<PAGE>
Filed pursuant to Rule 424(b)(4)
SEC File No. 333-34251
PROSPECTUS
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2,500,000 Shares
LOGO PETROGLYPH ENERGY, INC.
Common Stock
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All of the shares of the Common Stock, $.01 par value (the "Common Stock"),
offered hereby (the "Offering") are being sold by Petroglyph Energy, Inc., a
Delaware corporation ("Petroglyph" or the "Company").
Prior to this Offering, there has been no public market for the Common Stock
of the Company. See "Underwriting" for a discussion of the factors considered
in determining the initial public offering price. The Common Stock has been
approved for inclusion in The Nasdaq Stock Market's National Market (the
"Nasdaq National Market") under the trading symbol "PGEI."
SEE "RISK FACTORS" ON PAGES 10 TO 18 FOR A DISCUSSION OF MATERIAL FACTORS THAT
SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON STOCK
OFFERED HEREBY.
- -------------------------------------------------------------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
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<TABLE>
<CAPTION>
Underwriting
Price to Discounts and Proceeds to
Public Commissions(1) Company(2)
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<S> <C> <C> <C>
Per Share............................... $12.50 $0.875 $11.625
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Total(3)................................ $31,250,000 $2,187,500 $29,062,500
</TABLE>
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(1) The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act of
1933. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated to be $500,000.
(3) The Company has granted the several Underwriters a 30-day over-allotment
option to purchase up to 375,000 additional shares of Common Stock on the
same terms and conditions as set forth above. If all such additional
shares are purchased by the Underwriters, the total Price to Public will
be $35,937,500, the total Underwriting Discounts and Commissions will be
$2,515,625 and the total Proceeds to Company will be $33,421,875. See
"Underwriting."
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The shares of Common Stock are offered by the several Underwriters subject to
delivery by the Company and acceptance by the Underwriters, to prior sale and
to withdrawal, cancellation or modification of the offer without notice.
Delivery of the shares to the Underwriters is expected to be made at the
office of Prudential Securities Incorporated, One New York Plaza, New York,
New York, on or about October 24, 1997.
PRUDENTIAL SECURITIES INCORPORATED
OPPENHEIMER & CO., INC.
JOHNSON RICE & COMPANY L.L.C.
October 20, 1997
<PAGE>
[MAPS OF THE COMPANY'S PRINCIPAL PROPERTIES]
----------------
CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING PURCHASES OF THE COMMON STOCK TO STABILIZE ITS MARKET PRICE,
PURCHASES OF THE COMMON STOCK TO COVER SOME OR ALL OF A SHORT POSITION IN THE
COMMON STOCK MAINTAINED BY THE UNDERWRITERS AND THE IMPOSITION OF PENALTY
BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
2
<PAGE>
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the detailed
information and consolidated financial statements and the notes thereto
appearing elsewhere in this Prospectus. The information presented gives effect
to the reorganization of the Company. See "The Company." As used herein,
references to the Company or Petroglyph are to Petroglyph Energy, Inc. and its
predecessors and subsidiaries, including Petroglyph Gas Partners, L.P. (the
"Partnership"). Unless otherwise indicated, the information in this Prospectus
assumes that the Underwriters' over-allotment option will not be exercised.
Certain terms relating to the oil and natural gas industry are defined in
"Glossary of Oil and Natural Gas Terms."
THE COMPANY
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas reserves. Since its
inception in 1993, the Company has grown through leasehold acquisitions which,
together with associated development drilling, have increased the Company's
proved reserves, production, revenue and cash flow. The Company seeks to
develop properties in regions with known producing horizons, significant
available undeveloped acreage and considerable opportunities to increase
reserves, production and ultimate recoveries through development drilling and,
where applicable, enhanced oil recovery techniques. The Company's primary
activities are focused in the Uinta Basin in Utah, where it is implementing
enhanced oil recovery projects in the Lower Green River formation of the
Greater Monument Butte Region. The Company anticipates spending approximately
$35 million in 1997 and 1998 in connection with these projects. The Company has
identified several other formations in the Uinta Basin above and below the
Lower Green River formation that it believes have the potential to be
commercially productive. The Company recently acquired 56,000 gross and net
acres in the Raton Basin in Colorado. The Company plans to spend up to
approximately $5.0 million to initiate a pilot coalbed methane project to
determine the commercial viability of development of this area.
From January 1, 1994 through June 30, 1997, the Company drilled a total of 98
gross (51.5 net) wells, with a success rate of 99% and an average finding cost
of $3.43 per BOE. As of June 30, 1997, the Company had estimated net proved
reserves of approximately 7.7 MMBbls of oil and 20.9 Bcf of natural gas, or an
aggregate of 11.2 MMBOE with a PV-10 of $42.9 million. Of the Company's
estimated proved reserves, 97% are located in the Uinta Basin. At June 30,
1997, the Company had a total acreage position of approximately 108,000 gross
(99,000 net) acres and estimates that it has over 1,000 potential drilling
locations based on current spacing, approximately 75 of which are included in
the Company's independent petroleum engineers' estimate of proved reserves.
Uinta Basin. The Uinta Basin is generally recognized as one of the largest
onshore basins in the contiguous United States in terms of total hydrocarbons
in place. The Uinta Basin is a major onshore depositional and structural basin
containing the remnants of an ancient fresh water lake that broadly deposited
sand bars over the basin as the shoreline of the lake expanded and contracted
over time. Based on electric log analysis, the Company believes that
approximately 26 different horizons of oil and natural gas bearing sands have
been created in the Lower Green River formation by the ancient lake and exist
throughout its development area. As of December 31, 1996, approximately 450
MMBbls of oil and 1.6 Tcf of natural gas had been recovered from over 2,750
wells drilled in the Uinta Basin, including approximately 148 MMBbls of oil and
358 Bcf of natural gas from approximately 930 wells drilled in a 900 square
mile area of the Uinta Basin known as the Greater Monument Butte Region located
along the southern shoreline of the ancient lake.
The Company is currently implementing enhanced oil recovery projects using
waterflood techniques designed to repressure zones within the 1,500-foot thick
Lower Green River formation in the Greater Monument Butte Region. In 1996, the
Department of Energy (the "DOE") published a study of a similar enhanced oil
recovery project and concluded that such a program could ultimately increase
the recovery of the original oil in place in the Lower Green River formation
from approximately 5% to up to 21%. The Company believes the results of the
DOE's
3
<PAGE>
study are applicable to its enhanced oil recovery project in the Greater
Monument Butte Region. The Company also believes oil and natural gas exist at
depths above and below the Lower Green River formation throughout the Greater
Monument Butte Region.
The Company is an experienced operator in the Uinta Basin. From January 1,
1994 through June 30, 1997, the Company drilled 90 gross (46 net) new
development and exploratory wells in the Uinta Basin, with a 99% success rate.
As of June 30, 1997, the Company's independent petroleum engineers estimated
that the Company had approximately 75 gross (40 net) proved undeveloped well
locations in the Antelope Creek field in the Uinta Basin. The independent
petroleum engineers attributed an average of 135 MBOE gross proved undeveloped
reserves to such locations with a PV-10 per gross well of approximately
$285,000, net of drilling and completion costs. The Company's net share per
gross well is 58 MBOE with a PV-10 of $152,000, resulting in an aggregate of
approximately 4,340 MBOE with a PV-10 of approximately $11.4 million for such
75 proved undeveloped well locations. The Company believes that as of June 30,
1997 full development of the Company's 38,685 gross undeveloped acres within
the Uinta Basin would support approximately 820 additional drilling locations
based on 40-acre spacing, consisting of approximately 615 locations for
production wells and 205 locations for injection wells, at an estimated average
gross cost of $400,000 per well. In addition to the implementation of its
enhanced oil recovery projects in the Lower Green River formation, the Company
is currently developing the Upper Green River and Wasatch formations utilizing
traditional production methods.
Raton Basin. The Raton Basin, which is located in southeastern Colorado and
northeastern New Mexico, is approximately 80 miles long and 50 miles wide. The
Gas Research Institute has estimated that as of 1993 the Raton Basin held 18
Tcf of recoverable natural gas reserves from coalbed methane, a type of natural
gas produced from a coal source rather than traditional sandstone/carbonate
reservoirs. The Company estimates that, as of December 31, 1996, cumulative
production of approximately 7.9 Bcf of natural gas had been recovered from
approximately 140 coalbed methane wells in the Raton Basin, 91% of which
commenced production since January 1, 1995. As of December 31, 1996, daily
production from these wells was approximately 20 MMcf per day.
The Company recently acquired 56,000 gross and net acres in the Raton Basin
of southeastern Colorado for $700,000, where the Company plans to develop
coalbed methane natural gas reserves. During the last ten years, new drilling,
completion and production techniques have led to the development of substantial
new reserves of coalbed methane natural gas in the United States. Initially,
the Company plans to spend up to approximately $5.0 million to develop a pilot
project to study the feasibility of a full-scale coalbed methane project.
Should the pilot project be successful, based on proposed spacing, the Company
could drill up to 200 wells over the life of the project.
BUSINESS STRATEGY
The Company's strategy, which includes the following key elements, is to
increase its oil and natural gas reserves, oil and natural gas production and
cash flow per share:
. Develop Drillsite Inventory. The Company has established a large
inventory of potential projects by focusing on areas where known
hydrocarbon accumulations have not been fully exploited. The Company is
implementing enhanced oil recovery projects in a development area in the
Uinta Basin that has over 800 drillsite locations for production and
injection wells and intends to initiate a coalbed methane project in the
Raton Basin that, based upon the results of a pilot project, could
support up to 200 wells. Collectively, these projects provide the
Company with a ten-year inventory of potential drilling locations.
. Exploit Existing Reserve Base. The Company intends to apply management's
extensive geological, engineering and operating expertise to identify,
develop and exploit its existing undeveloped and
4
<PAGE>
underdeveloped acreage portfolio. The Company anticipates total capital
expenditures in the second half of 1997 and all of 1998 of approximately
$38 million, of which approximately $18 million will be used to develop
existing proved reserves included in the Company's June 30, 1997 reserve
report. The amount and timing of these expenditures will depend on a
number of factors, including actual drilling results, product prices and
availability of capital.
. Control of Operations. The Company seeks to operate and maintain a
majority working interest position in each of its core properties. These
factors enable the Company to influence directly its projects by
controlling all aspects of drilling, completion and production. In
addition, the Company intends to maintain a low cost overhead structure
by controlling the timing of the development of its properties. By
operating its producing wells, the Company believes it is well
positioned to control the expenses and timing of development and
exploitation of such properties and to better manage cost reduction
efforts.
. Acquire Additional Property Interests. The Company expects that it will,
from time to time, evaluate acquisitions of oil and natural gas
properties in its principal areas of operation and in other areas that
provide attractive investment opportunities for the addition of reserves
and production and that meet one or more of the Company's selection
criteria: (i) an attractive purchase price that, when combined with the
anticipated capital expenditures, exceeds a targeted internal rate of
return, (ii) the potential to increase reserves and production through
the application of lower risk exploitation and exploration techniques
and (iii) the opportunity for improved operating efficiency.
THE OFFERING
Common Stock Offered Hereby.............. 2,500,000 shares
Common Stock to be Outstanding after the 5,333,333 shares(1)
Offering.................................
Use of Proceeds.......................... To fund capital expenditures
relating to the Company's
development programs, to repay
existing indebtedness and for other
general corporate purposes. See
"Use of Proceeds."
Nasdaq National Market Symbol............ PGEI
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(1) Excludes 260,000 shares of Common Stock issuable upon exercise of
outstanding employee stock options, with an exercise price equal to the
initial public offering price set forth on the cover page of this
Prospectus, and 9,280 shares of Common Stock issuable upon exercise of
outstanding warrants. See "Capitalization," "Executive Compensation and
Other Information--1997 Incentive Plan," "Description of Capital Stock--
Warrants" and Note 9 of Notes to Combined Financial Statements.
RISK FACTORS
Investors should consider the material risk factors involved in connection
with an investment in the Common Stock and the impact to investors from
various events that could adversely affect the Company's business. See "Risk
Factors."
5
<PAGE>
SUMMARY COMBINED FINANCIAL DATA
The following table sets forth certain summary combined financial data of the
Company. The information should be read in conjunction with the Combined
Financial Statements and notes thereto included elsewhere in this Prospectus.
The Company acquired significant interests in certain oil and natural gas
properties and disposed of certain producing oil and natural gas properties in
certain of the periods presented which affect the comparability of the
historical financial and operating data for the periods presented. The
Company's predecessor was classified as a partnership for federal income tax
purposes and, therefore, no income taxes were paid by the Company prior to the
Conversion (as defined in "The Company").
