qualified in their entirety by these factors. The Company assumes
no obligation to update any of these statements.
VOLATILITY OF OIL AND NATURAL GAS PRICES. The Company's revenues, operating
results, profitability and future growth and the carrying value of its oil and
natural gas properties are substantially dependent upon the prices received for
the Company's oil and natural gas. Historically, the markets for oil and natural
gas have been volatile and such volatility may continue or recur in the future.
Various factors beyond the control of the Company will affect prices of oil and
natural gas, including the worldwide and domestic supplies of oil and natural
gas, the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls, political
instability or armed conflict in oil or natural gas producing regions, the price
and level of foreign imports, the level of consumer demand, the price,
availability and acceptance of alternative fuels, the availability of pipeline
capacity, weather conditions, domestic and foreign governmental regulations and
taxes and the overall economic environment.
Any significant decline in the price of oil or natural gas would adversely
affect the Company's revenues, operating income (loss) and cash flow and could
require an impairment in the carrying value of the Company's oil and natural gas
properties.
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES. There
are numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and their values, including many factors beyond the
Company's control. Estimates of proved undeveloped reserves and reserves
recoverable through enhanced oil recovery techniques, which comprise a
significant portion of the Company's reserves, are by their nature uncertain.
The reserve information set forth in this report represents estimates only.
Although the Company believes such estimates to be reasonable, reserve estimates
are imprecise and should be expected to change as additional information becomes
available.
Estimates of oil and natural gas reserves, by necessity, are projections
based on engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that are difficult to measure. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment. In particular, given the early stage of the
Company's development programs, the ultimate effect of such programs is
difficult to ascertain. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
improved recovery techniques such as the enhanced oil recovery techniques
utilized by the Company, the assumed effects of regulations by governmental and
tribal agencies and assumptions concerning future oil and natural gas prices,
future operating costs, severance and excise taxes, development costs and
workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties,
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classifications of such reserves based on risk of recovery and estimates of the
future net cash flows expected therefrom may vary substantially. Any significant
variance in the assumptions could materially affect the estimated quantity and
value of the reserves. Actual production, revenues and expenditures with respect
to the Company's reserves will likely vary from estimates, and such variances
may be material.
The PV-10 referred to in this report should not be construed as the current
market value of the estimated oil and natural gas reserves attributable to the
Company's properties. In accordance with applicable requirements, the estimated
discounted future net cash flows from proved reserves are based on prices and
costs as of the date of the estimate, whereas actual future prices and costs may
be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply
and demand for oil and natural gas, refinery capacity, curtailments or increases
in consumption by natural gas purchasers and changes in governmental regulations
or taxation. The timing of actual future net cash flows from proved reserves,
and thus their actual present value, will be affected by the timing of both the
production and the incurrence of expenses in connection with development and
production of oil and natural gas properties. In addition, the 10% discount
factor, which is required to be used to calculate discounted future net cash
flows for reporting purposes, is not necessarily the most appropriate discount
factor based on interest rates in effect from time to time and risks associated
with the Company or the oil and natural gas industry in general.
LIMITED OPERATING HISTORY. The Company, which began operations in April
1993, has a limited operating history upon which the Company's stockholders may
base their evaluation of the Company's performance. As a result of its brief
operating history, expanded drilling program and change in the Company's mix of
properties during such period as a result of its acquisition and disposition of
properties, the operating results from the Company's historical periods may not
be indicative of future results. There can be no assurance that the Company will
continue to experience growth in, or maintain its current level of, revenues,
oil and natural gas reserves or production.
HISTORY OF OPERATING LOSSES AND NET LOSSES. The Company has experienced
operating losses in each year since its inception in 1993, including an
operating loss of approximately $1,865,000 excluding the effect of a $4.8
million impairment in 1998. Excluding the effect of the $1.3 million gain on the
sale of the 50% interest in Antelope Creek in 1996, the Company also has
experienced net losses in each year since its inception. Although the Company
expects its results of operations to improve as it develops its Uinta Basin and
Raton Basin assets, there is no assurance that the Company will achieve, or be
able to sustain, profitability.
EARLY STAGES OF DEVELOPMENT ACTIVITIES. The Company's development plan
includes (i) the drilling of development and exploratory wells in the Uinta
Basin when oil prices improve to reasonable levels, together with injection well
conversions that are intended to repressurize producing reservoirs in the Lower
Green River formation, (ii) subject to observing increasing commercial gas
production from several of the 17 pilot wells, the drilling of additional wells
in connection with the development of a coalbed methane project in the Raton
Basin and (iii) the use of 3-D seismic technology to exploit its properties in
South Texas. The success of these projects will be materially dependent on
whether the Company's development and exploratory wells can be drilled and
completed as commercially productive wells, whether the enhanced oil recovery
techniques can successfully repressurize reservoirs and increase the rate of
production and ultimate recovery of oil and natural gas from the Company's
acreage in the Uinta Basin and whether the Company can successfully implement
its planned coalbed methane project on its acreage in the Raton Basin. Although
the Company believes the geologic characteristics of its project areas reduce
the probability of drilling nonproductive wells, there can be no assurance that
the Company will drill productive wells. If the Company drills a significant
number of nonproductive wells, the Company's business, financial condition and
results of operations would be materially adversely affected. While the
Company's pilot enhanced oil recovery projects in the Uinta Basin have indicated
that rates of oil production can be increased, the repressurization takes place
over a period of approximately two years and depends heavily on the amount and
rates of injected water, with full response occurring after approximately five
years; therefore, the ultimate effect of the enhanced oil recovery operations
will not be known for several years. Ultimate recoveries of oil and natural gas
from the enhanced oil recovery programs may also vary at different locations
within the Company's Uinta Basin properties. Accordingly, due to the early stage
of development, the Company is unable to predict whether its development
activities in the Uinta Basin will meet its expectations. In the event the
Company's enhanced oil recovery program does not effectively increase rates of
production or ultimate recovery of oil reserves, the Company's business,
financial condition and results of operation will likely be materially adversely
affected.
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RISKS ASSOCIATED WITH OPERATING IN THE UINTA BASIN
Concentration in Uinta Basin. The Company's properties in the Greater
Monument Butte Region of the Uinta Basin constitute the majority of the
Company's existing inventory of producing properties and drilling locations.
Approximately 53% of the Company's 1998 capital expenditures of approximately
$20.6 million was dedicated to developing the Company's enhanced oil recovery
projects in this area. There can be no assurance that the Company's operations
in the Uinta Basin will yield positive economic returns. Failure of the
Company's Uinta Basin properties to yield significant quantities of economically
attractive reserves and production would have a material adverse impact on the
Company's financial condition and results of operations.
Limited Refining Capacity for Uinta Basin Black Wax. The marketability of
the Company's oil production depends in part upon the availability, proximity
and capacity of refineries, pipelines and processing facilities. The crude oil
produced in the Uinta Basin is known as "black wax" or "yellow wax" and has a
higher paraffin content than crude oil found in most other major North American
basins. Currently, the most economic markets for the Company's black wax
production are five refineries in Salt Lake City that have limited facilities to
refine efficiently this type of crude oil. Because these refineries have limited
capacity, any significant increase in Uinta Basin "black wax" production or
temporary or permanent refinery shutdowns due to maintenance, retrofitting,
repairs, conversions to or from "black wax" production or otherwise could create
an over supply of "black wax" in the market, causing prices for Uinta Basin oil
to decrease. Since July 1996, the posted prices for Uinta Basin oil production
have been lower than major national indexes for crude oil. The Company believes
these differences are attributable to one or more market factors, including
refinery capacity constraints caused by the increase in supply of Uinta Basin
"black wax" production resulting from the recent drilling activity or the
reaction to the availability of additional non-Uinta Basin crude oil production
associated with a new pipeline. There can be no assurance that prices will
return to historical levels or that other price declines related to supply
imbalances will not occur in the future. To the extent crude oil prices decline
further or the Company is unable to market efficiently its oil production, the
Company's business, financial condition and results of operations could be
materially adversely affected.
Marketability of Natural Gas Production. The Company's Uinta Basin
properties currently produce natural gas in association with the production of
crude oil. The produced natural gas is gathered into the Company's natural gas
pipeline gathering system and compressed into an interstate natural gas
pipeline, at which point the produced natural gas is sold to marketers or end
users. Because current state and Ute tribal regulations prohibit the flaring or
venting of natural gas produced in the Uinta Basin, in the event the Company is
unable to market its natural gas production due to pipeline capacity constraints
or curtailments, the Company may be forced to shut in or curtail its oil and
natural gas production from any affected wells or install the necessary
facilities to reinject the natural gas into existing wells. Federal and state
regulation of oil and natural gas production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions all could
adversely affect the Company's ability to produce and market its natural gas.
Any dramatic change in any of these market factors or curtailment of oil and
natural gas production due to the Company's inability to vent or flare natural
gas could have a material adverse effect on the Company.
Availability of Water for Enhanced Oil Recovery Program. The Company's
enhanced oil recovery program involves the injection of water into wells to
pressurize reservoirs and, therefore, requires substantial quantities of water.
The Company intends to satisfy its requirements from one or more of three
sources: water produced from water wells, water purchased from local water
districts and water produced in association with oil production. The Company
currently has drilled water wells only in the Antelope Creek field, and there
can be no assurance that these water wells will continue to produce quantities
sufficient to support the Company's enhanced oil recovery program, that the
Company will be able to obtain the necessary approvals to drill additional water
wells or that successful water wells can be drilled in its other Uinta Basin
development areas. The Company has a contract with East Duchesne Water District
to purchase up to 10,000 barrels of water per day through September 30, 2004.
After the initial term, this contract automatically renews each year for one
additional year; however, either party may terminate the agreement with twelve
months prior notice. In the event of a water shortage, the East Duchesne Water
District contract provides that preferences will be given to residential
customers and other water customers having a higher use priority than the
Company. In addition, the Company has not yet secured a water source for full
development of its Natural Buttes Extension properties. There can be no
assurance that water shortages will not occur or that the Company will be able
to renew or enter into new water supply agreements on commercially reasonable
terms or at all. To the extent the Company is required to pay additional amounts
for its supply of water, the Company's financial condition and results of
operations may be adversely affected.
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While the Company believes that there will be sufficient volumes of water
available to support its improved oil recovery program and has taken certain
actions to ensure an adequate water supply will be available, in the event the
Company is unable to obtain sufficient quantities of water, the Company's
enhanced oil recovery program and business would be materially adversely
affected.
RISKS ASSOCIATED WITH PLANNED OPERATIONS IN THE RATON BASIN
Coalbed Methane Production. During the last ten years, new technology has
lowered the cost of coalbed methane production, making such development
commercially viable in areas where production was previously thought to be
uneconomic. While the Company believes that these new technologies will be
applicable to its acreage in the Raton Basin, the Company has recently begun its
development program. There can be no assurance that this program will discover
natural gas and, if natural gas is discovered, that the Company will be
successful in completing commercially productive wells.
Water Disposal. The Company believes that the future water production from
the Raton Basin coal seams will be low in dissolved solids, allowing the
Company, operating under permits which the Company believes will be issued by
the State of Colorado, to discharge the water into streambeds or stockponds.
However, if nonpotable water is discovered, it may be necessary to install and
operate evaporators or to drill disposal wells to reinject the produced water
back into the underground rock formations adjacent to the coal seams or to lower
sandstone horizons. In the event the Company is unable to obtain permits from
the State of Colorado, if nonpotable water is discovered or if applicable future
laws or regulations require water to be disposed of in an alternative manner,
the costs to dispose of produced water will increase, which increase could have
a material adverse effect on the Company's operations in this area.
SUBSTANTIAL CAPITAL REQUIREMENTS. The Company's development plans will
require it to make substantial capital expenditures in connection with the
exploration, development and exploitation of its oil and natural gas properties.
The Company's enhanced oil recovery project and pilot coalbed methane project
require substantial initial capital expenditures. Historically, the Company has
funded its capital expenditures through a combination of internally generated
funds from sales of production or properties, equity contributions, long-term
debt financing and short-term financing arrangements. The Company believes that
cash on hand, proceeds from future asset sales, revenues and availability under
the Credit Agreement, if any, will be sufficient to meet its estimated capital
expenditure requirements for 1999. The Company anticipates that proceeds from
sales of assets will provide additional capital to fund its debt reduction plans
and position the Company to better take advantage of acquisition opportunities
and fund its discretionary capital budget. The Company believes that after 1999
it will require a combination of additional financing, proceeds from asset sales
and cash flow from operations to implement its future development plans. The
Company currently does not have any arrangements with respect to, or sources of,
additional financing other than the Credit Agreement, and there can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all. Future cash flows and the availability of financing
will be subject to a number of variables, such as the level of production from
existing wells, prices of oil and natural gas, the Company's success in locating
and producing new reserves and the success of the enhanced recovery program in
the Uinta Basin and the coalbed methane project in the Raton Basin. To the
extent that future financing requirements are satisfied through the issuance of
equity securities, the Company's existing stockholders may experience dilution
that could be substantial. The incurrence of debt financing could result in a
substantial portion of the Company's operating cash flow being dedicated to the
payment of principal and interest on such indebtedness, could render the Company
more vulnerable to competitive pressures and economic downturns and could impose
restrictions on the Company's operations. If revenue were to decrease as a
result of lower oil and natural gas prices, decreased production or otherwise,
and the Company had no availability under the Credit Agreement or any other
credit facility, the Company could have a reduced ability to execute its current
development plans, replace its reserves or to maintain production levels, which
could result in decreased production and revenue over time.
COMPLIANCE WITH GOVERNMENTAL AND TRIBAL REGULATIONS. Oil and natural gas
operations are subject to extensive federal, state and local laws and
regulations relating to the exploration for, and the development, production and
transportation of, oil and natural gas, as well as safety matters, which may be
changed from time to time in response to economic or political conditions. In
addition, approximately 33% of the Company's acreage is located on Ute tribal
land and is leased by the Company from the Ute Indian Tribe and the Ute
Distribution Corporation. Because the Ute tribal authorities have certain rule
making authority and jurisdiction, such leases may be subject to a greater
degree of
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regulatory uncertainty than properties subject to only state and federal
regulations. Although the Company has not experienced any material difficulties
with its Ute tribal leases or in complying with Ute tribal laws or customs,
there can be no assurance that material difficulties will not be encountered in
the future. Matters subject to regulation by federal, state, local and Ute
tribal authorities include permits for drilling operations, road and pipeline
construction, reports concerning operations, the spacing of wells, unitization
and pooling of properties, taxation and environmental protection. Prior to
drilling any wells in the Uinta Basin, applicable federal and Ute tribal
requirements and the terms of its development agreements will require the
Company to have prepared by third parties and submitted for approval an
environmental and archaeological assessment for each area to be developed prior
to drilling any wells in such areas. Although the Company has not experienced
any material delays that have affected its development plans, there can be no
assurance that delays will not be encountered in the preparation or approval of
such assessments, or that the results of such assessments will not require the
Company to alter its development plans. Any delays in obtaining approvals or
material alterations to the Company's development plans could have a material
adverse effect on the Company's operations. From time to time, regulatory
agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and natural gas wells below actual
production capacity in order to conserve supplies of oil and natural gas.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation, and the
Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. Significant expenditures may be
required to comply with governmental and Ute tribal laws and regulations and may
have a material adverse effect on the Company's financial condition and results
of operations.
COMPLIANCE WITH ENVIRONMENTAL REGULATIONS. The Company's operations are
subject to complex and constantly changing environmental laws and regulations
adopted by federal, state and local governmental authorities. The implementation
of new, or the modification of existing, laws or regulations could have a
material adverse effect on the Company. The discharge of oil, natural gas or
potential pollutants into the air, soil or water may give rise to significant
liabilities on the part of the Company to the government and third parties and
may require the Company to incur substantial costs of remediation. Moreover, the
Company has agreed to indemnify sellers of properties purchased by the Company
against certain liabilities for environmental claims associated with such
properties. No assurance can be given that existing environmental laws or
regulations, as currently interpreted or reinterpreted in the future, or future
laws or regulations will not materially adversely affect the Company's results
of operations and financial condition or that material indemnity claims will not
arise against the Company with respect to properties acquired by the Company.
RESERVE REPLACEMENT RISK. The Company's future success depends upon its
ability to find, develop or acquire additional oil and natural gas reserves that
are economically recoverable. The proved reserves of the Company will generally
decline as reserves are depleted, except to the extent that the Company conducts
successful exploration or development activities, enhanced oil recovery
activities or acquires properties containing proved reserves. Approximately 18%
of the Company's total proved reserves at December 31, 1998 were undeveloped and
an additional 5.2 MMBOE (36%) previously included in proved categories were
determined to be marginally economical under year-end prices and were not
included in proved reserves. In order to increase reserves and production, the
Company must continue its development and exploitation drilling programs or
undertake other replacement activities. The Company's current development plan
includes increasing its reserve base through continued drilling, development and
exploitation of its existing properties. There can be no assurance, however,
that the Company's planned development and exploitation projects will result in
significant additional reserves or that the Company will have continuing success
drilling productive wells at anticipated finding and development costs.
In addition to the development of its existing proved reserves, the Company
expects that its inventory of unproved drilling locations will be the primary
source of new reserves, production and cash flow over the next few years. The
Company's properties in the Uinta Basin constitute the majority of the Company's
existing inventory. There can be no assurance that the Company's activities in
the Uinta Basin will yield economic returns. The failure of the Uinta Basin to
yield significant quantities of economically recoverable reserves could have a
material adverse impact on the Company's future financial condition and results
of operations and could result in a write-off of a significant portion of its
investment in the Uinta Basin.
DEPENDANCE ON KEY PERSONNEL. The Company's success has been and will
continue to be highly dependent on Robert C. Murdock, its Chairman of the Board,
President and Chief Executive Officer, Robert A. Christensen, its Executive Vice
President and Chief Technical Officer, Sidney Kennard Smith, its Executive Vice
President and Chief
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Operating Officer, Tim A. Lucas, its Vice President and Chief Financial Officer,
and a limited number of other senior management and technical personnel. Loss of
the services of Mr. Murdock, Mr. Christensen, Mr. Smith, Mr. Lucas or any of
those other individuals could have a material adverse effect on the Company's
operations. The Company's failure to retain its key personnel or hire additional
personnel could have a material adverse effect on the Company.
ACQUISITION RISKS. The Company has grown primarily through the acquisition
and development of its oil and natural gas properties. Although the Company
expects to concentrate on such activities in the future, the Company expects
that it may evaluate and pursue from time to time acquisitions in the Uinta
Basin, the Raton Basin and in other areas that provide attractive investment
opportunities for the addition of production and reserves and that meet the
Company's selection criteria. The successful acquisition of producing properties
and undeveloped acreage requires an assessment of recoverable reserves, future
oil and natural gas prices, operating costs, potential environmental and other
liabilities and other factors beyond the Company's control. This assessment is
necessarily inexact and its accuracy is inherently uncertain. In connection with
such an assessment, the Company performs a review of the subject properties it
believes to be generally consistent with industry practices. This review,
however, will not reveal all existing or potential problems, nor will it permit
a buyer to become sufficiently familiar with the properties to assess fully
their deficiencies and capabilities. Inspections may not be performed on every
well, and structural and environmental problems are not necessarily observable
even when an inspection is undertaken. The Company generally assumes preclosing
liabilities, including environmental liabilities, and generally acquires
interests in the properties on an "as is" basis. With respect to its
acquisitions to date, the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. There can be no
assurance that any acquisitions will be successful. Any unsuccessful acquisition
could have a material adverse effect on the Company.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
At March 23, 1999, the Company had 13,250 Bbls per month of 1999 oil
production hedged at a NYMEX floor price of $17.00 per Bbl and a ceiling price
of $22.00 per Bbl. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company uses hedging
contracts to manage its price risk and limit exposure to short-term fluctuations
in commodity prices. However, should 1999 NYMEX oil prices rise above $22.00 per
Bbl, the Company would not receive the marginal benefit of oil prices in excess
of $22.00 per Bbl.
Additionally, the Company is subject to interest rate risk, as $8.5 million
owed at March 23, 1999 under the Company's revolving credit facility accrues
interest at floating rates tied to LIBOR. The Company's current average rate is
approximately 7% locked in for 90 day terms.
The Company performed a sensitivity analysis to assess the potential effect
of commodity price risk and interest rate risk and determined that the effect,
if any, of reasonably possible near-term changes in NYMEX oil prices or interest
rates on the Company's financial position, results of operations and cash flow
should not be material.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements required by this item are
included on the pages immediately following the Index to Consolidated Financial
Statements appearing on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
27
<PAGE> 34
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF PETROGLYPH ENERGY, INC.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants...............................................................F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997...........................................F-3
Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996.............F-4
Consolidated Statements of Changes in Stockholders' Equity for the Years Ended
December 31, 1998, 1997 and 1996..............................................................F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996.............F-6
Notes to Consolidated Financial Statements.............................................................F-7
</TABLE>
F-1
<PAGE> 35
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Petroglyph Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
Petroglyph Energy, Inc. (a Delaware corporation) and subsidiary as of December
31, 1998 and 1997, and the related consolidated statements of operations,
changes in stockholders' equity, and cash flows for each of the three years in
the period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Petroglyph Energy, Inc. and subsidiary as of December 31, 1998 and 1997 and the
results of their operations and cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Dallas, Texas
February 25, 1999
F-2
<PAGE> 36
PETROGLYPH ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents ............................................ $ 2,007,737 $ 16,678,655
Accounts receivable:
Oil and natural gas sales ........................................ 264,827 665,214
Joint interest billing ........................................... 834,910 463,400
Other ............................................................ 133,342 144,684
------------ ------------
1,233,079 1,273,298
Inventory ............................................................ 1,234,323 1,376,737
Prepaid expenses ..................................................... 247,518 246,193
------------ ------------
Total Current Assets .................................... 4,722,657 19,574,883
------------ ------------
Property and equipment, successful efforts method at cost:
Proved properties .................................................... 32,191,345 23,317,886
Unproved properties .................................................. 10,072,036 2,957,707
Pipelines, gas gathering and other ................................... 10,024,602 6,901,300
------------ ------------
52,287,983 33,176,893
Less--Accumulated depreciation, depletion, and amortization .......... (11,590,068) (6,607,487)
------------ ------------
Property and equipment, net ...................................... 40,697,915 26,569,406
------------ ------------
Note receivable from officers ............................................. 246,500 246,500
Other assets, net ......................................................... 368,129 323,189
------------ ------------
Total Assets ............................................ $ 46,035,201 $ 46,713,978
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade ............................................................ $ 2,088,290 $ 3,608,144
Oil and natural gas sales ........................................ 280,179 735,343
Current portion of long-term debt ................................ -- 36,598
Accrued taxes payable ............................................ 124,857 172,411
Other ............................................................ 277,637 149,771
------------ ------------
Total Current Liabilities ............................... 2,770,963 4,702,267
------------ ------------
Long-term debt ............................................................ 7,500,000 --
------------ ------------
Deferred tax liability .................................................... 452,488 2,514,154
------------ ------------
Stockholders' Equity:
Common Stock, par value $.01 per share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding .............. $ 54,583 $ 54,583
Paid-in capital ...................................................... 46,134,018 46,134,018
Retained earnings (deficit) .......................................... (10,876,851) (6,691,044)
------------ ------------
Total Stockholders' Equity .............................. 35,311,750 39,497,557
------------ ------------
Total Liabilities and Stockholders' Equity ................................ $ 46,035,201 $ 46,713,978
============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-3
<PAGE> 37
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Operating Revenues:
Oil sales ............................................. $ 2,912,293 $ 3,734,856 $ 4,458,769
Natural gas sales ..................................... 1,365,850 1,070,195 998,920
Other ................................................. 189,924 60,847 --
------------ ------------ ------------
Total operating revenues ........................ 4,468,067 4,865,898 5,457,689
------------ ------------ ------------
Operating Expenses:
Lease operating ....................................... 1,927,334 1,559,885 2,368,973
Production taxes ...................................... 218,129 178,822 248,848
Exploration costs ..................................... 192,526 -- 68,818
Depreciation, depletion, and amortization ............. 1,866,111 1,852,296 2,805,693
Impairments ........................................... 4,848,218 -- --
General and administrative ............................ 2,128,774 1,299,851 902,409
------------ ------------ ------------
Total operating expenses ........................ 11,181,092 4,890,854 6,394,741
------------ ------------ ------------
Operating Loss ............................................. (6,713,025) (24,956) (937,052)
Other Income (Expenses):
Interest income (expense), net ........................ 406,975 114,036 40,580
Gain (loss) on sales of property and equipment, net ... 58,577 12,440 1,383,766
------------ ------------ ------------
Net income (loss) before income taxes ...................... (6,247,473) 101,520 487,294
------------ ------------ ------------
Income Tax Expense (Benefit):
Current ............................................... -- (463,238) --
Deferred .............................................. (2,061,666) 2,977,392 --
Pro forma ............................................. -- -- 190,044
------------ ------------ ------------
Total Income Tax (Benefit) Expense .............. (2,061,666) 2,514,154 190,044
------------ ------------ ------------
Net Income (Loss) .......................................... $ (4,185,807) $ (2,412,634) $ 297,250
============ ============ ============
Earnings (Loss) per Common Share, Basic and Diluted ........ $ (.77) $ (.73) $ .11
============ ============ ============
Weighted Average Common Shares Outstanding (Note 4)
Actual ................................................ 5,458,333 3,326,826 --
Pro forma ............................................. -- -- 2,833,333
============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-4
<PAGE> 38
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
RETAINED
COMMON PARTNERS' PAID IN EARNINGS
STOCK CAPITAL CAPITAL (DEFICIT) TOTAL EQUITY
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1995 ........ $ -- $ 16,973,044 $ -- $ (4,765,704) $ 12,207,340
Contributions ..................... -- -- -- -- --
Net income before income
taxes ............................. -- -- -- 487,294 487,294
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1996 ........ -- 16,973,044 -- (4,278,410) 12,694,634
Initial public offering of
common stock, net of
offering costs ................... 26,250 -- 29,189,307 -- 29,215,557
Transfers at Conversion ........... 28,333 (16,973,044) 16,944,711 -- --
Deferred income taxes
recorded upon Conversion
(Note 2) ....................... -- -- -- (2,474,561) (2,474,561)
Net income ........................ -- -- -- 61,927 61,927
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1997 ........ 54,583 0 46,134,018 (6,691,044) 39,497,557
Net income (loss) ................. -- -- -- (4,185,807) (4,185,807)
------------ ------------ ------------ ------------ ------------
BALANCE, DECEMBER 31, 1998 ........ $ 54,583 $ 0 $ 46,134,018 $(10,876,851) $ 35,311,750
============ ============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-5
<PAGE> 39
PETROGLYPH ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Operating Activities:
Net income (loss) ................................................. $ (4,185,807) $ (2,412,634) $ 487,294
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization ................. 1,866,111 1,852,296 2,805,693
Gain on sales of property and equipment, net .............. (58,577) (12,440) (1,383,766)
Amortization of deferred revenue .......................... -- (45,860) (524,140)
Impairments ............................................... 4,848,218 -- --
Exploration costs ......................................... 192,526 -- --
Property abandonments ..................................... -- -- 68,818
Deferred Taxes ............................................ (2,061,666) 2,514,154 --
Proceeds from deferred revenue ............................ -- -- 570,000
Changes in assets and liabilities--
(Increase) decrease in accounts and other receivables ........ (113,462) 142,144 (481,169)
Increase in inventory ........................................ (33,586) (311,935) (579,257)
(Increase) decrease in prepaid expenses ...................... (26,325) (113,945) 3,561
Increase (decrease) in accounts payable and accrued
liabilities ............................................... (1,894,706) 20,819 3,162,406
------------ ------------ ------------
Net cash provided by (used in) operating activities ....... (1,467,274) 1,632,599 4,129,440
Investing Activities:
Proceeds from sales of property and equipment ..................... 88,200 745,712 8,968,274
Additions to oil and natural gas properties, including
exploration costs ............................................ (17,499,817) (12,767,808) (7,801,229)
Additions to pipelines, gas gathering and other ................... (3,123,302) (3,491,853) (863,911)
------------ ------------ ------------
Net cash provided by (used in) investing activities .......... (20,534,919) (15,513,949) 303,134
Financing Activities:
Proceeds from issuance of equity securities ....................... -- 30,515,625 --
Proceeds from issuance of, and draws on, notes payable ............ 7,500,000 10,085,381 2,085,024
Payments on notes payable ......................................... (36,598) (10,133,545) (5,908,527)
Payments for organization and financing costs ..................... (132,127) (1,485,088) (106,375)
------------ ------------ ------------
Net cash provided by (used in) financing activities .......... 7,331,275 28,982,373 (3,929,878)
------------ ------------ ------------
Net increase in cash and cash equivalents ............................ (14,670,918) 15,101,023 502,696
Cash and cash equivalents, beginning of period ....................... 16,678,655 1,577,632 1,074,936
------------ ------------ ------------
Cash and cash equivalents, end of period ............................ $ 2,007,737 $ 16,678,655 $ 1,577,632
============ ============ ============
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-6
<PAGE> 40
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
1. ORGANIZATION:
Petroglyph Energy, Inc. ("Petroglyph" or the "Company") was
incorporated in Delaware in April 1997 for the purpose of consolidating and
continuing the activities previously conducted by Petroglyph Gas Partners, L.P.
("PGP" or the "Partnership"). PGP was a Delaware limited partnership organized
on April 15, 1993 to acquire, explore for, produce and sell oil, natural gas,
and related hydrocarbons. The general partner of PGP at its formation was
Petroglyph Energy, Inc., a Kansas corporation ("PEI"). Petroglyph Gas Partners
II, L.P. ("PGP II") was organized on April 15, 1995 as a Delaware limited
partnership, to acquire, explore for, produce and sell oil, natural gas and
related hydrocarbons. The general partner of PGP II was PEI (1% interest) and
the limited partner was PGP (99% interest). Pursuant to the terms of an Exchange
Agreement dated August 22, 1997 (the "Exchange Agreement"), the Company acquired
all of the outstanding partnership interests of the Partnership and all of the
stock of PEI in exchange for shares of Common Stock of the Company (the
"Conversion"). The Conversion and other transactions contemplated by the
Exchange Agreement were consummated immediately prior to the closing of the
initial public offering of the Company's Common Stock (the "Offering"). The
Conversion has been accounted for as a transfer of assets and liabilities
between affiliates under common control and resulted in no change in carrying
values of these assets and liabilities. Effective June 30, 1998, PEI, PGP and
PGP II were dissolved and the assets and liabilities and results of operations
were rolled up into the Company with no change in carrying values.
The accompanying consolidated financial statements of Petroglyph
include the assets, liabilities and results of operations of PGP, its wholly
owned subsidiary, Petroglyph Operating Company, Inc. ("POCI"), and PGP's
proportionate share of assets, liabilities and revenues and expenses of PGP II
through June 30, 1998. Prior to that time, PGP owned a 99% interest in PGP II.
POCI is a subchapter C corporation. POCI is the designated operator of all wells
for which Petroglyph has acquired operating rights. Accordingly, all producing
overhead and supervision fees were charged to the joint accounts by POCI. All
material intercompany transactions and balances have been eliminated in the
preparation of the accompanying consolidated financial statements.