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------ --------------------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1) HISTORICAL
---------------------------------- ------------ ---------- ------------ ----------
1993 1994 1995 1996 1996 1996 1996 1997
------- ------- ------- ------- ------------ ---------- ------------ ----------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Operating revenues:
Oil sales............. $ 224 $ 1,644 $ 3,217 $ 4,459 $3,523 $2,544 $1,608 $ 1,725
Natural gas sales..... 182 796 1,016 999 878 592 471 513
Other................. 86 45 36 -- -- -- -- 69
------- ------- ------- ------- ------ ------ ------ -------
Total operating
revenues........... 492 2,485 4,269 5,458 4,401 3,136 2,079 2,307
------- ------- ------- ------- ------ ------ ------ -------
Operating expenses:
Lease operating....... 238 1,601 2,260 2,369 1,954 1,329 914 841
Production taxes...... 9 89 188 249 205 121 77 98
Exploration costs..... -- 70 376 69 69 42 42 --
Depreciation,
depletion and
amortization......... 153 1,977 2,302 2,806 2,359 1,277 830 1,020
Impairments........... -- -- 109 -- -- -- -- --
General and
administrative....... 278 956 1,064 902 902 590 590 546
------- ------- ------- ------- ------ ------ ------ -------
Total operating
expenses........... 678 4,693 6,299 6,395 5,489 3,359 2,453 2,505
------- ------- ------- ------- ------ ------ ------ -------
Operating loss......... (186) (2,208) (2,030) (937) (1,088) (223) (374) (198)
Other income
(expenses):
Interest income
(expense), net....... -- (93) (216) 40 147 15 122 19
Gain (loss) on sales
of property and
equipment, net....... 63 44 (138) 1,384 70 1,174 (140) 6
------- ------- ------- ------- ------ ------ ------ -------
Net income (loss)
before income taxes... (123) (2,257) (2,384) 487 (871) 966 (392) (173)
Pro forma tax
expense(2)............ -- -- -- (190) -- (377) -- --
------- ------- ------- ------- ------ ------ ------ -------
Net income (loss)...... $ (123) $(2,257) $(2,384) $ 297 $ (871) $ 589 $ (392) $ (173)
======= ======= ======= ======= ====== ====== ====== =======
Supplemental pro forma
earnings (loss) per
common share(5)....... $ (.31) $ (.05)
====== =======
STATEMENT OF CASH FLOWS
DATA:
Net cash provided by
(used in):
Operating activities.. $ 4 $ (67) $ 347 $ 4,129 $ 906 $ 87
Investing activities.. (1,084) (8,131) (9,580) 303 2,816 (5,627)
Financing activities.. 1,418 8,119 10,049 (3,930) (100) 4,335
OTHER FINANCIAL DATA:
Capital expenditures... $ 1,136 $ 8,277 $10,443 $ 8,665 $4,596 $ 6,367
Adjusted EBITDA(3)..... 30 (117) 619 3,322 $1,110 2,270 $ 208 828
Operating cash
flow(4)............... (33) (233) 608 2,024 1,628 795
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997
-------------------------
HISTORICAL AS ADJUSTED(6)
---------- --------------
<S> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents............................ $ 372 $18,935(7)
Working capital...................................... (996) 17,567(7)
Total assets......................................... 23,545 47,107
Total long-term debt................................. 5,035 35
Total owners' equity................................. 12,522 41,085
</TABLE>
6
<PAGE>
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(1) The 1996 Pro Forma amounts reflect results of operations as if the June 1,
1996 disposition of the 50% interest in the Antelope Creek properties
occurred on January 1, 1996.
(2) The pro forma tax expense was computed at the federal statutory rate of 35%
and an average of the state statutory rates for those states in which the
Company has operations of 4% for each period presented.
(3) Adjusted EBITDA (as used herein) is calculated by adding interest, income
taxes, depreciation, depletion and amortization, impairments and
exploration costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. The Company did not
incur impairment expense for any period reported except for $109,000 for
the year ended December 31, 1995. Exploration costs were zero, $70,000,
$376,000 and $69,000 for each of the years ended December 31, 1993, 1994,
1995 and 1996, respectively, and $69,000 for the pro forma year ended
December 31, 1996. Exploration costs were $42,000 for the historical and
pro forma six months ended June 30, 1996 and zero for the historical six
months ended June 30, 1997. Adjusted EBITDA is presented not as a measure
of operating results, but rather as a measure of the Company's operating
performance and ability to service debt. Adjusted EBITDA is not intended to
represent cash flows for the period; nor has it been presented as an
alternative to net income (loss) or operating income (loss) nor as an
indicator of the Company's financial or operating performance. Management
believes that Adjusted EBITDA provides supplemental information about the
Company's ability to meet its future requirements for debt service, capital
expenditures and working capital. Management monitors trends in Adjusted
EBITDA, as well as the trends in revenues and net income (loss), to aid it
in managing its business. Management believes that the recent increases in
Adjusted EBITDA are indicative of the increased production volumes and
decreased operating costs experienced by the Company. Adjusted EBITDA
should not be considered in isolation, as a substitute for measures of
performance prepared in accordance with generally accepted accounting
principles or as being comparable to other similarly titled measures of
other companies, which are not necessarily calculated in the same manner.
(4) Operating cash flow is defined as net income plus adjustments to net income
to arrive at net cash provided by operating activities before changes in
working capital.
(5) Pro forma earnings (loss) per common share is calculated giving effect to
the sale of zero and 430,108 shares as of January 1, 1996 and 1997,
respectively, out of the 2,500,000 shares offered hereby. Weighted average
common shares outstanding used in the calculation of pro forma earnings
(loss) per common share for the year ended December 31, 1996 and the six
months ended June 30, 1997 were 2,833,333 and 3,263,441 shares,
respectively, as compared to the 5,333,333 common shares that will be
outstanding after the Offering.
(6) Adjusted to give effect to the sale of 2,500,000 shares of Common Stock
offered hereby and the application of the estimated net proceeds therefrom.
See "Use of Proceeds" and "Capitalization."
(7) Also includes the effect of the repayment of an additional $5.0 million of
indebtedness incurred subsequent to June 30, 1997.
7
<PAGE>
SUMMARY RESERVE AND ACREAGE DATA
The reserve and present value data at June 30, 1997 for the Company's
properties have been prepared by Lee Keeling and Associates, Inc. ("Keeling"),
independent petroleum engineering consultants. The reserve estimates for 1994,
1995 and 1996 have been prepared by the Company. For additional information
relating to the Company's oil and natural gas reserves, see "Risk Factors--
Uncertainty of Reserve Information and Future Net Revenue Estimates," "Business
and Properties--Oil and Natural Gas Reserves" and Note 12 of the Notes to the
Combined Financial Statements of the Company. A summary of the June 30, 1997
reserve report and the letter of Keeling with respect thereto is included as
Appendix A to this Prospectus.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------ AS OF JUNE 30,
1994 1995 1996 1997
----------- ----------- ------------ --------------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (Bbls)............... 1,204,969 1,561,092 6,127,136 7,724,137
Natural gas (Mcf)........ 7,307,359 6,659,160 18,812,463 20,910,065
BOE (6 Mcf per Bbl)...... 2,422,862 2,670,952 9,262,547 11,209,147
Percent proved
developed............... 100% 100% 15% 24%
Present value of
estimated future net
cash flows before income
tax(1)(2)............... $11,426,635 $14,973,803 $ 64,102,934 $42,871,275(3)
Future net cash flows
before income tax(2).... $16,657,782 $22,431,506 $123,799,579 $84,394,660(4)
ACREAGE:
Gross acres:
Developed............... 21,592 16,251 12,719 13,119
Undeveloped............. 18,561 20,577 34,407 94,612
Net acres:
Developed............... 15,392 13,640 9,450 9,783
Undeveloped............. 13,664 20,537 28,263 89,088
</TABLE>
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(1) The present value of future net cash flows attributable to the Company's
reserves was prepared using prices and costs in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax
basis. These amounts reflect the future effects of the Company's open
hedging contracts at the end of the periods presented. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Hedging Transactions."
(2) Period-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $17.01, $18.00,
$19.50 and $15.09 per Bbl at December 31, 1994, 1995, 1996 and June 30,
1997, respectively. Period-end weighted average natural gas prices were
$1.45, $1.85, $3.37 and $1.71 per Mcf at December 31, 1994, 1995 and 1996
and June 30, 1997, respectively.
(3) Using the Company's weighted average prices received for the 12 months
ending June 30, 1997 of $17.19 per Bbl of oil and $2.12 per Mcf of natural
gas, the present value of estimated net cash flows before income tax would
be $57.0 million as of June 30, 1997.
(4) Using the Company's weighted average prices received for the 12 months
ending June 30, 1997 of $17.19 per Bbl of oil and $2.12 per Mcf of natural
gas, the future net cash flows before income tax would be $110.6 million.
8
<PAGE>
SUMMARY OPERATING DATA
The following table sets forth summary data with respect to the production
and sales of oil and natural gas by the Company for the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
----------------------------------------------- ----------------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1) HISTORICAL
---------------------------------- ------------ ---------- ------------ ----------
1993 1994 1995 1996 1996 1996 1996 1997
------- -------- -------- -------- ------------ ---------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (Bbls)............. 10,782 110,373 182,704 262,910 213,535 141,775 94,542 117,770
Natural gas (Mcf)...... 81,192 485,062 659,202 553,770 461,292 358,420 271,431 243,095
Total (BOE)............ 24,314 191,217 292,571 355,205 290,417 201,512 139,781 158,286
AVERAGE SALES PRICE PER
UNIT(2):
Oil (per Bbl)(3)....... $ 20.78 $ 14.89 $ 17.61 $ 16.96 $ 16.50 $ 17.94 $ 17.01 $ 14.65
Natural gas (per Mcf).. 2.24 1.64 1.54 1.80 1.90 1.65 1.74 2.11
BOE.................... 16.71 12.76 14.47 15.36 15.15 15.56 14.87 14.14
COSTS PER BOE:
Average lease operating
expenses including
production and property
taxes (per BOE):
Utah.................. $ -- $ 9.95 $ 6.06 $ 5.21 $ 4.53 $ 6.08 $ 4.92 $ 4.13
Other................. 10.18 8.40 11.68 11.99 11.99 9.36 9.36 17.45(4)
Weighted average...... 10.18 8.84 8.37 7.37 7.43 7.19 7.09 5.93
General and
administrative........ 11.42 5.00 3.64 2.54 3.11 2.93 4.22 3.45
Depreciation, depletion
and amortization...... 6.31 10.34 7.87 7.90 8.12 6.34 5.94 6.45
</TABLE>
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(1) The Pro Forma amounts reflect results of operations as if the June 1, 1996
disposition of the 50% interest in the Antelope Creek properties had
occurred on January 1, 1996.
(2) Before deduction of production taxes.
(3) Excluding the effects of losses from crude oil hedging transactions and
amortization of deferred revenue, the weighted average sales price per Bbl
of oil was $20.22 for the year ended December 31, 1996, $18.22 for the
historical six months ended June 30, 1996, $17.43 for the pro forma six
months ended June 30, 1996 and $15.96 for the historical six months ended
June 30, 1997.
(4) Excluding the effects of a workover and bottomhole repair to a well that
totaled $131,000, the average lease operating expense for the other
properties for the six months ended June 30, 1997 was $11.37 per BOE.
The following table sets forth average finding costs data with respect to the
Company's oil and natural gas properties for the periods indicated.
<TABLE>
<CAPTION>
SIX MONTHS FROM
YEAR ENDED DECEMBER 31, ENDED JANUARY 1, 1994
------------------------ JUNE 30, TO
1994 1995 1996 1997 JUNE 30, 1997
------- -------- ------- ---------- ---------------
<S> <C> <C> <C> <C> <C>
AVERAGE FINDING COSTS
(PER BOE):
Utah.................. $ 7.79 $ 9.86 $ 2.74(1) $2.53(1) $3.39(1)
Other................. 2.31 * * * 4.01
Total................. 3.92 10.96 2.86 2.55 3.43
</TABLE>
- --------
* Not meaningful.
(1) The calculation of average finding costs for Utah for the year ended
December 31, 1996, the six months ended June 30, 1997 and for the period
from January 1, 1994 to June 30, 1997, includes future development costs of
$16.5 million, $1.7 million, and $18.1 million, respectively. Average
finding costs per BOE for Utah excluding these amounts were $0.79, $1.78
and $1.87 for the year ended December 31, 1996, the six months ended June
30, 1997, and for the period from January 1, 1994 to June 30, 1997,
respectively.
9
<PAGE>
RISK FACTORS
An investment in the shares of Common Stock offered hereby involves a high
degree of risk. Prospective investors should carefully consider the following
risk factors, in addition to the other information contained in this
Prospectus, in connection with an investment in the shares of Common Stock
offered hereby.
This Prospectus contains forward-looking statements. The words "anticipate,"
"believe," "expect," "plan," "intend," "estimate," "project," "will," "could,"
"may" and similar expressions are intended to identify forward-looking
statements. These statements include information regarding oil and natural gas
reserves, future drilling and operations, future production of oil and natural
gas and future net cash flows. Such statements reflect the Company's current
views with respect to future events and financial performance and involve
risks and uncertainties, including without limitation the risks described
below in "Risk Factors." Should one or more of these risks or uncertainties
occur, or should underlying assumptions prove incorrect, actual results may
vary materially and adversely from those anticipated, believed, estimated or
otherwise indicated.
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 and operating income (loss) and could require an
impairment in the carrying value of the Company's oil and natural gas
properties. See "Risk Factors--Uncertainty of Reserve Information and Future
Net Revenue Estimates," "Business and Properties--Competition" and "Business
and Properties--Regulation."
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES. There
are numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and their values, including many factors beyond the
Company's control. Estimates of proved undeveloped reserves and reserves
recoverable through enhanced oil recovery techniques, which comprise a
significant portion of the Company's reserves, are by their nature uncertain.
The reserve information set forth in this Prospectus represents estimates
only. Although the Company believes such estimates to be reasonable, reserve
estimates are imprecise and should be expected to change as additional
information becomes available.
Estimates of oil and natural gas reserves, by necessity, are projections
based on engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is
a subjective process of estimating underground accumulations of oil and
natural gas that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. In particular, given the early stage
of the Company's development programs, the ultimate effect of such programs is
difficult to ascertain. Estimates of economically recoverable oil and natural
gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
improved recovery techniques such as the enhanced oil recovery techniques
utilized by the Company, the assumed effects of regulations by governmental
and tribal agencies and assumptions concerning future oil and natural gas
prices, future operating costs, severance and excise taxes, development costs
and workover and remedial costs, all of which may in fact vary considerably
from actual results. For these reasons, estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, classifications of
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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. See "Business and Properties--Oil and Natural Gas Reserves."
The PV-10 referred to in this Prospectus 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 investors may base their
evaluation of the Company's performance. As a result of its brief operating
history, expanded drilling program and change in the Company's mix of
properties during such period as a result of its acquisition and disposition
of properties, the operating results from the Company's historical periods may
not be indicative of future results. There can be no assurance that the
Company will continue to experience growth in, or maintain its current level
of, revenues, oil and natural gas reserves or production. In addition, the
Company's expansion has placed significant demands on its administrative,
operational and financial resources and the Company is in the process of
implementing a new accounting system. Any future growth of the Company's oil
and natural gas reserves, production and operations would place significant
further demands on the Company's financial, operational and administrative
resources. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
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 $937,000 in 1996. Excluding the effect of the
$1.3 million gain on the sale of the 50% interest in Antelope Creek in 1996,
the Company also has experienced net losses in each year since its inception.
During the first six months of 1997, the Company incurred an operating loss
and a net loss of approximately $198,000 and $173,000, respectively. Although
the Company expects its results of operations to improve as it completes
additional Uinta Basin wells and develops its Raton Basin acreage, there is no
assurance that the Company will achieve, or be able to sustain, profitability.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations."
EARLY STAGES OF DEVELOPMENT ACTIVITIES. The Company's development plan
includes (i) the drilling of development and exploratory wells in the Uinta
Basin, together with injection wells that are intended to repressurize
producing reservoirs in the Lower Green River formation, (ii) subject to the
evaluation of the results of a pilot program, the drilling of exploratory
wells in connection with the development of a coalbed methane project in the
Raton Basin and (iii) the use of 3-D seismic technology to exploit its
properties in south Texas. The success of these projects will be materially
dependent on whether the Company's development and exploratory wells can be
drilled and completed as commercially productive wells, whether the enhanced
oil recovery techniques can successfully repressurize reservoirs and increase
the rate of production and ultimate recovery of oil and natural gas from the
Company's acreage in the Uinta Basin and whether the Company can successfully
implement its planned coalbed methane project on its acreage in the Raton
Basin. Although the Company believes the geologic characteristics of its
project areas reduce the probability of drilling nonproductive wells, there
can be no assurance that the Company will drill productive wells. If the
Company drills a significant number of nonproductive wells, the Company's
business, financial condition and results of operations would be materially
adversely affected. While the Company's pilot enhanced oil recovery projects
in the Uinta Basin have
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indicated that rates of oil production can be increased, the repressurization
takes place over a period of approximately two years, with full response
occurring after approximately five years; therefore, the ultimate effect of
the enhanced oil recovery operations will not be known for several years.
Ultimate recoveries of oil and natural gas from the enhanced oil recovery
programs may also vary at different locations within the Company's Uinta Basin
properties. Accordingly, due to the early stage of development, the Company is
unable to predict whether its development activities in the Uinta Basin will
meet its expectations. In the event the Company's enhanced oil recovery
program does not effectively increase rates of production or ultimate recovery
of oil reserves, the Company's business, financial condition and results of
operation will likely be materially adversely affected.
RISKS ASSOCIATED WITH OPERATING IN THE UINTA BASIN
Concentration in Uinta Basin. The Company's properties in the Greater
Monument Butte Region of the Uinta Basin constitute the majority of the
Company's existing inventory of producing properties and drilling locations.
Approximately 82% of the Company's 1997 capital expenditure budget of
approximately $18 million is expected to be dedicated to developing the
Company's enhanced oil recovery projects in this area. There can be no
assurance that the Company's operations in the Uinta Basin will yield positive
economic returns. Failure of the Company's Uinta Basin properties to yield
significant quantities of economically attractive reserves and production
would have a material adverse impact on the Company's financial condition and
results of operations. In addition, recent heavy drilling activity by a number
of operators in the Uinta Basin may increase the cost to acquire additional
acreage in this area, reduce or limit the availability of drilling and service
rigs, equipment and supplies, or reduce demand for the Company's production,
any of which would impact the Company more adversely than if the Company were
more geographically diversified.
Limited Refining Capacity for Uinta Basin Black Wax. The marketability of
the Company's oil production depends in part upon the availability, proximity
and capacity of refineries, pipelines and processing facilities. The crude oil
produced in the Uinta Basin is known as "black wax" or "yellow wax" and has a
higher paraffin content than crude oil found in most other major North
American basins. Currently, the most economic markets for the Company's black
wax production are five refineries in Salt Lake City that have limited
facilities to refine efficiently this type of crude oil. Because these
refineries have limited capacity, any significant increase in Uinta Basin
"black wax" production or temporary or permanent refinery shutdowns due to
maintenance, retrofitting, repairs, conversions to or from "black wax"
production or otherwise could create an over supply of "black wax" in the
market, causing prices for Uinta Basin oil to decrease. Since July 1996, the
posted prices for Uinta Basin oil production have been lower than major
national indexes for crude oil. The Company believes these differences are
attributable to one or more market factors, including refinery capacity
constraints caused by scheduled maintenance at one of the Salt Lake City
refineries, the increase in supply of Uinta Basin "black wax" production
resulting from the recent drilling activity or the reaction to the potential
availability of additional non-Uinta Basin crude oil production associated
with a new pipeline. There can be no assurance that prices will return to
historical levels or that other price declines related to supply imbalances
will not occur in the future. To the extent crude oil prices decline further
or the Company is unable to market efficiently its oil production, the
Company's business, financial condition and results of operations could be
materially adversely affected.
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 either 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.
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Availability of Water for Enhanced Oil Recovery Program. The Company's
enhanced oil recovery program involves the injection of water into wells to
pressurize reservoirs and, therefore, requires substantial quantities of
water. The Company intends to satisfy its requirements from one or more of
three sources: water produced from water wells, water purchased from local
water districts and water produced in association with oil production. The
Company currently has drilled water wells only in the Antelope Creek field,
and there can be no assurance that these water wells will continue to produce
quantities sufficient to support the Company's enhanced oil recovery program,
that the Company will be able to obtain the necessary approvals to drill
additional water wells or that successful water wells can be drilled in its
other Uinta Basin development areas. The Company has a contract with East
Duchesne Water District to purchase up to 10,000 barrels of water per day
through September 30, 2004. After the initial term, this contract
automatically renews each year for one additional year; however, either party
may terminate the agreement with twelve months prior notice. In the event of a
water shortage, the East Duchesne Water District contract provides that
preferences will be given to residential customers and other water customers
having a higher use priority than the Company. In addition, the Company has
not yet secured a water source for full development of its Natural Buttes
Extension properties. There can be no assurance that water shortages will not
occur or that the Company will be able to renew or enter into new water supply
agreements on commercially reasonable terms or at all. To the extent the
Company is required to pay additional amounts for its supply of water, the
Company's financial condition and results of operations may be adversely
affected. While the Company believes that there will be sufficient volumes of
water available to support its improved oil recovery program and has taken
certain actions to ensure an adequate water supply will be available, in the
event the Company is unable to obtain sufficient quantities of water, the
Company's enhanced oil recovery program and business would be materially
adversely affected.
RISKS ASSOCIATED WITH PLANNED OPERATIONS IN THE RATON BASIN
Coalbed Methane Production. Although similar to traditional natural gas
reserves, coalbed methane reserves have historically been more expensive to
develop and produce. 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 yet to begin its development
program. There can be no assurance that when and if such program is begun the
Company will discover natural gas and, if discovered, be successful in
completing commercially productive wells.
Dependence on Third Party Expertise. Based on its limited operating
experience in the Raton Basin, the Company intends to engage independent
contractors in connection with its coalbed methane natural gas development
activities. There can be no assurance that such technological expertise will
be available to the Company on commercially reasonable terms or at all.
Water Disposal. The Company believes that the water produced from the Raton
Basin coal seams will be low in dissolved solids, allowing the Company,
operating under permits which the Company believes will be issued by the State
of Colorado, to discharge the water into streambeds or stockponds. However, if
nonpotable water is discovered, it may be necessary to install and operate
evaporators or to drill disposal wells to reinject the produced water back
into the underground rock formations adjacent to the coal seams or to lower
sandstone horizons. In the event the Company is unable to obtain permits from
the State of Colorado, 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. See
"Business and Properties--Principal Properties--Raton Basin--Water Production
and Disposal."
RISKS OF HEDGING TRANSACTIONS. In order to manage its exposure to price
risks in the marketing of its oil and natural gas, the Company has in the past
and expects to continue to enter into oil and natural gas price hedging
arrangements with respect to a portion of its expected production. These
arrangements may include
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futures contracts on the New York Mercantile Exchange ("NYMEX"), fixed price
delivery contracts and financial collars and swaps. While intended to reduce
the effects of the volatility of the price of oil and natural gas, such
transactions may limit potential gains by the Company if oil and natural gas
prices were to rise substantially over the price established by the hedge. In
addition, such transactions may expose the Company to the risk of financial
loss in certain circumstances, including instances in which (i) production is
less than expected, (ii) there is a widening of price differentials between
delivery points for the Company's production and the delivery point assumed in
the hedging arrangement, (iii) the counterparties to the Company's
future contracts fail to perform the contract, or (iv) a sudden, unexpected
event materially impacts oil or natural gas prices. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Hedging Transactions," "Business and Properties--Hedging Activities" and Note
7 of Notes to Combined Financial Statements.
SUBSTANTIAL CAPITAL REQUIREMENTS. The Company's current development plans
will require it to make substantial capital expenditures in connection with
the exploration, development and exploitation of its oil and natural gas
properties. The Company's enhanced oil recovery project and pilot coalbed
methane project require substantial initial capital expenditures.
Historically, the Company has funded its capital expenditures through a
combination of internally generated funds from sales of production or
properties, equity contributions, long-term debt financing and short-term
financing arrangements. The Company anticipates that the net proceeds from the
Offering will be sufficient to meet its estimated capital expenditure
requirements for the 12 months following the Offering. The Company believes
that after such 12-month period it will require a combination of additional
financing and cash flow from operations to implement its future development
plans. The Company currently does not have any arrangements with respect to,
or sources of, additional financing other than the Credit Agreement, and there
can be no assurance that any additional financing will be available to the
Company on acceptable terms or at all. Future cash flows and the availability
of financing will be subject to a number of variables, such as the level of
production from existing wells, prices of oil and natural gas, the Company's
success in locating and producing new reserves and the success of the enhanced
recovery program in the Uinta Basin and the coalbed methane project in the
Raton Basin. To the extent that future financing requirements are satisfied
through the issuance of equity securities, the Company's existing stockholders
may experience dilution that could be substantial. The incurrence of debt
financing could result in a substantial portion of the Company's operating
cash flow being dedicated to the payment of principal and interest on such
indebtedness, could render the Company more vulnerable to competitive
pressures and economic downturns and could impose restrictions on the
Company's operations. If revenue were to decrease as a result of lower oil and
natural gas prices, decreased production or otherwise, and the Company had no
availability under the Credit Agreement or any other credit facility, the
Company could have a reduced ability to execute its current development plans,
replace its reserves or to maintain production levels, which could result in
decreased production and revenue over time. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources."