The Company's operations are primarily focused in the Uinta Basin of
Utah and the Raton Basin of Colorado.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
MANAGEMENT'S USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest during 1998, 1997 and 1996 totaled $116,000,
$325,000, and $250,000, respectively. The Company did not make any cash payments
for income taxes during 1998 based on net losses for the year, and no cash
payments for income taxes were made in 1997 or 1996 based on its partnership
structure in effect during those periods.
F-7
<PAGE> 41
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful
accounts, the amounts of which are immaterial as of December 31, 1998 and 1997.
INVENTORY
Inventories consist primarily of tubular goods and oil field materials
and supplies, which the Company plans to utilize in its ongoing exploration and
development activities and are carried at the lower of weighted average
historical cost or market value.
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its
oil and natural gas properties whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized on a
unit-of-production basis over the respective properties' remaining proved
reserves. Amortization of capitalized costs is provided on a
prospect-by-prospect basis.
Leasehold costs are capitalized when incurred. Unproved oil and natural
gas properties with significant acquisition costs are periodically assessed and
any impairment in value is charged to exploration costs. The costs of unproved
properties which are not individually significant are assessed periodically in
the aggregate based on historical experience, and any impairment in value is
charged to exploration costs. The costs of unproved properties that are
determined to be productive are transferred to proved oil and natural gas
properties. The Company does not capitalize general and administrative costs
related to drilling and development activities.
Exploration costs, including geological and geophysical expenses,
property abandonments and annual delay rentals, are charged to expense as
incurred. Exploratory drilling costs, if any, including the cost of
stratigraphic test wells, are initially capitalized but charged to expense if
and when the well is determined to be unsuccessful.
The Company adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," in connection with its formation.
SFAS No. 121 requires that proved oil and natural gas properties be assessed for
an impairment in their carrying value whenever events or changes in
circumstances indicate that such carrying value may not be recoverable. SFAS No.
121 requires that this assessment be performed by comparing the anticipated
future net cash flows to the net carrying value of oil and natural gas
properties. This assessment must generally be performed on a
property-by-property basis. The Company recognized impairments of $4,848,218 in
1998. No such impairments were required in the years ended December 31, 1997 and
1996.
Pipelines, Gas Gathering and Other
Other property and equipment is primarily comprised of field water
distribution systems and natural gas gathering systems located in the Uinta and
Raton Basins, field building and land, office equipment, furniture and fixtures
and automobiles. The gathering systems and the field water distribution systems
are amortized on a unit-of-production basis over the remaining proved reserves
attributable to the properties served. These other items are amortized on a
straight-line basis over their estimated useful lives which range from three to
forty years.
F-8
<PAGE> 42
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
ORGANIZATION AND FINANCING COSTS
Organization costs are amortized on a straight-line basis over a period
not to exceed 5 years and are presented net of accumulated amortization of
$100,385, $61,895 and $49,459 at December 31, 1998, 1997 and 1996, respectively.
Amortization of $38,490, $12,436, and $21,447 is included in depreciation,
depletion and amortization expense in the accompanying consolidated statements
of operations for the years ended December 31, 1998, 1997 and 1996,
respectively. Organization costs for periods prior to December 31, 1996 were
comprised of costs related to the formation of PGP and PGP II, which were
amortized over a period of three years.
Costs related to the issuance of the Company's notes payable are
deferred and amortized on a straight-line basis over the life of the related
borrowing. Such amortization costs of $25,883 are included in interest expense
in the accompanying statements of operations for the year ended December 31,
1998.
INTEREST INCOME (EXPENSE)
For the years ended December 31, 1998, 1997 and 1996, interest income
is presented net of interest expense of $132,193, $198,519 and $106,715,
respectively.
CAPITALIZATION OF INTEREST
Interest costs associated with maintaining the Company's inventory of
unproved oil and natural gas properties and significant development projects are
capitalized. Interest capitalized totaled $90,000, $127,000 and $195,000 for the
years ended December 31, 1998, 1997 and 1996, respectively.
REVENUE RECOGNITION AND NATURAL GAS BALANCING
The Company utilizes the entitlements method of accounting whereby
revenues are recognized based on the Company's revenue interest in the amount of
oil and natural gas production. The amount of oil and natural gas sold may
differ from the amount which the Company is entitled based on its revenue
interests in the properties. The Company had no significant natural gas
balancing positions at December 31, 1998 or 1997.
INCOME TAXES
Prior to the Conversion, the results of operations of the Company were
included in the tax returns of its owners. As a result, tax strategies were
implemented that are not necessarily reflective of strategies the Company would
have implemented. In addition, the tax net operating losses generated by the
Company during the period from its inception to date of the Conversion will not
be available to the Company to offset future taxable income as such benefit
accrued to the owners.
In conjunction with the Conversion, the Company adopted SFAS No. 109,
"Accounting for Income Taxes," which provides for determining and recording
deferred income tax assets or liabilities based on temporary differences between
the financial statement carrying amounts and the tax bases of assets and
liabilities using enacted tax rates. SFAS No. 109 requires that the net deferred
tax liabilities of the Company on the date of the Conversion be recognized as a
component of income tax expense. The Company recognized a one-time charge of
approximately $2.5 million in deferred tax liabilities and income tax expense on
the date of the Conversion.
Upon the Conversion, the Company became taxable as a corporation. Pro
forma income tax information for the year ended December 31, 1996, presented in
the accompanying consolidated statements of operations and in Note 7, reflects
the income tax expense (benefit), net income (loss) and net income (loss) per
common share as if all
F-9
<PAGE> 43
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: -- (CONTINUED)
Partnership income for 1996 had been subject to corporate federal income tax,
exclusive of the effects of recording the Company's net deferred tax liabilities
upon the Conversion.
DERIVATIVES
The Company uses derivatives on a limited basis to hedge against
interest rate and product prices risks, as opposed to their use for trading
purposes. The Company's policy is to ensure that a correlation exists between
the financial instruments and the Company's pricing in its sales contracts prior
to entering into such contracts. Gains and losses on commodity futures contracts
and other price risk management instruments are recognized in oil and natural
gas revenues when the hedged transaction occurs. Cash flows related to
derivative transactions are included in operating activities.
STOCK-BASED COMPENSATION
Upon the Conversion, the Company adopted the provisions of Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." In
accordance with APB No. 25, no compensation will be recorded for stock options
or other stock-based awards that are granted with an exercise price equal to or
above the common stock price on the date of the grant. As of December 31, 1998
and December 31, 1997, there is no impact from adoption of APB No. 25 or
Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation" (SFAS No. 123) as no stock options, warrants or grants had been
exercised at such dates. The Company will, however, adopt the disclosure
requirements of SFAS No. 123, "Accounting for Stock-Based Compensation" which
will require the Company to present pro forma disclosures of net income and
earnings per share as if SFAS No. 123 had been adopted.
RECLASSIFICATIONS
Certain reclassifications have been made to prior year balances to
conform to current year presentation.
3. ACQUISITIONS AND DISPOSITIONS:
In June 1996, the Company sold a 50% working interest in its Antelope
Creek field properties to an industry partner. The Company retained a 50%
working interest and continues to serve as operator of the property. In exchange
for the sale of the interest in the Antelope Creek field, the Company received
$7.5 million, as adjusted, in cash and the parties entered into a Unit
Participation Agreement for development of the Antelope Creek field. Under the
terms of this agreement, the Company received $5.3 million in carried
development costs for approximately 50 wells over a 12 month period which ended
on June 30, 1997. The Company recognized a pre-tax gain on this sale of $1.3
million. This Unit Participation Agreement is structured such that the Company
paid 25% of the development costs of the Antelope Creek field from the date of
the agreement until approximately $21 million in total development costs had
been incurred. By December 31, 1997, all of this carried development cost had
been expended. In addition, under the terms of the Unit Participation Agreement,
the Company's working interest in the Antelope Creek field will increase to 58%,
and its partner's working interest will be reduced to 42%, at such time as the
Company's partner in the Antelope Creek field achieves payout, as defined in the
Unit Participation Agreement.
As an additional part of the purchase and sale agreement, the Company
sold a 50% net profits interest (NPI) in its remaining 50% interest in the
Antelope Creek field commencing on the date of the agreement. The NPI continued
in effect until 67,389 barrels of equivalent production related to the NPI was
produced from the Antelope Creek field. The NPI entitled the holder to receive
the net profits, defined in the purchase and sale agreement as revenues less
direct operating expenses, from the sale of the barrels of oil equivalent
production relating to the NPI. A value of $570,000 was assigned to the sale of
the NPI and recorded as deferred revenue. This amount was determined based on
the projected net profits that would have been received from the sale of the
barrels of oil equivalent production related to
F-10
<PAGE> 44
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
3. ACQUISITIONS AND DISPOSITIONS: -- (CONTINUED)
the NPI. As these barrels of oil equivalent production were produced and NPI
proceeds were disbursed to the holder of the NPI, an equal amount of the
deferred revenue was recognized as oil and natural gas revenue. Through December
31, 1996, the Company recognized $524,140 of revenue related to this NPI. The
remaining $45,860 was recognized during the year ended December 31, 1997.
In July 1997, the Company acquired 56,000 net mineral acres in the
Raton Basin in Colorado for approximately $700,000. This acquisition had an
effective date of May 15, 1997. An additional 20,600 net mineral acres were
acquired by December 31, 1998 from various parties for a total of 76,600 acres.
In addition, the Company also acquired, simultaneously, an 80% interest in a 25
mile pipeline strategically located across the Company's acreage positions in
the Raton Basin for total consideration of approximately $320,000. The Company,
together with an industry partner, formed a partnership to operate this
pipeline. Under the terms of the purchase and sale agreement, the Company paid
$75,000 at closing, $75,000 on December 31, 1997 and paid a final $35,000 during
1998. Additionally, the Company assumed an obligation for delinquent property
taxes of approximately $135,000, which were paid in November of 1997. The
Company acquired the remaining 20% interest in the pipeline for $60,000
effective December 1998. Simultaneously, the partnership formed to operate the
pipeline was dissolved.
4. STOCKHOLDERS' EQUITY:
INITIAL PUBLIC OFFERING
On October 24, 1997, Petroglyph completed its initial public offering
(the "Offering") of 2,500,000 shares of common stock at $12.50 per share,
resulting in net proceeds to the Company of approximately $29.1 million.
Approximately $10.0 million of the net proceeds were used to eliminate all
outstanding amounts under the Company's Credit Agreement, the balance of the
proceeds were utilized to develop production and reserves in the Company's core
Uinta Basin and Raton Basin development properties and for other working capital
needs.
On November 24, 1997, the Company's underwriters exercised a portion of
an over-allotment option granted in connection with the Offering, resulting in
the issuance of an additional 125,000 shares of common stock at $12.50 per
share, with net proceeds to the Company of approximately $1.5 million.
EARNINGS PER SHARE INFORMATION
Effective December 31, 1997, the Company adopted the provisions of SFAS
No. 128, "Earnings Per Share," which prescribes standards for computing and
presenting earnings per share ("EPS") and supersedes APB Opinion 15, "Earnings
Per Share."
Pro forma weighted average shares outstanding for the year ended
December 31, 1996 are presented as if the Conversion had occurred, resulting in
common stock outstanding as of the beginning of the year. The computation of
basic and diluted EPS were identical for the years ended December 31, 1998, 1997
and 1996 due to the following reasons:
o Options to purchase 273,000 shares of common stock at $5.00 per share
were outstanding since October 19, 1998, but were not included in the
computation of diluted EPS because to do so would have been
antidilutive. The options, which expire on October 19, 2008, were still
outstanding at December 31, 1998.
o Options to purchase 321,000 shares and 337,000 shares of common stock
at $12.50 per share at December 31, 1998 and 1997, respectively, were
outstanding since November 1, 1997, but were not included in the
computations of diluted EPS because to do so would have been
antidilutive. The 321,000 options, which expire on November 1, 2007,
were still outstanding at December 31, 1998.
F-11
<PAGE> 45
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
EARNINGS PER SHARE INFORMATION: -- (CONTINUED)
o Warrants to purchase up to 6,496 shares of common stock were not
included in the computation of diluted EPS as they are antidilutive as
a result of the Company's net loss for the year ended December 31,
1998. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1998.
o As the Company completed the Offering in 1997, there were no equity
securities, nor any potentially dilutive equity securities outstanding
at December 31, 1996.
5. TRANSACTIONS WITH AFFILIATES:
The Company had notes receivable from certain executive officers
aggregating $246,500 at December 31, 1998 and 1997. These notes bear interest at
a rate of 9% and mature December 31, 2003. Accrued interest on the notes at
December 31, 1998 was $142,980.
The Company leases an office building from an affiliate. Rentals paid
to the affiliate for such leases totaled $36,486 during 1998 and $34,800 during
1997 and 1996. These rentals are included in general and administrative expense
in the accompanying consolidated financial statements.
In August 1997, the Company and Natural Gas Partners ("NGP") entered
into a financial advisory services agreement whereby NGP agreed to provide
financial advisory services to the Company for a quarterly fee of $13,750. In
addition, NGP was reimbursed for its out of pocket expenses incurred while
performing such services. The agreement was terminated at the end of the third
quarter 1998. Advisory fees paid to NGP during 1998 and 1997 totaled $43,190 and
$10,163, respectively.
For the years ended December 31, 1998, 1997 and 1996, the Company paid
legal fees of $57,060, $139,384 and $109,000, respectively, to the law firm of
Morris, Laing, Evans, Brock & Kennedy, Chartered, where A.J. Schwartz, a
director of the Company, is a partner.
During 1997, the Company entered into an agreement with Sego Resources,
Inc. (SEGO), a portfolio company of NGP, to serve as operator on a series of
wells to be drilled in the Wasatch formation in the Company's Natural Buttes
Extension acreage. The Company has participated in drilling and completing 2
wells through December 31, 1998. As a result of the drilling and operating
activity, the Company paid SEGO $183,359 for capital expenditures and $6,182 for
operating charges in 1998. As of December 31, 1998, SEGO owed the Company
$18,525 relating to this activity.
6. LONG-TERM DEBT:
In September 1997, the Company entered into the Credit Agreement with
Chase. The Credit Agreement included a $20.0 million combination credit facility
with a two-year revolving credit facility and an original borrowing base of $7.5
million to be redetermined semi-annually ("Tranche A"), which was set to expire
on September 15, 1999, at which time all balances outstanding under Tranche A
would have converted to a term loan expiring on September 15, 2002.
Additionally, the Credit Agreement contained a separate revolving facility of
$2.5 million ("Tranche B"), which was set to expire on March 15, 1999. The
Company utilized a portion of the proceeds from the Offering to eliminate all
outstanding amounts under the Credit Agreement in October 1997. With the
repayment of the Tranche B indebtedness, the $2.5 million under that portion of
the Credit Agreement was no longer available to the Company. Effective September
30, 1998, the Company amended the Credit Agreement with Chase, (the
"Amendment"). The Amendment increased the credit facility to $50.0 million with
a two-year revolving credit facility and an original borrowing base of $15.0
million to be redetermined quarterly beginning December 31, 1998. The next
scheduled borrowing base redetermination date is March 31, 1999. Because of
historically low crude oil prices, management expects the borrowing base amounts
available under the Credit Agreement will decline from the current level of
$15.0 million. Although the borrowing base amount ultimately determined by Chase
is outside of the Company's control, management believes the borrowing base
amount will not be reduced below the current outstanding balance of $8.5
F-12
<PAGE> 46
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
6. LONG-TERM DEBT: -- (CONTINUED)
million. The revolving credit facility expires on September 30, 2000, at which
time all outstanding balances will convert to a term loan expiring on September
30, 2003. Interest on outstanding borrowings is calculated, at the Company's
option, at either Chase's prime rate or the London Interbank Offer Rate plus a
margin determined by the amount outstanding under the facility.