DRILLING AND OPERATING RISKS. Oil and natural gas drilling activities are
subject to many risks, including the risk that no commercially productive
reservoirs will be encountered. There can be no assurance that wells drilled
by the Company will be productive or that the Company will recover all or any
portion of its drilling costs. Drilling for oil and natural gas may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. The cost of drilling, completing and
operating wells is often uncertain. In addition, the Company's use of enhanced
oil recovery techniques in the Uinta Basin requires greater development
expenditures than alternative primary production strategies. In order to
accomplish enhanced oil recovery, the Company expects to drill a number of
wells utilizing waterflood technology in the future. The Company's waterflood
program involves greater risk of mechanical problems than conventional
development programs. The Company's drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, many of which are beyond
the Company's control, including economic conditions, title problems, water
shortages, weather conditions, compliance with governmental and tribal
requirements and shortages or delays in the delivery of equipment and
services. The Company's future drilling activities may not be successful and,
if unsuccessful, such failure may have a material adverse effect on the
Company's future results of operations and financial condition.
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The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures and spills, any of which can
result in the loss of hydrocarbons, environmental pollution, personal injury
claims and other damage to properties of the Company and others. As protection
against operating hazards, the Company maintains insurance coverage against
some, but not all, potential losses. The Company may elect to self-insure in
circumstances in which management believes that the cost of insurance,
although available, is excessive relative to the risks presented. The
occurrence of an event that is not covered, or not fully covered, by third-
party insurance could have a material adverse effect on the Company's
business, financial condition and results of operations.
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 35% of the Company's acreage is located
on Ute tribal land and is leased by the Company from the Ute Indian Tribe and
the Ute Distribution Corporation. Because the Ute tribal authorities have
certain rule making authority and jurisdiction, such leases may be subject to
a greater degree of regulatory uncertainty than properties subject to only
state and federal regulations. Although the Company has not experienced any
material difficulties with its Ute tribal leases or in complying with Ute
tribal laws or customs, there can be no assurance that material difficulties
will not be encountered in the future. Matters subject to regulation by
federal, state, local and Ute tribal authorities include permits for drilling
operations, road and pipeline construction, reports concerning operations, the
spacing of wells, unitization and pooling of properties, taxation and
environmental protection. Prior to drilling any wells in the Uinta Basin,
applicable federal and Ute tribal requirements and the terms of its
development agreements will require the Company to have prepared by third
parties and submitted for approval an environmental and archaeological
assessment for each area to be developed prior to drilling any wells in such
areas. Although the Company has not experienced any material delays that have
affected its development plans, there can be no assurance that delays will not
be encountered in the preparation or approval of such assessments, or that the
results of such assessments will not require the Company to alter its
development plans. Any delays in obtaining approvals or material alterations
to the Company's development plans could have a material adverse effect on the
Company's operations. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow
of oil and natural gas wells below actual production capacity in order to
conserve supplies of oil and natural gas. Although the Company believes it is
in substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
Significant expenditures may be required to comply with governmental and Ute
tribal laws and regulations and may have a material adverse effect on the
Company's financial condition and results of operations. See "Business and
Properties--Regulation."
COMPLIANCE WITH ENVIRONMENTAL REGULATIONS. The Company's operations are
subject to complex and constantly changing environmental laws and regulations
adopted by federal, state and local governmental authorities. The
implementation of new, or the modification of existing, laws or regulations
could have a material adverse effect on the Company. The discharge of oil,
natural gas or other pollutants into the air, soil or water may give rise to
significant liabilities on the part of the Company to the government and third
parties and may require the Company to incur substantial costs of remediation.
Moreover, the Company has agreed to indemnify sellers of properties purchased
by the Company against certain liabilities for environmental claims associated
with such properties. No assurance can be given that existing environmental
laws or regulations, as currently interpreted or reinterpreted in the future,
or future laws or regulations will not materially adversely affect the
Company's results of operations and financial condition or that material
indemnity claims will not arise against the Company with respect to properties
acquired by the Company. See "Business and Properties--Regulation."
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
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successful exploration or development activities, enhanced oil recovery
activities or acquires properties containing proved reserves. Approximately
76% of the Company's total proved reserves at June 30, 1997 were undeveloped.
In order to increase reserves and production, the Company must continue its
development and exploitation drilling programs or undertake other replacement
activities. The Company's current development plan includes increasing its
reserve base through continued drilling, development and exploitation of its
existing properties. There can be no assurance, however, that the Company's
planned development and exploitation projects will result in significant
additional reserves or that the Company will have continuing success drilling
productive wells at anticipated finding and development costs.
DEPENDANCE ON KEY PERSONNEL. The Company's success has been and will
continue to be highly dependent on Robert C. Murdock, its Chairman of the
Board, President and Chief Executive Officer, Robert A. Christensen, its
Executive Vice President and Chief Technical Officer, Sidney Kennard Smith,
its Executive Vice President and Chief Operating Officer, and a limited number
of other senior management and technical personnel. Loss of the services of
Mr. Murdock, Mr. Christensen, Mr. Smith or any of those other individuals
could have a material adverse effect on the Company's operations. The
Company's failure to retain its key personnel or hire additional personnel
could have a material adverse effect on the Company.
CONTROL BY EXISTING STOCKHOLDERS. Upon completion of the Offering,
directors, executive officers and current principal stockholders of the
Company will beneficially own approximately 52.9% of the Company's outstanding
Common Stock (approximately 49.5% if the Underwriters over-allotment option is
exercised in full). Accordingly, these stockholders, as a group, will be able
to control the outcome of stockholder votes, including votes concerning the
election of directors, the adoption or amendment of provisions in the
Company's Certificate of Incorporation or Bylaws and the approval of mergers
and other significant corporate transactions. Furthermore, because certain
actions of the Board such as issuing preferred stock and amending the Bylaws
require an 80% supermajority approval of the Board of Directors, the existence
of these levels of ownership concentrated in a few persons makes it unlikely
that any other holder of Common Stock will be able to control the election of
enough directors to affect the management or direction of the Company. These
factors may also have the effect of delaying or preventing a change in the
management or voting control of the Company, including transactions that
otherwise could involve payment of a premium over prevailing market prices to
holders of Common Stock. See "Principal Stockholders" and "--Certain Anti-
Takeover Provisions."
COMPETITION. The Company operates in the highly competitive areas of oil and
natural gas exploration, exploitation, acquisition and production with other
companies, many of which have substantially larger financial resources,
operations, staffs and facilities. In seeking to acquire desirable producing
properties or new leases for future exploration and in marketing its oil and
natural gas production, the Company faces intense competition from both major
and independent oil and natural gas companies. Many of these competitors have
financial and other resources substantially in excess of those available to
the Company. The effects of this highly competitive environment could have a
material adverse effect on the Company. See "Business and Properties--
Competition."
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
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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.
CERTAIN ANTI-TAKEOVER PROVISIONS. The Company's Certificate of Incorporation
and Bylaws contain provisions which may have the effect of delaying, deferring
or preventing a change in control of the Company. These provisions, among
other things, provide for noncumulative election of the Board of Directors,
impose certain procedural requirements on stockholders of the Company who wish
to make nominations for the election of directors or propose other actions at
stockholders' meetings and require an 80% supermajority vote of the Board of
Directors in order to approve amendments to the Company's Bylaws. Furthermore,
the Company's Bylaws provide that stockholders may only call special meetings
by a majority of the votes entitled to be cast by the stockholders at the
meeting except that, not more than once per year, a meeting may be called by
the holders of 10% of the votes entitled to be cast at such meeting. In
addition, the Company's Certificate of Incorporation authorizes the Board to
issue up to 5,000,000 shares of preferred stock without stockholder approval
and to set the rights, preferences and other designations, including voting
rights, of those shares as the Board of Directors may determine. These
provisions, alone or in combination with each other and with the matters
described in "Risk Factors--Control by Existing Stockholders," may discourage
transactions involving actual or potential changes of control of the Company,
including transactions that otherwise could involve payment of a premium over
prevailing market prices to holders of Common Stock. The Company also is
subject to provisions of the Delaware General Corporation Law that may make
some business combinations more difficult. See "Description of Capital Stock--
Certain Provisions of the Company's Charter and Bylaws and Delaware Law
Provisions."
ABSENCE OF DIVIDENDS ON COMMON STOCK. The Company has never declared or paid
cash dividends on its Common Stock and anticipates that future earnings will
be retained for development of its business. In addition, the Credit Agreement
prohibits the payment of cash dividends. See "Dividend Policy."
SHARES ELIGIBLE FOR FUTURE SALE; REGISTRATION RIGHTS. Upon completion of the
Offering, the Company will have a total of 5,333,333 shares outstanding. Of
these shares, the 2,500,000 shares offered hereby (2,875,000 shares if the
Underwriters' over-allotment option is exercised in full) will be freely
tradeable without restriction or registration under the Securities Act of
1933, as amended (the "Securities Act"), by persons other than "affiliates" of
the Company, as defined under the Securities Act. The remaining 2,833,333
shares of Common Stock outstanding will be "restricted securities" as that
term is defined by Rule 144 as promulgated under the Securities Act. Upon the
closing of the Offering, the Company will have options and warrants
outstanding to purchase an aggregate of 269,280 shares of Common Stock. See
"Executive Compensation and Other Information," "Shares Eligible for Future
Sale" and "Description of Capital Stock."
Under Rule 144 (and subject to the conditions thereof, including the volume
limitations described above), the Company believes that the earliest date on
which any of the shares of its Common Stock currently outstanding will be
eligible for sale under Rule 144 is the first anniversary of the completion of
the Offering. All of the restricted shares are subject to lockup restrictions.
Pursuant to these restrictions, the holders of all restricted shares,
including certain of the Company's executive officers and directors, have
agreed that they will not, directly or indirectly, offer, sell, offer to sell,
contract to sell, pledge, grant any option to purchase or otherwise sell or
dispose (or announce any offer, sale, offer of sale, contract to sell, pledge,
grant of any options to purchase or sale or disposition) of any shares of
Common Stock or other capital stock of the Company, or any securities
convertible into, or exercisable or exchangeable for, any shares of Common
Stock or other capital stock of the Company without the prior written consent
of Prudential Securities Incorporated, on behalf of the Underwriters, for a
period of 180 days from the date of this Prospectus. Prudential Securities
Incorporated may, in its sole discretion, at any time and without notice,
release all or any portion of the securities to such agreements. The holders
of 2,833,333 shares of Common Stock and their permitted transferees have
demand registration rights to require the Company to register such shares
under the Securities Act beginning 180 days after the date of this
17
<PAGE>
Prospectus. See "Description of Capital Stock--Registration Rights."
Registration and sale of such shares could have an adverse effect on the
trading price of the Common Stock.
Prior to the Offering, there has been no public market for the Common Stock
and no predictions can be made of the effect, if any, that the sale or
availability for sale of shares of additional Common Stock will have on the
market price of the Common Stock. Nevertheless, sales of substantial amounts
of such shares in the public market, or the perception that such sales could
occur, could materially and adversely affect the market price of the Common
Stock and could impair the Company's future ability to raise capital through
an offering of its equity securities.
IMMEDIATE AND SUBSTANTIAL DILUTION. Purchasers of Common Stock in the
Offering will experience an immediate and substantial dilution in net tangible
book value per share of approximately $4.95. See "Dilution."
NO PRIOR PUBLIC MARKET; POSSIBLE STOCK PRICE VOLATILITY. Before the
Offering, there has been no public market for the Common Stock. The initial
public offering price has been determined through negotiations between the
Company and the Representatives of the Underwriters based on several factors
that may not be indicative of future market prices. See "Underwriting" for a
discussion of the factors considered in determining the initial public
offering price. Although the Common Stock has been approved for inclusion in
the Nasdaq National Market, there can be no assurance that it will be actively
traded on such market or that, if active trading does develop, it will be
sustained. The market price of the Common Stock and the price at which the
Company may sell securities in the future could be subject to large
fluctuations in response to changes and variations in the Company's operating
results, litigation, general market conditions, the prices of oil and natural
gas, refining capacity in Salt Lake City, Utah and other regions, the
liquidity of the Company and the Company's ability to raise additional funds,
the number of market makers for the Company's Common Stock and other factors.
In the event that the Company's operating results are below the expectations
of public market analysts and investors in one or more future periods, it is
likely that the price of the Common Stock will be materially adversely
affected. In addition, the stock market has experienced significant price and
volume fluctuations that have particularly affected the market prices of
equity securities of many energy companies and that often have been unrelated
to the operating performance of such companies. General market fluctuations
may also adversely affect the market price of the Common Stock.
18
<PAGE>
THE COMPANY
GENERAL
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of oil and natural gas properties. The Company's
primary operations are focused in the Greater Monument Butte Region of the
Uinta Basin of Utah. In addition, the Company recently acquired properties in
the Raton Basin in Colorado. See "Business and Properties."
COMPANY HISTORY
Initial Operations. The Company's predecessor was formed as a limited
partnership in April 1993 by Robert C. Murdock, Robert A. Christensen and
Natural Gas Partners, L.P. ("NGP I"). From its inception, the Company has
engaged in the acquisition, exploration and exploitation of oil and natural
gas properties, acquiring proved developed producing properties in Colorado,
Kansas, Oklahoma, Utah and Texas for approximately $11.7 million. These
acquisitions were funded by equity capital from NGP I and certain members of
management. Since inception of the Company to December 31, 1996, cash flow
from operations and from the sale of these properties amounted to
approximately $14.4 million. The Company sold the predominant portion of these
properties during 1996 in order to focus on and accelerate its Uinta Basin oil
and natural gas exploration and exploitation projects. Since the Company's
formation, NGP I, Natural Gas Partners II, L.P., Natural Gas Partners III,
L.P. (collectively, "NGP"), certain of NGP's affiliates and certain members of
the Company's management have invested an aggregate of approximately $17.0
million in the Company.
Uinta Basin. In February 1994, the Company purchased a 50% working interest
and operating rights in existing Antelope Creek and Duchesne fields containing
approximately 22,000 gross acres in the Uinta Basin for approximately $4.5
million. In September 1995, the Company purchased the remaining 50% working
interest in these fields for approximately $5.6 million. In April 1996, the
Company acquired development rights to approximately 15,450 gross acres in the
Natural Buttes Extension field, which forms the eastern boundary of the
Greater Monument Butte Region.
In June 1996, the Company sold a 50% working interest in its Antelope Creek
field to an industry partner. The Company owns the remaining 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
approximately $7.5 million in cash and $5.3 million in carried development
costs. The Company recognized a gain of $1.3 million on the sale of this
interest. See "Pro Forma Condensed Combined Statements of Operations."
Raton Basin. The Company recently acquired 56,000 gross and net acres in the
Raton Basin of southeastern Colorado for $700,000. This acquisition was
financed through the use of proceeds from borrowings under the Company's
Credit Agreement. Initially, the Company plans to spend up to approximately
$5.0 million to conduct a pilot project to study the feasibility of a full-
scale coalbed methane project in this area.
CORPORATE CONVERSION
Petroglyph was incorporated in Delaware in 1997 for the purpose of
consolidating and continuing the activities previously conducted by the
Partnership. Pursuant to the terms of an Exchange Agreement dated August 22,
1997 (the "Exchange Agreement"), the Company will acquire all of the
outstanding limited partnership interests of the Partnership from NGP and
certain of its affiliates and all of the stock of Petroglyph Energy, Inc., a
Kansas corporation and the general partner of the Partnership, in exchange for
shares of Common Stock of the Company (the "Conversion"). The Conversion and
other transactions contemplated by the Exchange Agreement will be consummated
immediately prior to the closing of the Offering. The Conversion will be
accounted for as a transfer of assets and liabilities between affiliates under
common control and will result in no change in carrying values of these assets
and liabilities.
Petroglyph's principal executive offices are located at 6209 North Highway
61, Hutchinson, Kansas 67502 and its telephone number is (316) 665-8500.
19
<PAGE>
USE OF PROCEEDS
The net proceeds to the Company from the Offering are expected to be
approximately $28.6 million ($32.9 million if the Underwriters' over-allotment
option is exercised in full), after deducting underwriting discounts and
commissions and estimated offering expenses of the Company. The net proceeds
will be used first to fund capital expenditures relating to the Company's
development programs. The Company intends to use the balance to repay existing
indebtedness under the Company's Amended and Restated Loan Agreement, dated
September 15, 1997, with The Chase Manhattan Bank ("Chase") (as amended, the
"Credit Agreement") and for other general corporate purposes. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources." Pending the application of the
net proceeds, the Company intends to invest the net proceeds in short-term,
investment-grade, interest-bearing securities.
At October 20, 1997, the outstanding principal balance of indebtedness under
the Credit Agreement was $10.0 million. For the six months ended June 30,
1997, the Original Agreement (as defined below) had an average interest rate
of 8.875% per annum, and the Credit Agreement has a final maturity of
September 2002.
DIVIDEND POLICY
The Company has never declared or paid cash dividends on its Common Stock
and anticipates that any future earnings will be retained for development of
its business. In addition, the Credit Agreement prohibits the payment of cash
dividends on Common Stock. The Board of Directors of the Company may review
the Company's dividend policy from time to time in light of, among other
things, the Company's earnings and financial position and limitations imposed
by the Company's debt instruments. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations--Liquidity and Capital
Resources" and Note 5 of the Notes to Combined Financial Statements.
20
<PAGE>
DILUTION
Purchasers of Common Stock offered hereby will experience an immediate and
substantial dilution in the net tangible book value of the Common Stock from
the initial public offering price. At June 30, 1997, the net tangible book
value per share of the Common Stock of the Company, on a pro forma basis after
giving effect to the issuance of 2,833,333 shares in the Conversion, was
$4.13. Such amount does not give effect to the Offering. Net tangible book
value per share represents the amount of the Company's tangible book value
(total book value of tangible assets less total liabilities) divided by the
total number of shares of Common Stock outstanding. After giving effect to the
receipt of $28.6 million of estimated net proceeds from the Offering and the
completion of the Conversion, the net tangible book value of the Common Stock
outstanding at June 30, 1997 would have been $40.3 million, or $7.55 per
share, representing an immediate increase in net tangible book value of
approximately $3.42 per share to current stockholders and an immediate
dilution of $4.95 per share (the difference between the initial public
offering price and the net tangible book value per share after the Offering)
to persons purchasing Common Stock in the Offering. The following table
illustrates such per share dilution:
<TABLE>
<S> <C> <C>
Initial public offering price................................. $12.50
Net tangible book value before the Offering................. $4.13
Increase in net tangible book value attributable to new
investors.................................................. 3.42
-----
Net tangible book value after giving effect to the Offering... 7.55
------
Dilution in net tangible book value to new investors.......... $ 4.95
======
</TABLE>
The following table sets forth the number of shares of Common Stock
purchased from the Company, the total consideration paid and the average price
per share paid by existing stockholders and to be paid by purchasers of shares
offered hereby (before deducting underwriting discounts and commissions and
estimated offering expenses):
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION
-------------------- ---------------------- AVERAGE PRICE
NUMBER PERCENTAGE AMOUNT PERCENTAGE PER SHARE
--------- ---------- ----------- ---------- -------------
<S> <C> <C> <C> <C> <C>
Existing stockholders... 2,833,333 53.1% $16,989,011 35.2% $ 6.00
New investors........... 2,500,000 46.9 31,250,000 64.8 12.50
--------- ----- ----------- -----
Total................. 5,333,333 100.0% $48,239,011 100.0%
========= ===== =========== =====
</TABLE>
The preceding table does not include 375,000 shares reserved for future
issuance under the Company's 1997 Incentive Plan, of which 260,000 shares are
issuable upon exercise of outstanding options with an exercise price equal to
the initial public offering price set forth on the cover page of this
Prospectus, or 9,280 shares of Common Stock issuable upon exercise of
outstanding warrants. See "Executive Compensation and Other Information" and
"Description of Capital Stock--Warrants."
21
<PAGE>
CAPITALIZATION
The following table sets forth the capitalization of the Company as of June
30, 1997 on a historical basis and as adjusted to give effect to the
Conversion and the Offering and the application of the estimated net proceeds
therefrom. The following table should be read in conjunction with the Combined
Financial Statements of the Company and the related notes and the other
information contained elsewhere in this Prospectus, including the information
set forth in "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
<TABLE>
<CAPTION>
JUNE 30, 1997
-------------------
ACTUAL AS ADJUSTED
------- -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt (excluding current portion)(1).............. $ 5,035 $ 35
------- -------
Owners' equity:
Partners' capital........................................ 12,522 --
Preferred Stock, $.01 par value, 5,000,000 shares
authorized; no shares outstanding actual and as
adjusted................................................ -- --
Common Stock, $.01 par value, 25,000,000 shares
authorized; no shares issued and outstanding, actual;
5,333,333 shares issued and outstanding, as
adjusted(1)............................................. -- 53
Additional paid-in capital............................... -- 41,032
------- -------
Total owners' equity....................................... 12,522 41,085
------- -------
Total capitalization....................................... $17,557 $41,120
======= =======
</TABLE>
- --------
(1) As of October 20, 1997, the outstanding principal balance of long-term
debt (excluding current portion) was approximately $10.0 million.
(2) Excludes 260,000 shares of Common Stock issuable upon exercise of
outstanding employee stock options, with an exercise price equal to the
initial public offering price set forth on the cover page of this
Prospectus, and 9,280 shares of Common Stock issuable upon exercise of
outstanding warrants. See "Executive Compensation and Other Information--
1997 Incentive Plan," "Description of Capital Stock--Warrants" and Note 9
of Notes to Combined Financial Statements.
22
<PAGE>
PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS
The following unaudited Pro Forma Condensed Combined Statements of
Operations for the year ended December 31, 1996 and for the six months ended
June 30, 1996 give effect to the Company's sale of a 50% working interest in
its Antelope Creek field as if the sale had been consummated as of January 1,
1996. See "The Company--Company History--Uinta Basin." The unaudited Pro Forma
Condensed Combined Statements of Operations are not necessarily indicative of
the results of operations that would have occurred had the transaction been
effected on the assumed dates. Additionally, future results may vary
significantly from the results reflected in the unaudited Pro Forma Condensed
Combined Statements of Operations due to normal production declines, changes
in prices, future development and acquisition activity and other factors.
These statements should be read in conjunction with the Company's audited
Combined Financial Statements and related notes as of and for the years ended
December 31, 1994, 1995 and 1996 and the Company's unaudited Combined
Financial Statements and related notes as of and for the six months ended June
30, 1997 and 1996, included elsewhere in this Prospectus.
23
<PAGE>
PETROGLYPH ENERGY, INC.
PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ----------
<S> <C> <C> <C>
Oil and natural gas revenues........... $5,457,689 $(1,057,000)(1) $4,400,689
---------- ----------- ----------
Total operating revenues............. 5,457,689 (1,057,000) 4,400,689
Lease operating expenses............... 2,368,973 (415,000)(1) 1,953,973
Production taxes....................... 248,848 (44,000)(1) 204,848
Exploration costs...................... 68,818 68,818
Depreciation, depletion and
amortization.......................... 2,805,693 (447,000)(2) 2,358,693
General and administrative expenses.... 902,409 902,409
---------- ----------- ----------
Total operating expenses............. 6,394,741 (906,000) 5,488,741
Interest income, net................... 40,580 107,000 (3) 147,580
Gain on sales of property and
equipment, net........................ 1,383,766 (1,314,000)(4) 69,766
---------- ----------- ----------
Net income (loss) before taxes......... 487,294 (1,358,000) (870,706)
Pro forma tax expense(5)............... 190,044 (190,044) --
---------- ----------- ----------
Net income (loss)...................... $ 297,250 $(1,167,956) $ (870,706)
========== =========== ==========
</TABLE>
- --------
(1) To reduce oil and natural gas revenues, production taxes, lease operating
expenses and exploration costs from 100% of such amounts for the Company's
Antelope Creek field for the period from January 1, 1996 to June 1, 1996
(the effective date of the sale of a 50% interest in this field) to 50% of
such amounts.
(2) To reflect depreciation, depletion and amortization expense on the
Antelope Creek field as if the Company had owned a 50% working interest
for all of 1996.
(3) To reduce interest expense based on the reduction in outstanding debt as
if proceeds from the sale were used to reduce outstanding debt as of
January 1, 1996.
(4) To remove the gain recognized on sale of the 50% interest in the Antelope
Creek properties.
(5) The pro forma tax expense was computed at the federal statutory rate of
35% and an average of the state statutory rates for those states in which
the Company has operations of 4% for each period presented.
24
<PAGE>
PETROGLYPH ENERGY, INC.
PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1996
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ----------
<S> <C> <C> <C>
Oil and natural gas revenues........... $3,135,717 $(1,057,000)(1) $2,078,717
---------- ----------- ----------
Total operating revenues............. 3,135,717 (1,057,000) 2,078,717
Lease operating expense................ 1,328,971 (415,000)(1) 913,971
Production taxes....................... 120,841 (44,000)(1) 76,841
Exploration costs...................... 41,610 41,610
Depreciation, depletion and
amortization.......................... 1,277,317 (447,000)(2) 830,317
General and administrative expenses.... 590,248 590,248
---------- ----------- ----------
Total operating expenses............. 3,358,987 (906,000) 2,452,987
Interest income, net................... 15,543 107,000 (3) 122,543
Gain (loss) on sales of property and
equipment, net........................ 1,173,801 (1,314,000)(4) (140,199)
---------- ----------- ----------
Net income (loss) before taxes......... 966,074 (1,358,000) (391,926)
Pro forma tax expense(5)............... 376,769 (376,769) --
---------- ----------- ----------
Net income (loss)...................... $ 589,305 $ (981,231) $ (391,926)
========== =========== ==========
</TABLE>
- --------
(1) To reduce oil and natural gas revenues, production taxes, lease operating
expenses and exploration costs from 100% of such amounts for the Company's
Antelope Creek field for the period from January 1, 1996 to June 1, 1996
(the effective date of the sale of a 50% interest in this field) to 50% of
such amounts.