7. INCOME TAXES:
Upon the completion of the Offering in November 1997, all income of the
Company became taxable as a corporation. Pro forma information in the 1996
consolidated statements of operations reflects the income tax expense (benefit),
net income (loss) and net income (loss) per common share/unit as if all prior
Partnership income had been subject to corporate federal income tax, exclusive
of the effects of recording the Company's net deferred tax liabilities upon the
conclusion of the Offering. This pro forma information is presented below for
comparative purposes only.
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the periods shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
---- ---- ----
(pro forma)
<S> <C> <C> <C>
Income tax expense (benefit) at the federal
statutory rate .................................... (35%) 35% 35%
State income tax expense (benefit) ......................... (4%) 4% 4%
Deferred tax liabilities recorded upon the Offering ........ -- 2438% --
Net operating loss utilized by partners .................... 2% -- --
Permanent differences ...................................... 2% -- --
True-ups ................................................... 1% -- --
Other ...................................................... 1% -- --
----- ------ ----
$ (33)% $ 2477% $ 39%
===== ====== ====
</TABLE>
Components of income tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
(pro forma)
<S> <C> <C> <C>
Current .................................................... $ -- $ (463,238) $ (222,169)
Deferred ................................................... (2,061,666) 2,977,392 412,213
----------- ----------- -----------
Total .................................... $(2,061,666) $ 2,514,154 $ 190,044
=========== =========== ===========
</TABLE>
F-13
<PAGE> 47
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
7. INCOME TAXES: -- (CONTINUED)
Deferred tax assets and liabilities are the results of temporary
differences between the financial statement carrying values and tax bases of
assets and liabilities. The Company's net deferred tax liability positions as of
December 31, 1998 and 1997, are summarized below:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1998 1997
----------- -----------
(pro forma)
<S> <C> <C>
Deferred Tax Assets:
Inventory and other ......................... 76,188 --
Net operating loss carryforwards ............ $ 6,344,613 $ 496,232
----------- -----------
Total Deferred Tax Assets ................ 6,420,801 496,232
----------- -----------
Deferred Tax Liabilities:
Inventory and other ......................... -- (32,994)
Property and equipment ...................... (6,873,289) (2,977,392)
----------- -----------
Total Deferred Tax Liabilities ........... (6,873,289) (3,010,386)
----------- -----------
Total Net Deferred Tax Liability ......... $ (452,488) $(2,514,154)
=========== ===========
</TABLE>
The net deferred tax liability as of December 31, 1997 is primarily the
amount that the Company was required to recognize as income tax expense on the
date of the Conversion discussed in Note 2.
8. DERIVATIVES, SALES CONTRACTS AND SIGNIFICANT CUSTOMERS:
DERIVATIVES AND SALES CONTRACTS
The Company accounts for forward sales transactions as hedging
activities and, accordingly, records all gains and losses in oil and natural gas
revenues in the period the hedged production is sold. Included in oil revenue is
a net gain of $386,000 in 1998, a net loss of $132,200 in 1997 and a net loss of
$128,400 in 1996. Included in natural gas revenues in 1997 is a net loss of
$46,000.
In September 1995, the Company assumed the obligations of a former
joint interest owner under a financial swap arrangement. This agreement covers
the sale of 549,000 Bbls from January 1996 to December 1999 at a NYMEX floor
price of $17.00 per Bbl and a ceiling price of $20.75 per Bbl. The ceiling price
was increased to $22.00 per Bbl for 1999. Additionally, during 1998, the Company
entered into a swap arrangement covering the sale of 6,000 Bbls per month from
January, 2000 to December, 2000 at a NYMEX floor price of $14.00 and a ceiling
price of $16.00 per Bbl. At December 31, 1998, this contract was outstanding and
calls for the remaining sale of 231,000 barrels of oil over the next two years
as follows:
<TABLE>
<CAPTION>
YEAR BBLS
---- --------
<S> <C>
1999.................................... 159,000
2000.................................... 72,000
--------
Total............................... 231,000
========
</TABLE>
During March of 1999, the Company liquidated the hedge contract
covering 72,000 Bbls in the year 2000 for approximately $16,000.
In June 1994, the Company entered into a contract to sell its oil
production from certain leases of its Utah properties to Purchaser "A." The
price under this contract is agreed upon on a monthly basis and is generally
based on
F-14
<PAGE> 48
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
DERIVATIVES AND SALES CONTRACTS: -- (CONTINUED)
this purchaser's posted price for yellow or black wax production, as applicable.
This contract will continue in effect until terminated by either party upon
giving proper notice. During the years ended December 31, 1998, 1997 and 1996
the volumes sold under this contract totaled 125 MBbls, 74 MBbls and 61 MBbls,
respectively, at an average sales price per Bbl for each year of $9.27, $14.80
and $19.33, respectively.
In January 1996, the Company entered into a contract to sell black wax
production from its Utah leases to Purchaser "B." The price under this contract
is based on the monthly average of the NYMEX price for West Texas Intermediate
("WTI") crude oil, less $.50 per Bbl, adjusted for the pricing differential
related to the gravity difference between Purchaser B's Utah black wax posting
and WTI, less $2.50 per Bbl to cover gathering costs and quality differential.
During the year ended December 31, 1996, the Company sold 59 MBbls of oil under
this contract at an average price of $19.69 per Bbl. This contract was canceled
effective January 1, 1997.
In July 1997, the Company entered into a modification of its crude oil
sales contract to sell its black wax crude oil production from the Antelope
Creek field to Purchaser "C" at a price equal to posting, less an agreed upon
adjustment to cover handling and gathering costs. This contract supersedes the
contract which the Company had with this purchaser from February 1994 through
June 1997. This contract will continue in effect until terminated by either
party upon giving proper notice. For the years ended December 31, 1998 and 1997,
the Company sold 38 MBbls and 70 MBbls, respectively, under this contract at an
average price of $9.04 and $16.58 per Bbl, respectively.
In June 1997, the Company entered into a crude oil contract to sell
black wax production from certain of its oil tank batteries in Antelope Creek to
Purchaser "D." This contract was effective until May 31, 1998 and called for the
Company to receive a per Bbl price equal to the current month NYMEX closing
price for sweet crude, averaged over the month in which the crude is sold, less
an agreed upon fixed adjustment. Volumes sold under this contract totaled 25
MBbls and 73 MBbls at an average price of $12.88 and $14.50 for the years ended
December 31, 1998 and 1997, respectively.
In addition to the sales contracts discussed above, Purchaser "C" has a
call on all of the Company's share of oil production from the Antelope Creek
field, which has priority over all other sales contracts. Under the terms of the
Oil Production Call Agreement (the "Call Agreement"), which the Company assumed
in connection with its acquisition of its initial interest in the Antelope Creek
field, this purchaser has the option to purchase all or any portion of the oil
produced from the Antelope Creek field at the current market price for the
gravity and type of oil produced and delivered by the Company. The Call
Agreement was assumed by the Company on the date it acquired its interest in the
Antelope Creek field and has no expiration date. In the event Purchaser "C"
exercises the call option, the Company will not be penalized under its other
sales contracts for failure to deliver volumes thereunder.
SIGNIFICANT CUSTOMERS
The Company's revenues are derived principally from uncollateralized
sales to customers in the oil and gas industry. The concentration of credit risk
in a single industry affects the Company's overall exposure to credit risk
because customers may be significantly affected by changes in economic and other
conditions. In addition, the Company sells a significant portion of its oil and
natural gas revenue each year to a few customers. Oil sales to two purchasers in
1998 were approximately 30% and 9% of total 1998 oil and gas revenues. Natural
gas sales to one purchaser in 1998 were approximately 25% of total oil and
natural gas revenues. Oil sales to three purchasers in 1997 were approximately
24%, 23% and 22% of total 1997 oil and gas revenues. Natural gas sales to one
purchaser in 1997 were approximately 18% of total oil and natural gas revenues.
Oil sales to three purchasers in 1996 were approximately 26%, 26% and 12% of
total 1996 oil and gas revenues.
F-15
<PAGE> 49
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
9. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Because of their short-term maturity, the fair value of cash and cash
equivalents, certificates of deposit, accounts receivable and accounts payable
approximate their carrying values at December 31, 1998 and 1997. The fair value
of the Company's bank borrowings approximate their carrying value because the
borrowings bear interest at market rates. The Company does not have any
investments in debt or equity securities as of December 31, 1998 or 1997. The
fair value of the Company's outstanding oil price swap arrangement, described in
the preceding note, has an estimated fair value of $648,000 and $182,000 at
December 31, 1998 and 1997, respectively. These estimates are based on quoted
market values.
10. STOCK INCENTIVE PLAN:
DESCRIPTION OF PLAN
The Board of Directors and the stockholders of the Company approved the
adoption of the Company's 1997 Incentive Plan (the "1997 Incentive Plan")
effective as of the completion of the Offering. The purpose of the 1997
Incentive Plan is to reward selected officers and key employees of the Company
and others who have been or may be in a position to benefit the Company,
compensate them for making significant contributions to the success of the
Company and provide them with proprietary interest in the growth and performance
of the Company. Participants in the 1997 Incentive Plan are selected by the
Compensation Committee of the Board of Directors from among those who hold
positions of responsibility and whose performance, in the judgment of the
Compensation Committee, can have a significant effect on the success of the
Company.
In October 1998, the Board of Directors of the Company approved an
amendment to the 1997 Incentive Plan, increasing the number of shares available
for grant from 375,000 to 605,000. The amendment is subject to the approval of
the stockholders of the Company at the annual stockholders meeting to be held on
May 26, 1999. As of December 31, 1998, options have been granted to purchase
594,000 shares of Common Stock. This amount includes 54,000 shares of Common
Stock available under the 1997 Incentive Plan as originally adopted that were
granted to participants at an exercise price equal to $5.00 per share and
219,000 shares of Common Stock, subject to stockholder approval, also granted at
an exercise price of $5.00 per share. One third of the options granted in
October 1998 will vest each year commencing on October 19, 1999.
As of December 31, 1997, options were granted to purchase 337,000
shares of Common Stock to participants at an exercise price per share equal to
$12.50 per share. 16,000 of those shares have subsequently been terminated.
One-third of these options vest each year commencing on November 1, 1998. No
options had been exercised under the 1997 Incentive Plan as of December 31,
1998.
The following table summarized information about Petroglyph's stock
options which were outstanding, and those which were exercisable, as of December
31, 1998.
OPTIONS OUTSTANDING
<TABLE>
<CAPTION>
EXERCISE NUMBER REMAINING NUMBER
PRICE OUTSTANDING LIFE EXERCISABLE
-------- ----------- --------- -----------
<S> <C> <C> <C>
$ 5.00 273,000 9.8 years --
$ 12.50 321,000 8.8 years 107,000
----------- --------- ---------- ---------
594,000 9.3 years 107,000
</TABLE>
F-16
<PAGE> 50
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
DESCRIPTION OF PLAN: -- (CONTINUED)
Pursuant to the 1997 Incentive Plan, participants will be eligible to
receive awards consisting of (i) stock options, (ii) stock appreciation rights,
(iii) stock, (iv) restricted stock, (v) cash, or (vi) any combination of the
foregoing. Stock options may be either incentive stock options within the
meaning of Section 422 of the Internal Revenue Code of 1986, as amended, or
nonqualified stock options.
Warrants to purchase up to 6,496 shares of common stock, at a price
equal to par value, were granted to Chase under the terms of the Credit
Agreement. The warrants, which expire on September 15, 2007, were still
outstanding at December 31, 1998.
PRO FORMA EFFECT OF RECORDING STOCK-BASE COMPENSATION AT ESTIMATED FAIR VALUE
(UNAUDITED)
The following table presents pro forma loss available to common stock
and loss per common share for 1998, as if stock-based compensation had been
recorded at the estimated fair value of stock awards at the grant date, as
prescribed by SFAS No. 123 (Note 2):
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED
DECEMBER 31, 1998 DECEMBER 31, 1997
----------------- -----------------
<S> <C> <C>
Loss available to common stock
As reported $ (4,185,807) $ (2,412,634)
Pro forma $ (4,633,833) $ (2,492,007)
Loss per common share
As reported, basic and diluted $ (.77) $ (.73)
Pro forma, basic and diluted $ (.85) $ (.75)
</TABLE>
The fair value of the options, as determined using the Black-Scholes
pricing model were $2.63 and $6.95 for the options issued during 1998 and 1997,
respectively. The assumptions used in calculating the values are set forth in
the following table:
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Risk free interest rate 4.62% 5.89%
Expected life 7 years 7 years
Expected volatility 43.59% 45.24%
Expected dividends 0 0
</TABLE>
There was no impact of adoption of APB No. 25 or SFAS No. 123 for the
year ended December 31, 1996 as no stock options, warrants or grants had been
issued at such date.
F-17
<PAGE> 51
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
11. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company leases offices and office equipment in its primary
locations under non-cancelable operating leases. As of December 31, 1998, total
minimum future lease payments for all non-cancelable lease agreements is
$137,747.
Amounts incurred by the Company under operating leases (including
renewable monthly leases) were $91,042, $53,383, and $41,548, in 1998, 1997 and
1996, respectively.
LITIGATION
The Company and its subsidiaries are involved in certain litigation and
governmental proceedings arising in the normal course of business. Company
management and legal counsel do not believe that ultimate resolution of these
claims will have a material effect on the Company's financial position or
results of operations.
OTHER COMMITMENTS
During July, 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately 37
miles of 10-inch steel pipeline from near Trinidad, Colorado, to the Company's
Raton Basin coalbed methane development area approximately 6 miles southwest of
Walsenburg, Colorado. The pipeline was placed in service in January 1999 with a
delivery capacity of approximately 50 MMcf per day and will provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company has committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity beginning February 1, 1999,
and ending January 31, 2009. The commitment begins at a minimum volume of 2,000
Mcf per day and increases by 1,000 Mcf per day after each three-month period,
with a maximum commitment of 10,000 Mcf per day. At the end of the first
two-year period, The Company has the option to increase the minimum volume or
eliminate the commitment. The cost of eliminating the commitment is the cost of
the pipeline ($6.4 million) less credit applied for the Company's Raton Basin
commercial gas production up to 16,000 Mcf per day. This cost could be applied
as a credit to transportation elsewhere on CIG's system. The Company can reduce
the minimum monthly commitment by selling its available pipeline capacity at
market rates.
In December 1996, the Company entered into an agreement with an
industry partner whereby the industry partner would pay for the costs of a 3-D
seismic survey on the Company's leasehold interests in the Helen Gohlke field,
located in Victoria and DeWitt Counties of South Texas. In exchange for such
costs, the industry partner has the right to earn a 50% interest in the
leasehold rights of the Company in the Helen Gohlke field. The industry partner
is required to pay 50% of the costs to drill and complete any wells in the area
covered by the seismic survey, and, in exchange, will earn a 50% interest in the
well and in certain acreage surrounding the well. The amount of such surrounding
acreage in which the industry partner will earn an interest is to be determined
based upon the depth of the well drilled.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to environmental
protection, including the generation, storage, handling, emission,
transportation and discharge of materials into the environment, and relating to
safety and health. The recent trend in environmental legislation and regulating
generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction of drilling commences and for certain other
activities; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness and other protected areas; and impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various of the Company's operations are subject to
revocation, modification and
F-18
<PAGE> 52
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
ENVIRONMENTAL MATTERS: -- (CONTINUED)
renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations, and violations are subject to fines
or injunction, or both. In the opinion of management, the Company is in
substantial compliance with current applicable environmental laws and
regulations, and the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. Nevertheless,
changes in existing environmental laws and regulations or in interpretations
thereof could have a significant impact on the Company, as well as the oil and
natural gas industry in general.
12. SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND NATURAL GAS PRODUCING
ACTIVITIES:
COSTS INCURRED RELATED TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition
Unproved Properties ............... $ 7,141,142 $ 1,721,636 $ 490,487
Proved Properties ................. 42,533 147,387 --
Development ............................ 10,123,616 10,003,468 6,983,715
Exploration ............................ 192,526 -- --
Improved recovery costs ................ -- 895,317 327,027
----------- ----------- -----------
Total ........................ $17,499,817 $12,767,808 $ 7,801,229
=========== =========== ===========
</TABLE>
PROVED RESERVES
Independent petroleum engineers have estimated the Company's proved oil
and natural gas reserves as of December 31, 1998 and 1997, all of which are
located in the United States. Prior period reserves were estimated by the
Company's reserve engineer. Proved reserves are the estimated quantities that
geologic and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are the quantities expected to
be recovered through existing wells with existing equipment and operating
methods. Due to the inherent uncertainties and the limited nature of reservoir
data, such estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production of these
reserves may be substantially different from the original estimate. Revisions
result primarily from new information obtained from development drilling and
production history and from changes in economic factors.
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows
("standardized measure") and changes in such cash flows are prepared using
assumptions required by the Financial Accounting Standards Board. Such
assumptions include the use of year-end prices for oil and natural gas and
year-end costs for estimated future development and production expenditures to
produce year-end estimated proved reserves. Discounted future net cash flows are
calculated using a 10% rate. Estimated future income taxes are calculated by
applying year-end statutory rates to future pre-tax net cash flows, less the tax
basis of related assets and applicable tax credits.
The standardized measure does not represent management's estimate of
the Company's future cash flows or the value of the proved oil and natural gas
reserves. Probable and possible reserves, which may become proved in the future,
are excluded from the calculations. Furthermore, year-end prices used to
determine the standardized measure of
F-19
<PAGE> 53
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
STANDARDIZED MEASURE:-- (CONTINUED)
discounted cash flows are influenced by seasonal demand and other factors and
may not be the most representative in estimating future revenues or reserve
data.
<TABLE>
<CAPTION>
OIL Natural Gas
(BBLS) (Mcf)
----------- -----------
<S> <C> <C>
Proved Reserves (Unaudited):
December 31, 1995 ..................................... 1,561,092 6,659,160
Revisions .................................... (801,535) (3,146,699)
Extensions, additions and discoveries ........ 6,440,869 18,448,489
Production ................................... (262,910) (553,770)
Purchases of reserves ........................ -- --
Sales in place ............................... (810,380) (2,594,717)
----------- -----------
December 31, 1996 ..................................... 6,127,136 18,812,463
Revisions .................................... 558,350 (2,895,611)
Extensions, additions and discoveries ........ 3,168,390 5,939,453
Production ................................... (251,631) (537,466)
Purchases of reserves ........................ 10,245 269,323
Sales in place ............................... (156,675) (892,712)
----------- -----------
December 31,1997 ...................................... 9,455,815 20,695,450
Revisions .................................... (3,686,673) (7,358,640)
Extensions, additions and discoveries ........ 937,164 2,835,622
Production ................................... (261,817) (679,992)
Purchases of reserves ........................ -- --
Sales in place ............................... (17,329) --
----------- -----------
December 31, 1998 ..................................... 6,427,160 15,492,440
=========== ===========
PROVED DEVELOPED RESERVES:
December 31, 1995 ..................................... 1,561,092 6,659,160
=========== ===========
December 31, 1996 ..................................... 865,018 3,010,401
=========== ===========
December 31, 1997 ..................................... 4,742,028 10,839,164
=========== ===========
December 31, 1998 ..................................... 5,319,768 12,670,033
=========== ===========
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Future cash inflows .............................. $ 84,010,748 $ 169,302,079 $ 184,248,490
Future costs:
Production .............................. (25,826,978) (50,913,842) (43,993,010)
Development ............................. (5,823,801) (19,151,264) (16,455,901)
------------- ------------- -------------
Future net cash flows before income tax .......... 52,359,969 99,236,973 123,799,579
=============
Future income tax ................................ (8,767,729) (22,247,206) (32,657,687)
------------- ------------- -------------
Future net cash flows ............................ 43,592,240 76,989,767 91,141,892
10% annual discount .............................. 19,398,715 (42,836,688) (43,117,804)
------------- ------------- -------------
Standardized Measure ............................. $ 24,193,525 $ 34,153,079 $ 48,024,088
============= ============= =============
</TABLE>
F-20
<PAGE> 54
PETROGLYPH ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Standardized Measure, Beginning of Period ............. $ 34,153,079 $ 48,024,088 $ 13,370,705
Revisions:
Prices and costs ............................. (32,472,461) (26,476,631) 4,839,954
Quantity estimates ........................... 2,814,596 380,840 6,000,942
Accretion of discount ........................ 4,346,915 6,484,830 1,484,547
Future development cost ...................... 7,332,602 (1,869,101) (15,068,164)
Income tax ................................... 5,201,663 7,508,139 (14,604,066)
Production rates and other ................... (6,027,000) (8,545,510) 1,901,254
------------ ------------ ------------
Net revisions ....................... (18,803,685) (22,517,433) (15,445,533)
Extensions, additions and discoveries ................. 6,061,487 12,757,280 56,781,465
Production ............................................ (2,132,680) (3,372,040) (2,390,023)
Development costs ..................................... 5,031,367 -- --
Purchases in place .................................... -- 397,644 --
Sales in place ........................................ (116,043) (1,136,460) (4,292,526)
------------ ------------ ------------
Net change ................................... (9,959,554) (13,871,009) 34,653,383
Standardized Measure, End of Period ................... $ 24,193,525 $ 34,153,079 $ 48,024,088
============ ============ ============
</TABLE>
Year-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $8.04, $13.46, and
$19.50 per Bbl at December 31, 1998, 1997, and 1996, respectively. Year-end
weighted average gas prices were $2.09, $2.03, and $3.37, per Mcf at December
31, 1998, 1997, and 1996, respectively. 1998 weighted average oil price includes
a positive impact from crude oil hedging transactions resulting in a realized
price of $11.89 in 1999 and $8.75 in 2000. Weighted average oil price, excluding
hedges would have been $7.80. Price and cost revisions are primarily the net
result of changes in period-end prices, based on beginning of period reserve
estimates.
F-21
<PAGE> 55
APPENDIX II
Item 7. Financial Statements and Exhibits.
(a) Financial Statements of Businesses Acquired.
Report of Independent Public Accountants
Audited Statements of Revenues and Direct Operating Expenses
for the Years Ended December 31, 1998, 1997, and 1996
Notes to Statements of Revenues and Direct Operating Expenses
(b) Pro Forma Financial Information.
Unaudited Pro Forma Consolidated Balance Sheet as of
June 30, 1999
Unaudited Pro Forma Consolidated Statements of Operations
for the Year Ended December 31, 1998 and the Six Months
Ended June 30, 1999
Notes to Unaudited Pro Forma Consolidated Financial Statements
(c) Exhibits.
None.
2
<PAGE> 56
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Petroglyph Energy, Inc.:
We have audited the accompanying statements of revenues and direct
operating expenses of the Antelope Creek Acquisition as described in
Note 1 for the years ending December 31, 1998, 1997, and 1996. These
statements are the responsibility of the management of Petroglyph
Energy, Inc. (the "Company"). Our responsibility is to express an
opinion on these statements based on our audit.
We conducted our audit in accordance with general accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the statements of revenues
and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the statements of revenues and direct
operating expenses. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall presentation of the statements of revenues
and direct operating expenses. We believe that our audit provides a
reasonable basis for our opinion.
The accompanying statements of revenues and direct operating expenses
were prepared for the purpose of complying with the rules and
regulations of the Securities and Exchange Commission as described in
Note 1 and are not intended to be a complete presentation of the
Company's revenues and expenses.
In our opinion, the statements of revenues and direct operating
expenses referred to above present fairly, in all material respects,
the revenues and direct operating expenses of the Antelope Creek
Acquisition as described in Note 1 for the years ended December 31,
1998, 1997, and 1996 in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Dallas, Texas
November 1, 1999
3
<PAGE> 57
ANTELOPE CREEK ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED
<TABLE>
<CAPTION>
December 31, December 31, December 31,
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
REVENUES
Oil $2,221,828 $3,225,609 $1,463,599
Gas 937,205 834,603 251,481
---------- ---------- ----------
Total 3,159,033 4,060,212 1,715,080
---------- ---------- ----------
DIRECT OPERATING EXPENSES
Lease operating expense 1,736,881 1,364,814 533,166
Severance taxes 170,715 169,268 70,328
---------- ---------- ----------
Total 1,907,596 1,534,082 603,494
---------- ---------- ----------
EXCESS OF REVENUES OVER
DIRECT OPERATING EXPENSES $1,251,437 $2,526,130 $1,111,586
========== ========== ==========
</TABLE>
See Accompanying Notes to Statements of Revenues and Direct Operating Expenses.
4
<PAGE> 58
ANTELOPE CREEK ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION
Antelope Creek Acquisition
On August 20, 1999, Petroglyph Energy, Inc. (the "Company") acquired
the remaining 50% working interest in the Antelope Creek Field in the
Uinta Basin of Utah (the "Antelope Creek Property") from its
non-operated working interest partner, Williams Production Rocky
Mountain Company ("Williams"), for a purchase price of $6.9 million
(the "Antelope Creek Acquisition"). The Antelope Creek Acquisition,
which was effective August 1, 1999, gives the Company a 100% working
interest in the Antelope Creek Property.
In order to finance the Antelope Creek Acquisition, the Company
borrowed $2.5 million on an existing revolving credit facility with The
Chase Manhattan Bank ("Chase") pursuant to Amendment No. 1 dated as of
August 20, 1999 to the Second Amended and Restated Credit Agreement by
and between the Company and Chase dated as of September 30, 1998.
Additionally, the Company sold $5 million of 8% senior subordinated
notes due 2004 (the "Notes") to Intermountain Industries, Inc., an
Idaho corporation ("Intermountain"). The Notes required the Company to
deliver to Intermountain a stock purchase warrant to acquire 150,000
shares of Common Stock of the Company at an exercise price of $3.00 per
share and the ability for Intermountain to obtain additional stock
purchase warrants over the life of the Notes. The number of future
stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The
maximum number of shares of Common Stock issuable under the stock
purchase warrants for any given period is limited to 250,000 shares in
any one year, 400,000 over the first three years and 750,000 over the
five-year life of the notes. The Company may redeem the Notes at par
without penalty at any time. Upon redemption of the Notes, any
remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining
purchase price of the Antelope Creek Acquisition and for working
capital needs.
The accompanying statements of revenues and direct operating expenses
do not include general and administrative expense, interest income or
expense, a provision for depreciation, depletion and amortization or
any provision for income taxes because the property interests acquired
represent only a portion of a business and the costs incurred by
Williams are not necessarily indicative of the costs to be incurred by
the Company.
Historical financial information reflecting financial position, results
of operations and cash flows of the Antelope Creek Acquisition is not
presented because the entire acquisition cost was assigned to the oil
and gas property interests. Accordingly, the historical statements of
revenues and direct operating expenses have been presented in lieu of
the financial statements required under Rule 3-05 of Securities and
Exchange Commission Regulation S-X.
2. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Estimated Quantities of Proved Oil and Gas Reserves
Reserve information presented below has been estimated by the Company's
internal engineers using June 30, 1999 prices and costs. Proved
reserves are estimated quantities of crude oil and natural gas which,
based on geologic and engineering data, are estimated to be reasonably
recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those
which are expected to be recovered through existing wells with existing
equipment and operating methods. Because of inherent uncertainties
5
<PAGE> 59
and the limited nature of reservoir data, such estimates are subject to
change as additional information becomes available.
<TABLE>
<S> <C> <C>
Proved Oil and Gas Reserves at
June 30, 1999 Oil (Bbls) Gas (Mcf)
Proved reserves 8,148,000 14,736,000
========= ==========
Proved developed reserves 4,708,000 8,865,000
========= ==========
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows
("Standardized Measure") is prepared using assumptions required by the
Financial Accounting Standards Board. Such assumptions include the use
of period-end prices for oil and gas and period-end costs for estimated
future development and production expenditures to produce period-end
estimated proved reserves. Discounted future net cash flows are
calculated using a 10% rate.
The Standardized Measure does not represent the Company's estimate of
future net cash flows or the value of proved oil and gas reserves.
Probable and possible reserves, which may become proved in the future,
are excluded from the calculations. Furthermore, period-end prices,
used to determine the Standardized Measure, are influenced by seasonal
demand and other factors and may not be the most representative in
estimating future reserves or reserve data.
June 30, 1999 weighted average oil price used in the estimation of
proved reserves and calculation of the Standardized Measure was $15.75.
June 30, 1999 weighted average gas price was $2.32 per Mcf.
Standardized Measure of Discounted Future Net Cash Flows at June 30,
1999
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Future cash inflows $ 164,253
Future costs:
Production (29,873)
Development (20,828)
----------
Future net cash inflows 113,552
10% annual discount (61,654)
----------
Standardized measure of discounted future
Net cash flows before income taxes $ 51,898
==========
</TABLE>
6
<PAGE> 60
PETROGLYPH ENERGY, INC.
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
The accompanying Pro Forma Consolidated Financial Statements have been
prepared by recording pro forma adjustments to the historical
consolidated financial statements of Petroglyph Energy, Inc. ("the
Company"). The Pro Forma Consolidated Balance Sheet as of June 30, 1999
has been prepared as if the Antelope Creek Acquisition (as described in
Note 2) was consummated on January 1, 1998. The Pro Forma Consolidated
Statements of Operations for the year ended December 31, 1998 and for
the six months ended June 30, 1999 have been prepared as if the
Antelope Creek Acquisition (as described in Note 2) was consummated on
January 1, 1998.
The Pro Forma Consolidated Financial Statements are not necessarily
indicative of the financial position or results of operations that
would have occurred had the transactions been effected on the assumed
date. Additionally, future results may vary significantly from the
results reflected in the Pro Forma Consolidated Statements of
Operations due to normal production declines, changes in prices, future
transactions and other factors. These statements should be read in
conjunction with the Company's 1998 Form 10-K, the Company's
consolidated financial statements and the related notes for the six
months ended June 30, 1999 included in the Company's Form 10-Q for the
quarter ended June 30, 1999 and the statements of revenues and direct
operating expenses of the Antelope Creek Acquisition for the years
ended December 31, 1998, 1997, and 1996.
7
<PAGE> 61
PETROGLYPH ENERGY, INC.
PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF JUNE 30, 1999
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
------------ ------------ ------------
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 946,563 $ 1,131,011 (1) $ 2,077,574
Accounts receivable:
Oil and Gas Sales 278,556 -- 278,556
Other 39,111 -- 39,111
------------ ------------ ------------
Total Accounts Receivable 317,667 -- 317,667
Inventory 1,500,863 -- 1,500,863
Prepaid expenses and Other Current Assets 164,822 -- 164,822
------------ ------------ ------------
Total Current Assets 2,929,915 1,131,011 4,060,926
------------ ------------ ------------
Property and Equipment, Successful efforts method at cost:
Proved properties 31,913,848 6,900,000 (2) 38,813,848
Unproved properties 10,644,854 -- 10,644,854
Pipelines, gathering and other 10,360,832 -- 10,360,832
------------ ------------ ------------
52,919,534 6,900,000 59,819,534
Less: accumulated depreciation, depletion, and amortization (11,677,217) (836,358)(3) (12,513,575)
------------ ------------ ------------
Property and equipment, net 41,242,317 6,063,642 47,305,959
------------ ------------ ------------
Note receivable from officers 246,500 -- 246,500
Other assets, net 211,879 -- 211,879
------------ ------------ ------------
Total Assets $ 44,630,611 $ 7,194,653 $ 51,825,264
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 297,419 $ -- $ 297,419
Oil and natural gas sales payable 301,254 -- 301,254
Accrued taxes Payable 165,604 -- 165,604
Current portion of long-term debt -- -- --
Other 389,992 -- 389,992
------------ ------------ ------------
Total Current Liabilities 1,154,269 -- 1,154,269
------------ ------------ ------------
Long-term debt 8,000,000 6,802,350 (4) 14,802,350
Deferred Tax Liability - Long-term 360,858 95,054 (5) 455,912
Stockholders' equity:
Common Stock, par value $.01 per share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding 54,583 -- 54,583
Warrants outstanding -- 139,500 (6) 139,500
Paid-in-Capital 46,134,018 -- 46,134,018
Retained Earnings (deficit) (11,073,117) 157,749 (7)(8) (10,915,368)
------------ ------------ ------------
Total Stockholders' Equity 35,115,484 297,249 35,412,733
------------ ------------ ------------
Total Liabilities and Stockholders' Equity $ 44,630,611 $ 7,194,653 $ 51,825,264
============ ============ ============
</TABLE>
See Accompanying Notes to Pro Forma Consolidated Financial Statements.
8
<PAGE> 62
PETROGLYPH ENERGY, INC.
PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
------------ ------------ ------------
(Audited) (Unaudited) (Unaudited)
<S> <C> <C> <C>
Operating Revenues:
Oil sales $ 2,912,293 $ 2,221,828 (1) $ 5,134,121
Natural gas sales 1,365,850 937,205 (1) 2,303,055
Other 189,924 -- 189,924
------------ ------------ ------------
Total operating revenues 4,468,067 3,159,033 7,627,100
------------ ------------ ------------
Operating Expenses:
Lease operating 1,927,334 1,736,881 (1) (5) 3,664,215
Production taxes 218,129 170,715 (1) 388,844
Exploration Costs 192,526 -- 192,526
Depreciation, depletion, and amortization 1,866,111 619,529 (2) 2,485,640
Impairments 4,848,218 -- 4,848,218
General and administrative 2,128,774 236,438 (5) 2,365,212
------------ ------------ ------------
Total operating expenses 11,181,092 2,763,563 13,944,655
------------ ------------ ------------
Operating Gain (Loss) (6,713,025) 395,470 (6,317,555)
------------ ------------ ------------
Other Income (Expenses):
Interest Income (expense), net 406,975 (579,900)(3) (4) (172,925)
Gain (loss) on sales of property & equip, net 58,577 -- 58,577
------------ ------------ ------------
Net income (loss) before income taxes (6,247,473) (184,430) (6,431,903)
------------ ------------ ------------
Income Tax Expense (Benefit):
Current -- -- --
Deferred (2,061,666) (69,346)(6) (2,131,012)
------------ ------------ ------------
Total income tax (benefit) expense (2,061,666) (69,346) (2,131,012)
------------ ------------ ------------
Net Income (Loss) $ (4,185,807) $ (115,084) $ (4,300,891)
============ ============ ============
</TABLE>
See Accompanying Notes to Pro Forma Consolidated Financial Statements
9
<PAGE> 63
PETROGLYPH ENERGY, INC.
PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 1999
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues:
Oil sales $ 1,219,964 $ 946,342 (1) $ 2,166,306
Natural gas sales 625,039 324,424 (1) 949,463
Other 140,525 -- 140,525
----------- ----------- -----------
Total operating revenues 1,985,528 1,270,766 3,256,294
----------- ----------- -----------
Operating Expenses:
Lease operating 950,754 774,990 (1) (5) 1,725,744
Production taxes 99,997 94,818 (1) 194,815
Depreciation, depletion, and amortization 824,633 216,829 (2) 1,041,462
General and administrative 904,366 64,446 (5) 968,812
----------- ----------- -----------
Total operating expenses 2,779,750 1,151,083 3,930,833
----------- ----------- -----------
Operating Gain (Loss) (794,222) 119,683 (674,539)
----------- ----------- -----------
Other Income (Expenses):
Interest Income (expense), net (196,782) (289,950)(3) (4) (486,732)
Gain (loss) on sales of property & equip, net 876,842 607,500 (6) 1,484,342
----------- ----------- -----------
Net income (loss) before income taxes (114,162) 437,233 323,071
----------- ----------- -----------
Income Tax Expense (Benefit):
Current -- -- --
Deferred (29,085) 164,400 (7) 135,315
----------- ----------- -----------
Total income tax (benefit) expense (29,085) 164,400 135,315
----------- ----------- -----------
Net Income (Loss) Before Change in Accounting Principles: $ (85,077) $ 272,833 $ 187,756
Accounting Change - Expense of Start Up Costs (net of tax) (111,190) -- (111,190)
----------- ----------- -----------
Net Income (Loss) $ (196,267) $ 272,833 $ 76,566
=========== =========== ===========
</TABLE>
See Accompanying Notes to Pro Forma Consolidated Financial Statements
10
<PAGE> 64
PETROGLYPH ENERGY, INC.
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. BASIS OF PRESENTATION
The accompanying Pro Forma Consolidated Balance Sheet at June 30, 1999
and the Pro Forma Consolidated Statements of Operations for the year
ended December 31, 1998 and the six months ended June 30, 1999 have
been prepared assuming that Petroglyph Energy, Inc. ("the Company")
consummated the Antelope Creek Acquisition (see Note 2) on January 1,
1998. The Pro Forma Consolidated Statements of operations are not
necessarily indicative of the results of operations had the
above-described transactions occurred on the assumed date.
2. ACQUISITION
On August 20, 1999, the Company acquired the remaining 50% working
interest in the Antelope Creek Field in the Uinta Basin of Utah (the
"Antelope Creek Property") from its non-operated working interest
partner, Williams Production Rocky Mountain Company ("Williams"), for a
purchase price of $6.9 million (the "Antelope Creek Acquisition"). The
Antelope Creek Acquisition, which was effective August 1, 1999, gives
the Company a 100% working interest in the Antelope Creek Property.
In order to finance the Antelope Creek Acquisition, the Company
borrowed $2.5 million on an existing revolving credit facility with The
Chase Manhattan Bank ("Chase") pursuant to Amendment No. 1 dated as of
August 20, 1999 to the Second Amended and Restated Credit Agreement by
and between the Company and Chase dated as of September 30, 1998.
Additionally, the Company sold $5 million of 8% senior subordinated
notes due 2004 (the "Notes") to Intermountain. The Notes required the
Company to deliver to Intermountain a stock purchase warrant to acquire
150,000 shares of Common Stock of the Company at an exercise price of
$3.00 per share and the ability for Intermountain to obtain additional
stock purchase warrants over the life of the Notes. The number of
future stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The
maximum number of shares of Common Stock issuable under the stock
purchase warrants for any given period is limited to 250,000 shares in
any one year, 400,000 over the first three years and 750,000 over the
five-year life of the notes. The Company may redeem the Notes at par
without penalty at any time. Upon redemption of the Notes, any
remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining
purchase price of the Antelope Creek Acquisition and for working
capital needs.
3. PRO FORMA ADJUSTMENTS
The following are notes to the Pro Forma Consolidated Balance Sheet
dated June 30, 1999:
(1) To reflect pro forma cash flows from January 1, 1998 through
June 30, 1999:
<TABLE>
<S> <C>
Oil and natural gas sales $ 4,429,799
Production taxes (265,533)
LOE & G&A expenses (2,812,755)
Interest expense (828,000)
Sale of equipment 607,500
-----------
Net cash $ 1,131,011
-----------
</TABLE>
(2) The purchase price of the additional 50% working interest in
the Antelope Creek Field.
(3) Depreciation, depletion, and amortization expense for 18
months attributable to the Antelope Creek Acquisition.
(4) Additional borrowings to finance the Antelope Creek
Acquisition.
11
<PAGE> 65
(5) Income tax expense of $164,400 for six months of 1999 less
$69,346 tax benefit from the net loss in 1998 from operations
of the Antelope Creek Acquisition.
(6) To reflect the calculated value of a warrant to purchase
150,000 shares of Common Stock granted on the sale of Notes.
(7) To reflect the net loss (after income tax benefit) from
operations of the Antelope Creek Acquisition for 1998.
(8) To reflect the net income (after income tax expense) from
operations of the Antelope Creek Acquisition for the first six
months of 1999.
The following are notes to the Pro Forma Consolidated Statement of
Operations dated December 31, 1998:
(1) To add oil and natural gas revenues and volumes, production
taxes, and operating expenses attributable to the Antelope
Creek Acquisition for the period January 1, 1998 through
December 31, 1998.
(2) To reflect depreciation, depletion, and amortization expense
on the Antelope Creek Field as if the Company had owned a 100%
working interest for all of 1998.
(3) To add interest expense related to the debt required to
purchase the additional 50% of the Antelope Creek Field:
$6,900,000 at 8% interest outstanding for all of 1998.
(4) Includes $27,900 amortization of $139,500 calculated value of
a warrant to purchase 150,000 shares of Common Stock granted
on the sale of Notes.
(5) To reflect the increase in general and administrative expense
and decrease in lease operating expense resulting from owning
100% of the Antelope Creek Field and billing no overhead and
service income fees to third parties.
(6) The pro forma tax expense was computed at a combined rate of
37.6%.
The following are notes to the Pro Forma Consolidated Statement of
Operations dated June 30, 1999:
(1) To add oil and natural gas revenues and volumes, production
taxes, and operating expenses attributable to the Antelope
Creek Acquisition for the period January 1, 1999 through June
30, 1999.
(2) To reflect depreciation, depletion, and amortization expense
on the Antelope Creek Field as if the Company had owned a 100%
working interest for the first six months of 1999.
(3) To add interest expense related to the debt required to
purchase the additional 50% of the Antelope Creek Field:
$6,900,000 at 8% interest outstanding for the first six months
of 1999.
(4) Includes $13,950 amortization of $139,500 calculated value of
a warrant to purchase 150,000 shares of Common Stock granted
on the sale of Notes.
(5) To reflect the increase in general and administrative expense
and decrease in lease operating expense resulting from owning
100% of the Antelope Creek Field and billing no overhead and
service income fees to third parties.
(6) To reflect the sale of equipment in the first half of 1999
attributable to the Antelope Creek Acquisition.
(7) The pro forma tax expense was computed at a combined rate of
37.6%.
12
<PAGE> 66
APPENDIX III
ITEM 1. FINANCIAL STATEMENTS
PETROGLYPH ENERGY, INC
Consolidated Balance Sheets
(in thousands)
<TABLE>
<CAPTION>
ASSETS SEPTEMBER 30, DECEMBER 31,
1999 1998
-------------- --------------
(Unaudited) (Audited)
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 274 $ 2,008
Accounts receivable:
Oil and natural gas sales 758 265
Joint interest billing 30 835
Other 61 133
Inventory 1,363 1,234
Prepaid expenses 143 247
-------------- --------------
Total Current Assets 2,629 4,722
-------------- --------------
Property and Equipment, successful efforts method at cost:
Proved properties 39,424 32,191
Unproved properties 10,684 10,072
Pipelines, gas gathering and other 10,395 10,025
-------------- --------------
60,503 52,288
Less: Accumulated depletion, depreciation and amortization (12,090) (11,590)
-------------- --------------
Property and equipment, net 48,413 40,698
Other assets, net of accumulated amortization 284 615
-------------- --------------
Total Assets $ 51,326 $ 46,035
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 645 $ 2,088
Oil and natural gas sales 110 280
Current portion of long-term debt -- --
Other 309 403
-------------- --------------
Total Current Liabilities 1,064 2,771
-------------- --------------
Long-term Debt 15,363 7,500
Deferred Tax Liability 91 452
Stockholders' Equity:
Common Stock, par value $.01 par share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding 55 55
Warrants outstanding 140 --
Paid-in capital 46,134 46,134
Retained earnings (deficit) (11,521) (10,877)
-------------- --------------
Total Stockholders' Equity 34,808 35,312
-------------- --------------
Total Liabilities and Stockholders' Equity $ 51,326 $ 46,035
============== ==============
</TABLE>
See accompanying notes to consolidated financial statements.
-2-
<PAGE> 67
PETROGLYPH ENERGY, INC
Consolidated Statements of Operations
(in thousands, except per share data)
(Unaudited)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- ------------------------------
1999 1998 1999 1998
---------------- -------------- --------------- --------------
<S> <C> <C> <C> <C>
Operating Revenues:
Oil sales $ 1,139 $ 728 $ 2,359 $ 2,221
Natural gas sales 310 349 936 949
Other 62 49 202 122
---------------- -------------- --------------- --------------
Total operating revenues 1,511 1,126 3,497 3,292
Operating Expenses:
Lease operating 831 443 1,782 1,480
Production taxes 120 53 220 154
Exploration costs 21 - 21 -
Depletion, depreciation and amortization 423 482 1,248 1,373
General and administrative 626 525 1,530 1,535
---------------- -------------- --------------- --------------
Total operating expenses 2,021 1,503 4,801 4,542
---------------- -------------- --------------- --------------
Operating loss (510) (377) (1,304) (1,250)
Other Income:
Interest income (expense), net (190) 50 (387) 393
Gain on sales of property and equipment, net (17) 3 860 59
---------------- -------------- --------------- --------------
Net loss before income taxes (717) (324) (831) (798)
Income Tax Benefit:
Deferred (270) (97) (299) (282)
Current - - - -
---------------- -------------- --------------- --------------
Total income tax benefit (270) (97) (299) (282)
---------------- -------------- --------------- --------------
Net loss before change in accounting principle (447) (227) (532) (516)
Change in accounting principle (net of income tax effect) - - (111) -
---------------- -------------- --------------- --------------
Net loss $ (447) $ (227) $ (643) $ (516)
================ ============== =============== ==============
Net loss per common share before change in accounting
principle, basic and diluted $ (0.08) $ (0.04) $ (0.10) $ (0.09)
Net loss per common share from change in accounting principle $ - $ - $ (0.02) $ -
---------------- -------------- --------------- --------------
Net loss per common share, basic and diluted $ (0.08) $ (0.04) $ (0.12) $ (0.09)
================ ============== =============== ==============
Weighted average common shares outstanding 5,458,333 5,458,333 5,458,333 5,458,333
================ ============== =============== ==============
</TABLE>
See accompanying notes to consolidated financial statements.
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<PAGE> 68
PETROGLYPH ENERGY, INC
Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------
1999 1998
-------------- ------------
<S> <C> <C>
Operating Activities:
Net loss before income taxes $ (643) $ (516)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization 1,263 1,373
Gain on sales of property and equipment, net (859) (59)
Exploration costs 21 --
Expense of capitalized organization costs
due to change in accounting principle 173 --
Write-off of officer note receivable 176 --
Deferred taxes (361) (282)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable 359 (1,226)
Increase in inventory (183) (507)
(Increase) decrease in prepaid expenses 104 (167)
Decrease in accounts payable and
accrued liabilities (1,707) (417)
---------- ----------
Net cash used in operating activities: (1,657) (1,801)
---------- ----------
Investing Activities:
Proceeds from sales of property and equipment 1,503 88
Additions to oil and natural gas properties, including
exploration costs (9,005) (13,583)
Additions to pipelines, natural gas gathering and other (561) (1,435)
---------- ----------
Net cash used in investing activities (8,063) (14,930)
---------- ----------
Financing Activities:
Proceeds from issuance of, and draws on, notes payable 8,000 2,000
Payments on notes payable -- (37)
Payments for financing costs (14) (46)
---------- ----------
Net cash provided by financing activities 7,986 1,917
---------- ----------
Net decrease in cash and cash equivalents (1,734) (14,814)
Cash and Cash Equivalents, beginning of period 2,008 16,679
---------- ----------
Cash and Cash Equivalents, end of period $ 274 $ 1,865
========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
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<PAGE> 69
PETROGLYPH ENERGY, INC.
Notes to Consolidated Financial Statements
(1) ORGANIZATION AND BASIS OF PRESENTATION
Petroglyph Energy, Inc. ("Petroglyph" or the "Company") was incorporated in
Delaware in April 1997 for the purpose of consolidating and continuing the
activities previously conducted by Petroglyph Gas Partners, L.P. ("PGP" or the
"Partnership"). PGP was a Delaware limited partnership, which was organized on
April 15, 1993 to acquire, explore for, produce and sell oil, natural gas and
related hydrocarbons. The sole general partner of PGP was Petroglyph Energy,
Inc., a Kansas corporation ("PEI"). Petroglyph Gas Partners II, L.P. ("PGP II")
was 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 sole general partner of PGP II was PEI (1% interest) and the
sole limited partner was PGP (99% interest). Pursuant to the terms of an
Exchange Agreement dated August 22, 1997 (the "Exchange Agreement"), the Company
acquired all of the outstanding partnership interests of the Partnership and all
of the stock of PEI in exchange for shares of Common Stock of the Company (the
"Conversion"). The Conversion and other transactions contemplated by the
Exchange Agreement were consummated on October 24, 1997, immediately prior to
the closing of the initial public offering of the Company's Common Stock (the
"Offering"). The Conversion was accounted for as a transfer of assets and
liabilities between affiliates under common control in October 1997 and resulted
in no change in carrying values of these assets and liabilities.
On June 30, 1998, all properties owned by PGP, PGP II, and PEI were
transferred into the Company and the three entities (PGP, PGP II, and PEI) were
dissolved.
The accompanying consolidated financial statements of Petroglyph include
the assets, liabilities and results of operations of its wholly owned
subsidiary, Petroglyph Operating Company, Inc. ("POCI"). POCI is a subchapter C
corporation. POCI is the designated operator of all wells for which the Company
has acquired operating rights. Accordingly, all producing overhead and
supervision fees were charged to the joint accounts by POCI. All material
intercompany transactions and balances have been eliminated in the preparation
of the accompanying consolidated financial statements.
The Company's operations are primarily focused in the Uinta Basin of Utah
and the Raton Basin of Colorado with additional operations in DeWitt and
Victoria Counties in South Texas.
The accompanying consolidated financial statements of Petroglyph, with the
exception of the consolidated balance sheet at December 31, 1998, have not been
audited by independent public accountants. In the opinion of the Company's
management, the accompanying consolidated financial statements reflect all
adjustments necessary to present fairly the financial position at September 30,
1999 and the related results of operations for the three month and nine-month
periods ended September 30, 1999 and 1998. All such adjustments are of a normal
recurring nature. These interim results are not necessarily indicative of
results for a full year.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules and
regulations of the Securities and Exchange Commission.
(2) SIGNIFICANT EVENTS
A. CHANGE OF CONTROL
On August 18, 1999, III Exploration Company, an Idaho corporation ("III"),
completed the purchase (the "Purchase") from Robert A. Christensen, a director
and executive officer of the Company, David R. Albin, a director of the Company,
Kenneth A. Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster,
Bruce B. Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural
Gas Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of common stock, $.01 par value of the Company.
According to the Schedule 13D filed with the Securities and Exchange
Commission by III on August 30, 1999, III is controlled by Intermountain
Industries, Inc., an Idaho corporation ("Intermountain"). The stock purchase was
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<PAGE> 70
effected through a privately negotiated sale between the Sellers and
Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999 (collectively, the "Agreement"), with a purchase price of $3.00
per share. The source of funds for the Purchase came from working capital of
Intermountain. As a result of the Purchase, Intermountain, through its ownership
of III, now owns approximately 50.4% of the outstanding Common Stock of the
Company.
Intermountain, a closely-held holding company exempt from the provisions of
the Public Utility Holding Company Act of 1935, except for Section 9(a)(2),
through its subsidiaries operates the largest natural gas distribution utility
in Idaho, the largest end-use natural gas marketing business in the northwest
United States and has producing oil and gas properties in the Rocky Mountain
region, including the Uinta Basin of Utah.
Related to the sale, David Albin, Kenneth Hersh and Robert Christensen
tendered their resignations from the Company's Board of Directors. Mr.
Christensen also resigned as an executive officer of the Company, but will
remain as an engineering advisor. After discussing the resignations with
Intermountain, the remaining members of the Company's Board of Directors
nominated William C. Glynn, Richard Hokin and Eugene C. Thomas, who are also
members of Intermountain's Board of Directors, to fill the vacancies created on
the Board of Directors by the resignations.
B. ANTELOPE CREEK ACQUISITION
During August 1999, Petroglyph Energy, Inc. acquired the remaining 50%
working interest in the Antelope Creek Field in the Uinta Basin of Utah (the
"Antelope Creek Property") from its non-operated working interest partner,
Williams Production Rocky Mountain Company ("Williams"), for a purchase price of
$6.9 million (the "Antelope Creek Acquisition"). The Antelope Creek Acquisition,
which was effective August 1, 1999, gives the Company a 100% working interest in
the Antelope Creek Property.
(3) LONG-TERM DEBT
Effective September 30, 1998, the Company entered into a credit agreement
with the Chase Manhattan Bank ("Chase") (the "Credit Agreement"). The Credit
Agreement established a credit facility for the Company of up to $50.0 million
with a two-year revolving line and a borrowing base to be redetermined
quarterly. The revolving credit facility expires on September 30, 2000, at which
time all outstanding balances will convert to a term loan expiring on September
30, 2003. Interest on outstanding borrowings is calculated, at the Company's
option, at either Chase's prime rate or the London Interbank Offer Rate plus a
margin determined by the amount outstanding under the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition, the
borrowing base was increased to $11.0 million and the quarterly redetermination
scheduled for September 30, 1999 was waived. The next redetermination is
scheduled to occur on or before December 31, 1999.
In order to finance the Antelope Creek Acquisition, the Company and Chase
entered into Amendment No. 1 to the Credit Agreement, dated as of August 20,
1999, pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III. The Notes required the Company to deliver to III
a stock purchase warrant to acquire 150,000 shares of Common Stock of the
Company at an exercise price of $3.00 per share and the ability for III to
obtain additional stock purchase warrants over the life of the Notes. The number
of future stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The maximum
number of shares of Common Stock issuable under the stock purchase warrants for
any given period is limited to 250,000 shares in any one year, 400,000 over the
first three years and 750,000 over the five-year life of the notes. The Company
may redeem the Notes at par without penalty at any time. Upon redemption of the
Notes, any remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining purchase
price of the Antelope Creek Acquisition and for working capital needs.
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<PAGE> 71
(4) COMMITMENTS
The Company has hedged a portion of its future production with crude oil
collars based on a floor price and a ceiling price indexed to the NYMEX light
crude future settlement price. Oil hedge contracts currently in place are:
<TABLE>
<CAPTION>
DURATION VOLUME FLOOR CEILING
-------- ------ ------ -------
<S> <C> <C> <C> <C>
January 1999 - December 1999 13,250 Bbl/month $17.00 $22.00
January 2000 - December 2000 12,000 Bbl/month $17.00 $20.00
AVERAGE PRICE
-------------
September 1999 - December 1999 12,000 Bbl/month $21.00
January 2000 - June 2000 12,000 Bbl/month $20.05
</TABLE>
The Company has contracted for the sale of its natural gas production and
taken hedge positions to effect the following volumes and prices:
<TABLE>
<CAPTION>
DURATION VOLUME AVERAGE PRICE
-------- ------ -------------
<S> <C> <C> <C>
Utah: October 1999 - September 2000 1,500 MMBtu/day $2.01 MMBtu ($2.33 MCF)
Texas: August 1999 - March 2000 1,000 MMBtu/day $2.2275 MMBtu ($2.29 MCF)
April 2000 - March 2001 1,000 MMBtu/day $2.2425 MMBtu ($2.31 MCF)
</TABLE>
The Company uses price hedging arrangements and fixed price natural gas
sales contracts as described above to reduce price risk on a portion of its oil
and natural gas production.
In September 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for fiscal years beginning after June 15, 2000. With its
current hedge contracts, management believes SFAS No. 133 will have no impact on
the financial statements of the Company.
During July 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately
37 miles of 10-inch steel pipeline from near Trinidad, Colorado to the Company's
Raton Basin coalbed methane development area approximately 6 miles southwest of
Walsenburg, Colorado. The pipeline was placed in service in January 1999 with a
delivery capacity of approximately 50 MMcf per day and would provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company has committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity beginning February 1, 1999
and ending January 31, 2009. The commitment begins at a minimum volume of
2,000 Mcf per day and increases after each three-month period by 1,000 Mcf per
day, with a maximum commitment of 10,000 Mcf per day. At the end of the first
two-year period the Company has the option to: 1) continue the agreement with a
minimum volume of 16,000 Mcf per day, 2) increase the minimum volume to
32,000 Mcf per day, or 3) eliminate the commitment. The cost of eliminating the
commitment is the cost of the pipeline ($6.4 million) less a credit applied for
the Company's Raton Basin commercial gas production up to 16,000 Mcf per day.
This cost could be applied as a credit to transportation elsewhere on CIG's
system. The Company can reduce the minimum monthly commitment by selling its
available pipeline capacity at market rates. Net commitment fees paid to CIG
totaling $82,000 and $151,000 for the three and nine-month periods ending
September 30, 1999, respectively, are reflected as lease operating expense in
the Company's consolidated statements of operations.
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<PAGE> 72
ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. The
Company's strategy is to increase its reserves, production and cash flow through
(i) the development of its drillsite inventory, (ii) the exploitation of its
existing reserve base, (iii) the control of operations of its core properties,
(iv) the acquisition of additional property interests, and (v) the development
of a strong financial position that affords the Company the financial
flexibility to execute its business strategy.
OPERATING DATA
The following table sets forth certain operating data of the Company for
the periods presented.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Production Data:
Oil (Bbls)........................ 64,838 67,131 158,329 201,644
Natural gas (Mcf)................. 160,476 180,936 489,480 473,604
Total (BOE)....................... 91,584 97,287 239,909 280,578
Average Daily Production:
Oil (Bbls)........................ 705 730 580 739
Natural gas (Mcf)................. 1,744 1,967 1,793 1,735
Total (BOE)....................... 995 1,057 879 1,028
Average Sales Price per Unit (1):
Oil (per Bbl) (2)................. $ 17.56 $ 10.84 $ 14.90 $ 11.01
Natural gas (per Mcf)............. $ 1.94 $ 1.93 $ 1.91 $ 2.00
Costs Per BOE:
Lease operating expenses.......... $ 9.08 $ 4.56 $ 7.43 $ 5.27
Production and property taxes..... $ 1.31 $ 0.55 $ 0.92 $ 0.55
Depletion, depreciation and
amortization................... $ 4.62 $ 4.95 $ 5.20 $ 4.89
General and administrative........ $ 6.83 $ 5.39 $ 6.38 $ 5.47
</TABLE>
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<PAGE> 73
(1) Before deduction of production taxes.
(2) Excluding the effects of crude oil hedging transactions, the weighted
average sales price per Bbl of oil was $18.45 and $9.25 for the three
months, and $14.27 and $9.86 for the nine months ended September 30, 1999
and 1998, respectively.
Bbl - Barrel
Mcf - Thousand cubic feet
BOE - Barrels of oil equivalent (six Mcf equal one Bbl)
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, costs of
geological, geophysical and seismic testing, 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.
One gross (.5 net) well was drilled as a dry hole in South Texas and no
wells were completed during the three months ended September 30, 1999. This
compares with 12 gross and net wells drilled and 12 gross (9.5 net) wells
completed during the three months ended September 30, 1998.
RESULTS OF OPERATIONS
Three Months Ended September 30, 1999 Compared to Three Months Ended
September 30, 1998
OPERATING REVENUES
Third quarter 1999 operating revenues increased 34% to $1,511,000 compared
to $1,126,000 for the same period in 1998. Oil prices during the third quarter
1999 increased $6.72 (62%) to $17.56 per barrel compared to the third quarter
1998. This price includes a third quarter hedge loss of $0.89 per barrel in 1999
compared to $1.59 hedge gain in 1998. The gas price was essentially flat between
periods at $1.94 and $1.93 per Mcf for 1999 and 1998, respectively. However, the
1999 third quarter price includes $0.35 per Mcf hedge loss. There was no gas
hedge effect for the 1998 period.
Oil sales volumes declined 3% to 64,800 Bbls and gas volumes fell 11% to
160,500 Mcf in the third quarter of 1999 compared to the 1998 period. Third
quarter 1999 sales include volumes totaling 24,393 Bbls and 27,023 Mcf
attributable to the purchase of 50% of the Antelope Creek Field. Excluding the
Antelope Creek Acquisition, oil sales volumes declined 40% from the prior year
due to suspension of development in the Antelope Creek Field mid-year 1998
coupled with the conversion of six wells from producers to injectors between
periods.
OPERATING EXPENSES
Lease operating expense for the third quarter 1999 of $831,000 was $388,000
(87%) greater than the comparable period in 1998. The 1999 figure includes
$106,000 in compressor rentals attributable to the sale of the Texas and
Antelope Creek compressors, $82,000 in CIG commitment fees, and $272,000 in
lease operating expense attributable to the Antelope Creek Acquisition. None of
these costs were present in the third quarter of 1998. As a result of these
increases and the production declines noted above, average LOE rose $4.52 to
$9.08 per barrel.
Third quarter 1999 general and administrative expense increased 19% to
$626,000 compared to the comparable quarter in 1998. This amount included a
one-time, non-cash charge of $176,000 associated with forgiveness of debt owed
to the Company by a former executive officer. In exchange for the debt
forgiveness, the officer relinquished his rights under a severance agreement,
which had a potential cash value of $250,000. Absent this charge, general and
administrative expense decreased $75,000 to $450,000 compared to $525,000 for
the third quarter of 1998 as a result of cost reduction measures implemented in
the first quarter of 1999.
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<PAGE> 74
OTHER INCOME (EXPENSE)
Other operating revenues increased to $62,000 during the third quarter 1999
from $49,000 for the same period in 1998. Gas transportation income from Texas
wells is the principal reason for this increase.
Net interest expense for the third quarter 1999 was $190,000 compared to
net interest income of $50,000 for third quarter 1998. This represents the
decline in invested cash after the Offering to a net debt position at the end of
1998.
RESULTS OF OPERATIONS
Nine Months Ended September 30, 1999 Compared to Nine Months Ended
September 30, 1998
OPERATING REVENUE
Operating revenues of $3,497,000 for the first nine months of 1999 were 6%
greater than revenues for the same period in 1998. The average year to date oil
price for 1999 was $14.90 per barrel, inclusive of $0.63 per barrel hedge gain.
This compares to $11.01 per barrel for the 1998 period, including $1.16 per
barrel hedge gain. Not including hedging adjustments, the Company's average oil
price rose 45% between periods. The average realized gas price for the first
nine months of 1999 was $1.91 per Mcf after subtracting $0.14 per Mcf hedge
loss. For the same period in 1998 the average gas price was $2.00 per Mcf with
no hedge adjustments.
Oil sales volumes fell 21% to 158,300 barrels for the first nine months of
1999 compared to 201,600 barrels for the same period in 1998. Excluding the
Antelope Creek Acquisition, oil sales volumes declined 34% from the prior year
due to suspension of development in the Antelope Creek Field mid-year 1998
coupled with the conversion of six wells from producers to injectors since the
end of the third quarter 1998. A similar decline in Antelope Creek gas
production was mitigated by gas sales from wells drilled in the fourth quarter
of 1998 and the first quarter of 1999 in the Helen Gohlke Field in Texas.