(2) To reflect depreciation, depletion and amortization expense on the
Antelope Creek field as if the Company had owned a 50% working interest
for all of 1996.
(3) To reduce interest expense based on the reduction in outstanding debt as
if proceeds from the sale were used to reduce outstanding debt at January
1, 1996.
(4) To remove the gain recognized on sale of the 50% interest in the Antelope
Creek properties.
(5) The pro forma tax expense was computed at the federal statutory rate of
35% and an average of the state statutory rates for those states in which
the Company has operations of 4% for each period presented.
25
<PAGE>
SELECTED COMBINED FINANCIAL DATA
The following table sets forth certain summary combined consolidated
financial data of the Company. The information should be read in conjunction
with the Combined Financial Statements and notes thereto included elsewhere in
this Prospectus. The Company acquired significant and disposed of certain
producing oil and natural gas properties in certain of the periods presented
which affect the comparability of the historical financial and operating data
for the periods presented. The Company's predecessor was classified as a
partnership for federal income tax purposes and, therefore, no income taxes
were paid by the Company prior to the Conversion.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------- --------------------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1) HISTORICAL
----------------------------------- ------------ ---------- ------------ ----------
1993 1994 1995 1996 1996 1996 1996 1997
------- ------- -------- ------- ------------ ---------- ------------ ----------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Operating revenues:
Oil sales.............. $ 224 $ 1,644 $ 3,217 $ 4,459 $3,523 $2,544 $1,608 $ 1,725
Natural gas sales...... 182 796 1,016 999 878 592 471 513
Other.................. 86 45 36 -- -- -- -- 69
------- ------- -------- ------- ------ ------ ------ -------
Total operating
revenues............. 492 2,485 4,269 5,458 4,401 3,136 2,079 2,307
------- ------- -------- ------- ------ ------ ------ -------
Operating expenses:
Lease operating........ 238 1,601 2,260 2,369 1,954 1,329 914 841
Production taxes....... 9 89 188 249 205 121 77 98
Exploration costs...... -- 70 376 69 69 42 42 --
Depreciation, depletion
and amortization...... 153 1,977 2,302 2,806 2,359 1,277 830 1,020
Impairments............ -- -- 109 -- -- -- -- --
General and
administrative........ 278 956 1,064 902 902 590 590 546
------- ------- -------- ------- ------ ------ ------ -------
Total operating
expenses............. 678 4,693 6,299 6,395 5,489 3,359 2,453 2,505
------- ------- -------- ------- ------ ------ ------ -------
Operating loss......... (186) (2,208) (2,030) (937) (1,088) (223) (374) (198)
Other income
(expenses):
Interest income
(expense), net........ -- (93) (216) 40 147 15 122 19
Gain (loss) on sales of
property and
equipment, net........ 63 44 (138) 1,384 70 1,174 (140) 6
------- ------- -------- ------- ------ ------ ------ -------
Net income (loss)
before income taxes... (123) (2,257) (2,384) 487 (871) 966 (392) (173)
Pro forma tax
expense(2)............ -- -- -- (190) -- (377) -- --
------- ------- -------- ------- ------ ------ ------ -------
Net income (loss)...... $ (123) $(2,257) $ (2,384) $ 297 $ (871) $ 589 $ (392) $ (173)
======= ======= ======== ======= ====== ====== ====== =======
Supplemental pro forma
earnings (loss) per
common share(5)....... $ (.31) $ (.05)
====== =======
STATEMENT OF CASH FLOWS
DATA:
Net cash provided by
(used in):
Operating activities... $ 4 $ (67) $ 347 $ 4,129 $ 906 $ 87
Investing activities... (1,084) (8,131) (9,580) 303 2,816 (5,627)
Financing activities... 1,418 8,119 10,049 (3,930) (100) 4,335
OTHER FINANCIAL DATA:
Capital expenditures... $ 1,136 $ 8,277 $ 10,443 $ 8,665 $4,596 $ 6,367
Adjusted EBITDA(3)..... 30 (117) 619 3,322 $1,110 2,270 $ 208 828
Operating cash
flow(4)............... (33) (233) 608 2,024 1,628 795
</TABLE>
<TABLE>
<CAPTION>
JUNE 30, 1997
-------------------------
DECEMBER 31, 1996 HISTORICAL AS ADJUSTED(6)
----------------- ---------- --------------
<S> <C> <C> <C>
CONSOLIDATED BALANCE SHEET DATA: (UNAUDITED)
Cash and cash equivalents......... $ 1,578 $ 372 $18,935(7)
Working capital................... (541) (996) 17,567(7)
Total assets...................... 17,470 23,545 47,107
Total long-term debt.............. 52 5,035 35
Total owners' equity.............. 12,695 12,522 41,085
</TABLE>
26
<PAGE>
- -------
(1) The 1996 Pro Forma amounts reflect results of operations as if the June 1,
1996 disposition of the 50% interest in the Antelope Creek properties
occurred on January 1, 1996.
(2) The pro forma tax expense was computed at the federal statutory rate of
35% and an average of the state statutory rates for those states in which
the Company has operations of 4% for each period presented.
(3) Adjusted EBITDA (as used herein) is calculated by adding interest, income
taxes, depreciation, depletion and amortization, impairments and
exploration costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. The Company did not
incur impairment expense for any period reported except for $109,000 for
the year ended December 31, 1995. Exploration costs were zero, $70,000,
$376,000 and $69,000 for each of the years ended December 31, 1993, 1994,
1995 and 1996 and $69,000 for the pro forma year ended December 31, 1996.
Exploration costs were $42,000 for the historical and pro forma six months
ended June 30, 1996 and zero for the historical six months ended June 30,
1997. Adjusted EBITDA is presented not as a measure of operating results,
but rather as a measure of the Company's operating performance and ability
to service debt. Adjusted EBITDA is not intended to represent cash flows
for the period; nor has it been presented as an alternative to net income
(loss) or operating income (loss) nor as an indicator of the Company's
financial or operating performance. Management believes that Adjusted
EBITDA provides supplemental information about the Company's ability to
meet its future requirements for debt service, capital expenditures and
working capital. Management monitors trends in Adjusted EBITDA, as well as
the trends in revenues and net income (loss), to aid it in managing its
business. Management believes that the recent increases in Adjusted EBITDA
are indicative of the increased production volumes and decreased operating
costs experienced by the Company. Adjusted EBITDA should not be considered
in isolation, as a substitute for measures of performance prepared in
accordance with generally accepted accounting principles or as being
comparable to other similarly titled measures of other companies, which
are not necessarily calculated in the same manner.
(4) Operating cash flow is defined as net income plus adjustments to net
income to arrive at net cash provided by operating activities before
changes in working capital.
(5) Pro forma earnings (loss) per common share is calculated giving effect to
the sale of zero and 430,108 shares as of January 1, 1996 and 1997,
respectively, out of the 2,500,000 shares offered hereby. Weighted average
common shares outstanding used in the calculation of pro forma earnings
(loss) per common share for the year ended December 31, 1996 and the six
months ended June 30, 1997 were 2,833,333 and 3,263,441 shares,
respectively, as compared to the 5,333,333 common shares that will be
outstanding after the Offering.
(6) Adjusted to give effect to the sale of 2,500,000 shares of Common Stock
offered hereby and the application of the estimated net proceeds
therefrom. See "Use of Proceeds" and "Capitalization."
(7) Also includes the effect of the repayment of an additional $5.0 million of
indebtedness incurred subsequent to June 30, 1997.
27
<PAGE>
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 oil and natural gas reserves, oil and
natural gas production and cash flow per share through (i) the development of
the Company's drillsite inventory, (ii) the exploitation of the Company's
existing reserve base, (iii) the control of operations and (iv) the
acquisition of additional interests in oil and natural gas properties that
meet its selection criteria.
The following table sets forth certain operating data of the Company for the
periods presented:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------ ----------------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1) HISTORICAL
-------------------------- ------------ ---------- ------------ ----------
1994 1995 1996 1996 1996 1996 1997
-------- -------- -------- ------------ ---------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (Bbls)............. 110,373 182,704 262,910 213,535 141,775 94,542 117,770
Natural gas (Mcf)...... 485,062 659,202 553,770 461,292 358,420 271,431 243,095
Total (BOE)........... 191,217 292,571 355,205 290,417 201,512 139,781 158,286
AVERAGE SALES PRICE PER
UNIT(2):
Oil (per Bbl)(3)....... $ 14.89 $ 17.61 $ 16.96 $ 16.50 $ 17.94 $ 17.01 $ 14.65
Natural gas (per Mcf).. 1.64 1.54 1.80 1.90 1.65 1.74 2.11
BOE.................... 12.76 14.47 15.36 15.15 15.56 14.87 14.14
COSTS PER BOE:
Lease operating
expenses.............. $ 8.38 $ 7.73 $ 6.67 $ 6.73 $ 6.60 $ 6.54 $ 5.31
Production and property
taxes................. 0.47 0.64 0.70 0.70 0.60 0.55 0.62
General and
administrative........ 5.00 3.64 2.54 3.11 2.93 4.22 3.45
Depreciation, depletion
and amortization...... 10.34 7.87 7.90 8.12 6.34 5.94 6.45
Average finding costs.. 3.92 10.96 2.86(4) -- -- -- 2.55(4)
</TABLE>
- --------
(1) The 1996 Pro Forma amounts reflect results of operations as if the June 1,
1996 disposition of the 50% interest in the Antelope Creek field had
occurred on January 1, 1996.
(2) Before deduction of production taxes.
(3) Excluding the effects of losses from crude oil hedging transactions and
amortization of deferred revenue, the weighted average sales price per Bbl
of oil was $20.22 for the year ended December 31, 1996, $18.22 for the
historical six months ended June 30, 1996, $17.43 for the pro forma six
months ended June 30, 1996 and $15.96 for the historical six months ended
June 30, 1997.
(4) The calculation of average finding costs for the year ended December 31,
1996 and the six months ended June 30, 1997 includes future development
costs of $16.5 million and $1.7 million, respectively. Average finding
costs per BOE excluding these amounts were $0.79 and $1.78 for the year
ended December 31, 1996 and the six months ended June 30, 1997,
respectively.
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.
28
<PAGE>
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
Six Months Ended June 30, 1997 Compared to Six Months Ended June 30, 1996
OPERATING REVENUES
Oil revenues decreased by 32% to $1,725,000 for the six months ended June
30, 1997 as compared to $2,544,000 for the 1996 period primarily as a result
of a decrease in the Company's oil production volume of 24,005 Bbls and a
decline in average oil sales prices from $17.94 per Bbl in the 1996 period to
$14.65 in 1997. The decline in the Company's oil production is due to the sale
of the 50% interest in the Utah properties in June 1996 and the sale of
certain other non-strategic properties in Texas in March 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 $3.29 per Bbl was due to a reduction
in demand for the Company's production as a result of a temporary shutdown for
major maintenance of one of the refineries which is a primary user of the
Company's Utah production during late 1996 and early 1997, a crude oil hedge
loss of $114,000 and amortization of deferred revenue of $46,000. The
Company's average oil sales price for the six months ended June 30, 1997,
excluding the effects of the hedge loss and amortization of deferred revenue
was $15.96 per Bbl.
Natural gas revenues declined by 13% to $513,000 for the six months ended
June 30, 1997, as compared to $592,000 for the 1996 period primarily due to a
decline in natural gas production of 115,325 Mcf due to dispositions of
certain non-strategic natural gas properties during 1996, the sale of the 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 partially 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. The
decline in natural gas production volumes was partially offset by an increase
in average natural gas sales price to $2.11 per Mcf during the six months
ended June 30, 1997, as compared to $1.65 per Mcf for the 1996 period.
OPERATING EXPENSES
Lease operating expenses decreased to $841,000 for the six months ended June
30, 1997, as compared to $1,329,000 for the same 1996 period primarily as a
result of 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 March 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. In addition, the Company's
lease operating expenses on a per BOE basis for its Utah properties declined
by 32% to $4.13 per BOE during the 1997 period as compared to $6.08 per BOE
for the 1996 period. This decline in lease operating expenses per BOE is due
to the benefits of increasing economies of scale as the production volumes of
the Utah properties continue to increase 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 20% to
$1,020,000 for the six months ended June 30, 1997, as compared to $1,277,000
for the same period in 1996 primarily as a result of 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 March 1997 partially
offset by increased production from the Company's remaining interest in the
Utah properties.
Exploration costs declined by $42,000 to zero for the six months ended June
30, 1997 as compared to the same period in 1996, as the Company's exploratory
drilling activities were all successful during the period and no geological
and geophysical work was performed.
29
<PAGE>
General and administrative expenses declined by 7% to $546,000 for the six
months ended June 30, 1997, as compared to $590,000 for the same 1996 period.