Company gas sales for the first nine months of 1999 of 489,500 Mcf were 3%
greater than gas sales for the same period in 1998.
OPERATING EXPENSES
Lease operating expenses increased 20% to $1,782,000 for the first nine
months of 1999 compared to $1,480,000 for the comparable period in 1998. LOE for
1999 includes $151,000 in CIG commitment fees, $226,000 in compressor rentals,
and $272,000 in lease operating expense attributable to the Antelope Creek
Acquisition. None of these costs were present in the first nine months of 1998.
Absent these charges, which are not comparable between periods, LOE decreased
$347,000, or 23%, between the first nine months of 1999 and the same period in
1998.
Because of the operating expense increases and production declines noted
above, LOE per barrel rose $2.16 to $7.43 per BOE for the first nine months of
1999 compared to the same period in 1998.
Year to date general and administrative expense for 1999 of $1,530,000 was
essentially flat to the comparable period in 1998. However, the 1999 figure
included a one-time, non-cash charge of $176,000 associated with forgiveness of
debt owed to the Company by a former executive officer. In exchange for the debt
forgiveness, the officer relinquished his rights under a severance agreement,
which had a potential cash value of $250,000. Cost reductions begun in the
fourth quarter of 1998 and completed in 1999 have resulted in decreased general
and administrative expense. The 1999 amounts include $82,000 in severance costs
incurred during the first half of year. Not including these unusual items,
general and administrative expense decreased $253,000, or 17%, between the
nine-month periods of 1999 and 1998.
OTHER INCOME (EXPENSES)
Other operating income, principally natural gas transportation revenues,
rose 66% to $202,000 for the first nine months of 1999 compared to the same
period in 1998. This increase is due to gas transported from the new Texas wells
mentioned above.
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<PAGE> 75
Net interest expense for the first nine months of 1999 was $387,000,
compared to net interest income of $393,300 for the same period in 1998. This
represents the decline in invested cash after the Offering to a net debt
position at the end of 1998.
Gain on sale of property was $860,000 for the first nine months of 1999
compared to $59,000 for the comparable 1998 period due to an increase in asset
sales activity between periods.
CHANGE IN ACCOUNTING PRINCIPLE
The Company is required to comply with Statement of Position ("SOP") 98-5,
Reporting on the Costs of Start-Up Activities, for fiscal years beginning after
December 15, 1998. This SOP requires start-up and organizational costs be
expensed as incurred. It also requires start-up and organizational costs
previously capitalized be expensed and that the resulting one-time expense be
accounted for as a change in accounting principle. Accordingly, the Company has
shown as a change in accounting principle an $111,000 expense, which represents
net capitalized organizational costs of $173,000 and the associated income tax
benefit of $62,000.
SIGNIFICANT EVENTS
CHANGE OF CONTROL
On August 18, 1999, III Exploration Company, an Idaho corporation ("III"),
completed the purchase from Robert A. Christensen, a director and executive
officer of the Company, David R. Albin, a director of the Company, Kenneth A.
Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster, Bruce B.
Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural Gas
Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of common stock, $.01 par value of the Company.
According to the Schedule 13D filed with the Securities and Exchange
Commission by III on August 30, 1999, III is controlled by Intermountain
Industries, Inc., an Idaho corporation ("Intermountain"). The stock purchase was
effected through a privately negotiated sale between the Sellers and
Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999 (collectively, the "Agreement"), with a purchase price of $3.00
per share. The source of funds for the Purchase came from working capital of
Intermountain. As a result of this purchase, Intermountain, through its
ownership of III, now owns approximately 50.4% of the outstanding Common Stock
of the Company.
CHANGES IN BOARD OF DIRECTORS
Related to the sale, David Albin, Kenneth Hersh and Robert Christensen
tendered their resignations from the Company's Board of Directors. Mr.
Christensen also resigned as an executive officer of the Company, but will
remain as an engineering advisor. After discussing the resignations with
Intermountain, the remaining members of the Company's Board of Directors
nominated William C. Glynn, Richard Hokin and Eugene C. Thomas, who are also
members of Intermountain's Board of Directors, to fill the vacancies created on
the Board of Directors by the resignations.
Since 1982, Richard Hokin, 59, has been a member of the board of
Intermountain and has served as Chairman of it and of each of its subsidiaries
since 1984. Mr. Hokin has been a director of Displaytech, Inc., a developer and
manufacturer of microelectronic displays, since 1995. He has held the position
of Managing Partner of Century Partners, an investment partnership, since 1996.
From 1984 through 1987, Mr. Hokin served as a Director of the Pacific Coast Gas
Association.
William C. Glynn, 54, has served as President of Intermountain and each of
its subsidiaries from 1987 to the present. Mr. Glynn is a member of and has
served as Chairman of the Board of Directors of the Pacific Coast Gas
Association. He is also a member of the Board of Directors of the American Gas
Association.
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<PAGE> 76
Eugene C. Thomas, 68, has served on the Board of Directors of Intermountain
and of each of its subsidiaries since 1984. Mr. Thomas is a partner of Moffatt,
Thomas, Barrett, Rock & Fields, Chtd. and he has acted as general counsel to
Intermountain since 1978. Mr. Thomas is a member of the American Bar Association
and served as its President for 1986-87.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities was $1,657,000 for the nine months ended
September 30, 1999. Current liabilities were reduced $1,707,000. Thus far in
1999 the Company has realized cash of $1,503,000 from the sale of Texas and
Antelope Creek Field compression facilities, surplus vehicles and inventory, and
non-core properties.
The Company expects to generate cash from operations, asset sales,
increased availability under its Credit Agreement, if any, and other capital
sources. The Company believes that a combination of these sources and current
cash on hand will be adequate to support its budgeted working capital and
discretionary capital expenditure programs for at least the next 12 months. The
Company is actively pursuing capital to fund its drilling, development, and
acquisition plans and, if successful, intends to proceed with the further
development of its properties.
CAPITAL EXPENDITURES
During the first nine months of 1999, the Company converted 2 gross (1 net)
producing wells in the Antelope Creek Field to water injectors and began
returning shut-in wells to producing status as a result of oil price increases.
Management believes oil volume declines in the Antelope Creek Field have been
arrested with the recent well remediation program and expects Antelope Creek
Field waterflood response to continue to improve as water injection continues.
Depending on available capital the Company intends to spend up to $6.0 million
converting as many as 34 wells to injectors and drilling up to 8 new wells
during the remainder of 1999 and all of 2000 to increase the field-wide water
injection pattern and enhance production.
In the first half of 1999, the Company completed its water disposal and gas
gathering system infrastructure in the Raton Basin. During the third quarter of
1999, the Company increased the daily water withdrawal rate from the 17 pilot
area wells to approximately 37,000 barrels per day as a result of obtaining a
surface discharge permit from the State of Colorado. The permit provides for a
total discharge rate of up to 240,000 barrels per day, and the Company can
further increase pilot area withdrawal rates by increasing water pump capacity
at individual wells. By the end of the third quarter of 1999, total water
removed from the pilot area wells was 8.2 million barrels. Measured reservoir
pressures had been reduced by approximately 85 psi. The Company has estimated
that commercial gas production will require a reservoir pressure reduction of
approximately 200 psi. All coalbed methane wells in the pilot area are currently
producing some volumes of natural gas, and two wells are now supplying enough
gas to fuel the engines that power their water pumping systems. Currently the
field is producing a total of approximately 100 Mcf per day. While not
commercial in quantity, the gas volumes are being recovered and utilized to
offset fuel costs. Reservoir pressure testing is currently in process which
management believes will allow the Company to understand how much longer it may
take to reduce the pilot area reservoir pressure to the targeted 200 psi
pressure drop and achieve commercial volumes of gas production.
During the first nine months of 1999, the Company drilled 4 gross (2.5 net)
wells and completed 2 gross (1 net) wells in the Helen Gohlke Field in Victoria
and Dewitt Counties, Texas. One gross and net well was a dry hole and was
accrued as exploration expense in 1998; one gross (.5 net) well was expensed as
a dry hole in 1999. This property, which is non-core to the Company's reserve
development strategy, is currently offered for sale.
On August 20, 1999, the Company acquired the remaining 50% working interest
in the Antelope Creek Field in the Uinta Basin of Utah from its non-operated
working interest partner, Williams Production Rocky Mountain Company, for a
purchase price of $6.9 million. This purchase, which was effective August 1,
1999, gives the Company a 100% working interest in the Antelope Creek Property.
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<PAGE> 77
FINANCING
Effective September 30, 1998, the Company entered into the Credit Agreement
with Chase. The Credit Agreement established a credit facility for the Company
of up to $50.0 million with a two-year revolving line and a borrowing base to be
redetermined quarterly. The revolving credit facility expires on September 30,
2000, at which time all outstanding balances will convert to a term loan
expiring on September 30, 2003. Interest on outstanding borrowings is
calculated, at the Company's option, at either Chase's prime rate or the London
Interbank Offer Rate plus a margin determined by the amount outstanding under
the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition, the
borrowing base was increased to $11.0 million and the quarterly redetermination
scheduled for September 30, 1999 was waived. The next redetermination is
scheduled to occur on or before December 31, 1999.
In order to finance the Antelope Creek Acquisition, the Company and Chase
entered into Amendment No. 1 to the Credit Agreement dated as of August 20, 1999
pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III. The Notes required the Company to deliver to III
a stock purchase warrant to acquire 150,000 shares of Common Stock of the
Company at an exercise price of $3.00 per share and the ability for III to
obtain additional stock purchase warrants over the life of the Notes. The number
of future stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The maximum
number of shares of Common Stock issuable under the stock purchase warrants for
any given period is limited to 250,000 shares in any one year, 400,000 over the
first three years and 750,000 over the five-year life of the notes. The Company
may redeem the Notes at par without penalty at any time. Upon redemption of the
Notes, any remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining purchase
price of the Antelope Creek Acquisition and for working capital needs.
YEAR 2000 ISSUES
The Company is aware of the potential for disruption of its business as a
result of the failure of computer systems which will not properly recognize "00"
in date sensitive information when the year changes to 2000. Such failures are
collectively characterized as the "Year 2000 issue".
Management of the Company has formed a Year 2000 Team (the "Team"),
consisting of managers and knowledgeable employees, to assess and identify the
potential risks of the Year 2000 issue on the Company and to take the necessary
actions to nullify, as much as possible, the impact of the Year 2000 issue. The
Team has developed a program focusing on the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and governmental
entities
The information technology and systems of the Company are believed to be
Year 2000 compliant. Software upgrades and service releases supplied by vendors
have been installed. The processing ability of hardware and computer equipment
with embedded technology has been successfully tested. Most of these upgrades
were system replacements conducted in 1996 and 1997 to improve business
efficiencies and functionality and were not undertaken solely to address the
Year 2000 issues. As such, management believes the Year 2000 issues with respect
to the Company's information technology and systems will not have a significant
effect on the Company's financial position or operations.
The process controls and embedded technology area is essentially complete.
Field level processors, meters and equipment utilized by the Company are not
expected to contain embedded technology such as microprocessors. However, the
Company continues to conduct internal evaluations and hold discussions with
suppliers to ensure appropriate measures are taken to minimize the impact to
operations caused by any unidentified company or third party Year 2000 issues.
The Company also relies on non-information technology systems such as
telephones, facsimile machines, security
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<PAGE> 78
systems and other equipment which may have embedded technology such as
microprocessors, which may or may not be Year 2000 compliant. Management
believes any such disruption is not likely to have a significant effect on the
Company's financial position or operations.
Formal communications have been initiated with vendors, suppliers,
customers and others with whom the Company has significant business
relationships. Approximately 85% of correspondents responded. The Team continues
to evaluate responses and make additional inquiries as needed. The Company is
not currently aware of any third party issues that would cause a significant
business disruption.
The total cost of the Company's Year 2000 program is not expected to be
material to the Company's financial position. The Company anticipates spending
less than $10,000 during the remainder of 1999 for Year 2000 related
modifications and testing.
The Company continues to develop its contingency plans in the unlikely
event that portions of its Year 2000 program are inadequate. The Company
believes that the most likely worst-case Year 2000 scenarios are as follows: (i)
unanticipated Year 2000 induced failures in information systems could cause a
reliance on manual contingency procedures and significantly reduce efficiencies
in the performance of certain normal business activities; and (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
developed to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At September 30, 1999, the Company currently has oil and gas hedge
contracts in place further described in Note 4 (Commitments) to Consolidated
Financial Statements. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company uses hedging
contracts to manage its price risk and limit exposure to short-term fluctuations
in commodity prices. However, should NYMEX oil prices rise above the ceiling
prices in effect for the periods mentioned above, the Company would not receive
the marginal benefit of oil prices in excess of the ceiling prices.
Additionally, the Company is subject to interest rate risk, as $10.5
million owed at September 30, 1999 under the Company's revolving credit facility
accrues interest at floating rates tied to LIBOR. The Company's current average
rate is approximately 7.96%, locked in for 90-day terms.
The Company performed a sensitivity analysis to assess the potential effect
of commodity price risk and interest rate risk and determined that the effect,
if any, of reasonably possible near-term changes in NYMEX oil prices or interest
rates on the Company's financial position, results of operations and cash flow
should not be material.
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<PAGE> 79
PETROGLYPH ENERGY, INC.
1302 NORTH GRAND
HUTCHINSON, KANSAS 67501
THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS
The undersigned stockholder of Petroglyph Energy, Inc., a Delaware
corporation (the "Company"), hereby appoints Robert C. Murdock and Tim A. Lucas,
or either of them, the proxy or proxies of the undersigned, each with full power
of substitution, to vote all shares of Common Stock of the Company which the
undersigned would be entitled to vote at the Special Meeting of Stockholders to
be held on Tuesday, February 15, 2000 at 9:00 a.m., Central Standard Time at the
Kansas Cosmosphere & Space Center, 1100 North Plum Street, Hutchinson, Kansas
67501, or any adjournment thereof, according to the number of votes that the
undersigned would be entitled to if personally present upon the matters referred
to in this proxy.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE "FOR" EACH OF THE PROPOSALS.
1. PROPOSAL 1--Approval of the issuance of (a) 250,000 shares of Series A
Convertible Preferred Stock, par value $.01 per share (the "Preferred
Shares"), to III Exploration Company, an affiliate of the Company, in
exchange for certain oil and gas producing properties primarily located
in the Uinta Basin of Utah; and (b) shares of Common Stock, par value
$.01 per share, upon the potential conversion of such Preferred Shares.
[ ] FOR [ ] AGAINST [ ] ABSTAIN
(CONTINUED AND TO BE SIGNED ON OTHER SIDE)
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<PAGE> 80
(CONTINUED FROM OTHER SIDE)
This Proxy when properly executed will be voted in the manner directed
herein by the undersigned stockholder. If no direction is made, this proxy will
be voted FOR the proposals set forth herein.
The undersigned acknowledges receipt of Notice of Special Meeting of
Stockholders dated January 14, 2000, and the accompanying Proxy Statement.
Date: , 2000
--------------------------------------------
Signature
--------------------------------------------
Name(s) (typed or printed)
--------------------------------------------
--------------------------------------------
Address(es)
Please sign exactly as name appears on this Proxy. When shares are held
by joint tenants, both should sign. When signing as attorney, executor,
administrator, trustee or guardian, please give full title as such. If
a corporation, please sign in full corporate name by the President or
other authorized officer. If a partnership, please sign in partnership
name by authorized person.
PLEASE MARK, SIGN, DATE AND RETURN THE PROXY CARD PROMPTLY USING THE
ENCLOSED ENVELOPE. NO POSTAGE IS REQUIRED IF MAILED IN THE UNITED
STATES.
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