This decrease was due to an increase in overhead charges billed to non-
operating partners of $160,000 during 1997 due to sale of a 50% interest in
the Utah properties in June 1996 and the significant increase in the number of
Company-operated wells as a result of the aggressive drilling program on the
Company's Utah properties. This decline was partially offset by an increase in
engineering, geological and administrative staff as a result of the increased
development activity.
OTHER INCOME (EXPENSES)
Gain on sale of assets declined to $6,000 for the six month period ended
June 30, 1997, as compared to $1,174,000 for the same 1996 period due to a
gain of $1,314,000 recognized on the sale of the 50% interest in the Utah
properties in June 1996.
Year Ended December 31, 1996 Compared to December 31, 1995
OPERATING REVENUES
Oil revenues increased by 39% to $4,459,000 in 1996 as compared to
$3,217,000 in 1995 primarily as a result of an increase in the Company's oil
production volume of 80,206 Bbls in 1996. The increase in production volume is
primarily the result of the Company's aggressive drilling program on its Utah
properties during the last six months of 1996. This increase was partially
offset by a decline in average oil sales prices from $17.61 per Bbl in 1995 to
$16.96 per Bbl in 1996. The decline in the average oil sales price was due to
a reduction in demand for the Company's Utah oil production during the second
half of 1996 as a result of a temporary shutdown for major maintenance of one
of the refineries which is a primary purchaser of the Company's Utah
production, a crude oil hedge loss of $128,000 and amortization of deferred
revenue of $524,000. The Company's average 1996 sales price of oil excluding
the effects of the hedge loss and amortization of deferred revenue was $20.22
per Bbl.
Natural gas revenues declined by 2% to $999,000 in 1996 as compared to
$1,016,000 in 1995 primarily due to a decline in natural gas sales production
to 553,770 Mcf in 1996 as compared to 659,202 Mcf in 1995. The decline in
natural gas sales production is attributable to disposition of certain
nonstrategic natural gas properties during 1996 and reduced gas production
volumes from the Utah properties due to inception of the secondary oil
recovery program. The decrease in natural gas production volumes was partially
offset by an increase in average sales prices of natural gas to $1.80 per Mcf
in 1996 as compared to $1.54 per Mcf in 1995.
OPERATING EXPENSES
Lease operating expenses increased to $2,369,000 in 1996 as compared to
$2,260,000 in 1995 primarily as a result of an increase in the number of
producing wells in which the Company has an interest due to the 1996 drilling
program, partially offset by a reduction in lease operating expenses per BOE
to $6.67 in 1996 as compared to $7.73 in 1995. The 14% decrease in lease
operating expenses on a per BOE basis is primarily due to a decline in
production costs of the Utah properties due to the Company's continued focus
on reduction of operating costs through improved efficiencies. This decrease
is partially offset by an increase in per BOE production costs of the Company
non-Utah properties.
Production taxes increased by 33%, or $61,000, from 1995 to 1996. This
increase is due primarily to a 29% increase in the Company's oil and natural
gas revenues during 1996 as compared to 1995.
Depreciation, depletion and amortization expense increased by 22% to
$2,806,000 in 1996 as compared to $2,302,000 in 1995, primarily as a result of
increased production volumes due to 1996 drilling activity. Depreciation,
depletion and amortization expense increased slightly to $7.90 per BOE in 1996
as compared to $7.87 per BOE in 1995.
30
<PAGE>
Exploration costs declined by 82% to $69,000 in 1996 as compared to $376,000
in 1995 due to a reduction in dry hole costs in 1996.
General and administrative expenses decreased by 15% to $902,000 in 1996 as
compared to $1,064,000 in 1995. This decline was due to an increase in
overhead charges billed to non-operating partners of $484,000 as a result of
increased activity on the Utah properties during 1996 due to the significant
number of wells drilled in the second half of 1996. This decline was partially
offset by an increase in engineering and administrative staff as a result of
the increased development activity.
OTHER INCOME (EXPENSES)
Interest income (expense), net, improved by $256,000 as compared to 1995 to
$40,000 of income in 1996 primarily as a result of a reduction in average
outstanding debt and an increase in interest capitalized of $44,000 on the
Company's Utah properties development project.
Gain on sale of assets was $1,384,000 in 1996 as compared to a loss of
$138,000 in 1995. The gain in 1996 is primarily due to a gain of $1,314,000
recognized on the sale of the 50% interest in the Utah properties in
June 1996.
Year Ended December 31, 1995 Compared to December 31, 1994
OPERATING REVENUES
Oil revenues increased by 96% to $3,217,000 in 1995 as compared to
$1,644,000 in 1994. This increase was primarily due to an increase in oil
production volumes of 72,331 Bbls as a result of the acquisition of an
additional 50% interest in the Antelope Creek and Duchesne fields in July 1995
which brought the Company's working interest to 100%. In addition, the average
oil sales price increased to $17.61 per Bbl in 1995 from $14.89 per Bbl in
1994.
Natural gas revenues increased by 28% to $1,016,000 in 1995 as compared to
$796,000 in 1994 primarily due to an increase in natural gas production
volumes of 174,140 Mcf as a result of the acquisition of an additional 50%
interest in the Utah properties in July 1995. This increase was partially
offset by a decline in the average sales price of natural gas to $1.54 per Mcf
in 1995 from $1.64 per Mcf in 1994.
OPERATING EXPENSES
Lease operating expense increased by 41% to $2,260,000 in 1995 as compared
to $1,601,000 in 1994, primarily as a result of the acquisition of an
additional 50% interest in the Utah properties in July 1995. This increase was
partially offset by a decline in lease operating expenses of $0.65 per BOE in
1995 as compared to 1994 due to the Company's focus on reduction of lease
operating expense through improved efficiency of operations.
Production and property taxes increased by 110%, or $98,000, in 1995 as
compared to 1994. This increase is primarily the result of the increase in oil
and natural gas revenues during 1995 as compared to 1994 which is discussed
above.
Depreciation, depletion and amortization expense increased by 16% to
$2,302,000 in 1995 as compared to $1,977,000 in 1994 primarily as a result of
increased production volumes due to the acquisition of an additional 50%
interest in the Utah properties in July 1995. Depreciation, depletion and
amortization expense declined to $7.87 per BOE in 1995 as compared to $10.34
per BOE in 1994 as a result of increased proved reserves due to upward reserve
revisions on properties that existed at December 31, 1994, and lower
depreciation rates on 1995 acquisitions.
31
<PAGE>
During 1995, the Company recognized an impairment of $109,000 in the
carrying value of its Kansas properties, in accordance with Statement of
Financial Accounting Standards No. 121, "Accounting for Impairment of Long-
Lived Assets to be Disposed Of."
Exploration costs increased to $376,000 in 1995 as compared to $70,000 in
1994 primarily due to $316,000 of exploratory dry hole costs on two
exploratory wells on the Company's Kansas properties during 1995. There were
no exploratory dry hole costs in 1994.
General and administrative expense increased by 11% to $1,064,000 in 1995 as
compared to $956,000 in 1994 primarily as a result of an increase in
engineering, accounting and clerical staff to handle the increased activity as
a result of the Company's growth and a reduction in overhead changes billed to
non-operating partners of $53,000 due primarily to acquisition in July 1995 of
the remaining 50% interest in the Utah properties.
OTHER INCOME (EXPENSES)
Interest expense, net, increased by 131% to $216,000 in 1995 as compared to
$93,000 in 1994. This was primarily the result of an increase in the average
balance of outstanding debt in 1995 as compared to 1994 and was partially
offset by an increase in interest capitalized on development projects of
$114,000 from 1995 to 1994.
The Company recognized a loss on sale of assets in 1995 of $138,000 as
compared to a gain of $44,000 in 1994. The 1995 loss was caused primarily by a
loss on sale of the Company's investment in certain producing properties in
Kansas and Oklahoma.
LIQUIDITY AND CAPITAL RESOURCES
Overview
The Company's primary sources of liquidity are cash flow from operations and
borrowings under the Credit Agreement. The Company's cash flow requirements
other than for operations are generally for the development of its Uinta Basin
oil and natural gas properties.
The Company's primary financial resource is its oil and natural gas reserves
in the Uinta Basin of Utah. In addition, the Company entered into the Original
Agreement in May 1995 with Texas Commerce Bank National Association. In the
past, the Company's owners have provided a significant portion of the capital
needed by the Company to finance its acquisitions and development program.
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.
32
<PAGE>
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,
-------------------------------- SIX MONTHS ENDED
1994 1995 1996 JUNE 30, 1997
---------- ---------- ---------- ----------------
<S> <C> <C> <C> <C>
Acquisition costs:
Unproved properties......... $ 52,685 $ 8,206 $ 490,487 $ 416,601
Proved properties........... 5,193,043 4,718,201 -- --
Development costs............. 1,311,272 3,448,972 6,983,715 4,057,976
Exploration costs............. 69,570 316,089 -- --
Improved recovery costs....... 271,276 154,023 327,027 99,531
---------- ---------- ---------- ----------
Total......................... $6,897,846 $8,645,491 $7,801,229 $4,574,108
========== ========== ========== ==========
</TABLE>
During the last six months of 1997, the Company plans to focus its efforts
on the continued development of its improved recovery projects in the Uinta
Basin.
The Company plans to drill approximately 45 gross (29 net) wells in the
Uinta Basin during the last six months of 1997 at a projected cost of $8.5
million. In addition, the Company plans to drill up to 10 pilot wells in the
Raton Basin at an estimated cost of up to $3.0 million during the same time
period.
Capital Resources
During the first six months of 1997, the Company generated cash flow from
operating activities of $87,000 and received proceeds from sales of oil and
natural gas properties of $740,000 and from borrowings against the Credit
Agreement of $5,000,000. During the same period, the Company incurred capital
costs of $6,367,000, consisting primarily of the development of its Uinta
Basin properties and the enhanced oil recovery infrastructure.
During 1996, the Company generated cash flow from operating activities of
$4,129,000 and received proceeds from sales of oil and natural gas properties
of $8,968,000. During the same period, the Company incurred $8,665,000 in
capital expenditures and repaid $5,909,000 of outstanding debt.
The Company's working capital decreased from $1,133,000 at December 31,
1995, to a deficit of ($541,000) and ($996,000) at December 31, 1996 and June
30, 1997, respectively. This was due to an increase in spending and an
increase in trade payables which is the result of the increased development
activity in the Uinta Basin during the last six months of 1996 and the first
six months of 1997 and the retirement of all outstanding long-term debt during
1996. These decreases were partially offset by increased cash flow as a result
of higher average prices for oil and natural gas production and proceeds
received from the June 1, 1996 sale of a 50% interest in the Antelope Creek
field.
The Company's cash flow from operations during the last six months of 1997
is not expected to be adequate to fund the Company's operations and planned
Uinta Basin and Raton Basin development programs. The Company anticipates that
the remaining available borrowing capacity under the Credit Agreement,
including the overdraft facility, will be sufficient to meet its estimated
capital expenditure requirements until such time as the net proceeds from the
Offering become available, and that the net proceeds from the Offering will be
sufficient to meet its estimated capital expenditure requirements for the 12
months following the Offering. The Company believes that after such 12-month
period it will require a combination of additional financing and cash flow
from operations to implement its future development plans. The Company
currently does not have any arrangements with respect to, or sources of,
additional financing other than the Credit Agreement, and there can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all. In the event a sufficient amount of capital is not
available, the Company may be unable to develop its Uinta Basin properties in
accordance with the planned schedule discussed elsewhere in this Prospectus.
33
<PAGE>
Financing
In May 1995, the Company entered into a credit agreement with Texas Commence
Bank National Association (the "Original Agreement"). The Original Agreement
was a combination credit facility with a two-year revolving credit agreement
which originally expired on May 25, 1997, at which time all balances
outstanding under the revolving credit agreement were to convert to a term
loan, expiring on October 1, 1999. The borrowing base was redetermined at $7.5
million on July 2, 1997. This effectively allowed the Company to continue to
borrow on the facility in place at June 30, 1997. On September 15, 1997, the
Company amended the Original Agreement and entered into the Credit Agreement
with Chase. The Credit Agreement includes a $20.0 million combination credit
facility with a two-year revolving credit agreement with an original borrowing
base of $7.5 million to be redetermined semi-annually ("Tranche A"), which
expires on September 15, 1999, at which time all balances outstanding under
Tranche A will convert to a term loan expiring on September 15, 2002.
Additionally, the Credit Agreement contains a separate revolving facility of
$2.5 million ("Tranche B"), which expires on March 15, 1999, at which time all
balances outstanding become immediately payable. Subsequent to June 30, 1997,
the Company has borrowed an additional $5.0 million, for a total outstanding
obligation under this facility of $10.0 million at October 20, 1997. The
Company had no balances outstanding under the Original Agreement at December
31, 1996. Interest on borrowings outstanding under both Tranche A and Tranche
B 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 each tranche.
INFLATION AND CHANGES IN PRICES
The Company's revenue and the value of its oil and natural gas properties
have been, and will continue to be, affected by changes in oil and natural gas
prices. The Company's ability to obtain capital through borrowings and other
means is also substantially dependent on 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.
HEDGING TRANSACTIONS
In the past, the Company has entered into hedging contracts of various types
in an attempt to manage price risk with regard to a portion of the Company's
crude and natural gas production. While use of these hedging arrangements
limit the downside risk of price declines, such arrangements may also limit
the benefits which may be derived from price increases.
The Company historically has used various financial instruments such as
collars, swaps and futures contracts in an attempt to manage its price risk.
Monthly settlements on these financial instruments are typically based on
differences between the fixed prices specified in the instruments and the
settlement price of certain future contracts quoted on the NYMEX or certain
other indices. The instruments which have been historically used by the
Company have not had a contractual obligation which requires or allows the
future physical delivery of the hedged products.
The Company had one open hedging contract at June 30, 1997, which is a crude
oil collar on 378,000 Bbls of oil with a floor price of $17.00 per Bbl and a
ceiling price of $20.75 per Bbl indexed to the NYMEX light crude future
settlement price. See Note 7 to the Notes to Combined Financial Statements.
This contract covers 378,000 Bbls of oil over the next two and one-half years
as follows:
<TABLE>
<CAPTION>
YEAR BBLS
---- -------
<S> <C>
1997................................. 69,000
1998................................. 150,000
1999................................. 159,000
-------
Total............................... 378,000
=======
</TABLE>
34
<PAGE>
ENVIRONMENTAL AND OTHER LAWS AND REGULATIONS
The Company's business is subject to certain federal, state, tribal and
local laws and regulations relating to the exploration for and the
development, production and transportation of oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have
become more stringent in recent years, often imposing greater liability on a
larger number of potentially responsible parties. 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. The Company has no material commitments for capital
expenditures to comply with existing environmental requirements. Nevertheless,
changes in existing environmental laws or in interpretations thereof could
have a significant impact on the operating costs of the Company as well as the
oil and natural gas industry in general.
35
<PAGE>
BUSINESS AND PROPERTIES
GENERAL
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas reserves. Since its
inception in 1993, the Company has grown through leasehold acquisitions which,
together with associated development drilling, have increased the Company's
proved reserves, production, revenue and cash flow. The Company seeks to
develop properties in regions with known producing horizons, significant
available undeveloped acreage and considerable opportunities to increase
reserves, production and ultimate recoveries through development drilling and,
where applicable, enhanced oil recovery techniques. The Company's primary
activities are focused in the Uinta Basin in Utah, where it is implementing
enhanced oil recovery projects in the Lower Green River formation of the
Greater Monument Butte Region. The Company anticipates spending approximately
$35 million in 1997 and 1998 in connection with these projects. The Company
has identified several other formations in the Uinta Basin above and below the
Lower Green River formation that it believes have the potential to be
commercially productive. The Company recently acquired 56,000 gross and net
acres in the Raton Basin in Colorado. The Company plans to spend up to
approximately $5.0 million to initiate a pilot coalbed methane project to
determine the commercial viability of development of this area.
From January 1, 1994 through June 30, 1997, the Company drilled a total of
98 gross (51.5 net) wells, with a success rate of 99% and an average finding
cost of $3.43 per BOE. As of June 30, 1997, the Company had estimated net
proved reserves of approximately 7.7 MMBbls of oil and 20.9 Bcf of natural
gas, or an aggregate of 11.2 MMBOE with a PV-10 of $42.9 million. Of the
Company's estimated proved reserves, 97% are located in the Uinta Basin. At
June 30, 1997, the Company had a total acreage position of approximately
108,000 gross (99,000 net) acres and estimates that it has over 1,000
potential drilling locations based on current spacing, approximately 75 of
which are included in the Company's independent petroleum engineers' estimate
of proved reserves.
Uinta Basin. The Uinta Basin is generally recognized as one of the largest
onshore basins in the contiguous United States in terms of total hydrocarbons
in place. The Uinta Basin is a major onshore depositional and structural basin
containing the remnants of an ancient fresh water lake that broadly deposited
sand bars over the basin as the shoreline of the lake expanded and contracted
over time. Based on electric log analysis, the Company believes that
approximately 26 different horizons of oil and natural gas bearing sands have
been created in the Lower Green River formation by the ancient lake and exist
throughout its development area. As of December 31, 1996, approximately 450
MMBbls of oil and 1.6 Tcf of natural gas had been recovered from over 2,750
wells drilled in the Uinta Basin, including approximately 148 MMBbls of oil
and 358 Bcf of natural gas from approximately 930 wells drilled in a 900
square mile area of the Uinta Basin known as the Greater Monument Butte Region
located along the southern shoreline of the ancient lake.
The Company is currently implementing enhanced oil recovery projects using
waterflood techniques designed to repressure zones within the 1,500-foot thick
Lower Green River formation in the Greater Monument Butte Region. In 1996, the
DOE published a study of a similar enhanced oil recovery project and concluded
that such a program could ultimately increase the recovery of the original oil
in place in the Lower Green River formation from approximately 5% to up to
21%. The Company believes the results of the DOE's study are applicable to its
enhanced oil recovery project in the Greater Monument Butte Region. The
Company also believes oil and natural gas exist at depths above and below this
formation throughout the Greater Monument Butte Region.
The Company is an experienced operator in the Uinta Basin. From January 1,
1994 through June 30, 1997, the Company drilled 90 gross (46 net) new
development and exploratory wells in the Uinta Basin, with a 99% success rate.
As of June 30, 1997, the Company's independent petroleum engineers estimated
that the Company had approximately 75 gross (40 net) proved undeveloped well
locations in the Antelope Creek field in the Uinta Basin. The independent
petroleum engineers attributed an average of 135 MBOE gross proved undeveloped
36
<PAGE>
reserves to such locations with a PV-10 per gross well of approximately
$285,000, net of drilling and completion costs. The Company's net share per
gross well is 58 MBOE with a PV-10 of $152,000, resulting in an aggregate of
approximately 4,340 MBOE with a PV-10 of approximately $11.4 million for such
75 proved undeveloped well locations. The Company believes that as of June 30,
1997, full development of the Company's 38,685 gross undeveloped acres within
the Uinta Basin would support approximately 820 additional drilling locations
based on 40-acre spacing, consisting of approximately 615 locations for
production wells and 205 locations for injection wells, at an estimated
average gross cost of $400,000 per well. In addition to the implementation of
its enhanced oil recovery projects in the Lower Green River formation, the
Company is currently developing the Upper Green River and Wasatch formations
utilizing traditional production methods.
Raton Basin. The Raton Basin, which is located in southeastern Colorado and
northeastern New Mexico, is approximately 80 miles long and 50 miles wide. The
Gas Research Institute has estimated that as of 1993 the Raton Basin held 18
Tcf of recoverable natural gas reserves from coalbed methane, a type of
natural gas produced from a coal source rather than traditional
sandstone/carbonate reservoirs. As of December 31, 1996, the Company estimates
that cumulative production of approximately 7.9 Bcf of natural gas had been
recovered from approximately 140 coalbed methane wells in the Raton Basin, 91%
of which commenced production since January 1, 1995. As of December 31, 1996,
daily production from these wells was approximately 20 MMcf per day.
The Company recently acquired 56,000 gross and net acres in the Raton Basin
of southeastern Colorado for $700,000, where the Company plans to develop
coalbed methane natural gas reserves. During the last ten years, new drilling,
completion and production techniques have led to the development of
substantial new reserves of coalbed methane natural gas in the United States.
Initially, the Company plans to spend up to approximately $5.0 million to
conduct a pilot project to study the feasibility of a full-scale coalbed
methane project. Should the pilot project be successful, based on proposed
spacing, the Company could drill up to 200 wells over the life of the project.
BUSINESS STRATEGY
The Company's strategy, which includes the following key elements, is to
increase its oil and natural gas reserves, oil and natural gas production and
cash flow per share:
. Develop Drillsite Inventory. The Company has established a large
inventory of potential projects by focusing on areas where known
hydrocarbon accumulations have not been fully exploited. The Company is
implementing enhanced oil recovery projects in a development area in the
Uinta Basin that has over 800 drillsite locations for production and
injection wells, and intends to initiate a coalbed methane project in
the Raton Basin that, based upon the results of a pilot project, could
support up to 200 wells. Collectively, these projects provide the
Company with a ten-year inventory of potential drilling locations.
. Exploit Existing Reserve Base. The Company intends to apply management's
extensive geological, engineering and operating expertise to identify,
develop and exploit its existing undeveloped and underdeveloped acreage
portfolio. The Company anticipates capital expenditures in the second
half of 1997 and all of 1998 of approximately $38 million, of which
approximately $18 million will be used to develop existing proved
reserves included in the Company's June 30, 1997 reserve report. The
amount and timing of these expenditures will depend on a number of
factors, including actual drilling results, product prices and
availability of capital.
. Control of Operations. The Company seeks to operate and maintain a
majority working interest position in each of its core properties. These
factors enable the Company to influence directly its projects by
controlling all aspects of drilling, completion and production. In
addition, the Company intends to maintain a low cost overhead structure
by controlling the timing of the development of its properties. By
operating its producing wells, the Company believes it is well
positioned to control the expenses and timing of development and
exploitation of such properties and to better manage cost reduction
efforts.
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. Acquire Additional Property Interests. The Company expects that it will,
from time to time, evaluate acquisitions of oil and natural gas
properties in its principal areas of operations and in other areas that
provide attractive investment opportunities for the addition of reserves
and production and that meet one or more of the Company's selection
criteria: (i) an attractive purchase price that, when combined with the
anticipated capital expenditures, exceeds a targeted internal rate of
return, (ii) the potential to increase reserves and production through
the application of lower risk exploitation and exploration techniques
and (iii) the opportunity for improved operating efficiency.
PRINCIPAL PROPERTIES
The following table sets forth certain information, as of June 30, 1997,
which relates to the principal oil and natural gas properties owned by the
Company.
<TABLE>
<CAPTION>
PROVED RESERVES
------------------------------
TOTAL OIL
GROSS OIL NATURAL GAS EQUIVALENT
REGION ACRES (MBBLS) (MMCF) (MBOE)
------ ------- ------- ----------- ----------
<S> <C> <C> <C> <C>
Utah-Uinta Basin......................... 45,525 7,560 19,755 10,853
Colorado-Raton Basin..................... 55,927 -- -- --
Other.................................... 6,279 164 1,155 356
------- ----- ------ ------
Total.................................. 107,731 7,724 20,910 11,209
======= ===== ====== ======
</TABLE>
UINTA BASIN. The Uinta Basin is a major onshore depositional and structural
basin located in northeast Utah. The American Association of Petroleum
Geologists has estimated that as of 1971 the Uinta Basin held 3.5 billion Bbls
of remaining recoverable oil reserves. In 1996, the Uinta Basin was estimated
by an independent industry publication to contain 7.0 Tcf of remaining
recoverable natural gas reserves. As of December 31, 1996, cumulative
production of approximately 450 MMBbls of oil and 1.6 Tcf of natural gas had
been recovered from approximately 2,750 wells in the Uinta Basin.
The Company's Uinta Basin properties are located in the Greater Monument
Butte Region, an area that begins at the Company's Duchesne field on the west,
extends across the Monument Butte field and ends to the east at the Wonsits
Valley and Red Wash fields. The Greater Monument Butte Region, which is
depicted on the map appearing on the inside front cover page of this
Prospectus, is roughly 15 miles wide and 60 miles long. Hydrocarbons have been
shown to exist throughout the explored sedimentary column. The first
successful enhanced oil recovery project in the Uinta Basin was initiated
approximately 40 years ago. As of June 30, 1996, cumulative production of 148
MMBbls of oil and 358 Bcf of natural gas had been recovered from the Greater
Monument Butte Region.
The principal producing horizons in the Greater Monument Butte Region is the
Lower Green River formation. Commercial production of hydrocarbons has also
occurred from the Uinta, Upper Green River, Wasatch and Mesa Verde formations.
These four reservoir formations contain discontinuous sand bodies of varying
size that are multi-layered and pinch out at the boundaries. Within the
Greater Monument Butte Region, the producing formations have similar time and
depositional characteristics. The producing sands can be correlated as they
occur across the Greater Monument Butte Region.
Development History. Exploratory drilling in the Uinta Basin commenced
around 1900. The first significant hydrocarbon discovery was in 1925 in the
Ashley field. The first enhanced oil recovery program in the Lower Green River
formation consisted of a natural gas injection pilot program in the Red Wash
field beginning in 1957. Beginning in 1960, waterflood programs were conducted
in the Red Wash field in the Lower Green River formation. This project
indicated that enhanced oil recovery techniques were successful in recovering
additional hydrocarbons in the Lower Green River formation and successful
enhanced oil recovery projects followed in the Walker Hallow and Wonsits
Valley fields.
The Department of Energy Study. In 1986, Lomax Exploration Co. ("Lomax")
conducted a study of the Wonsits Valley unit enhanced oil recovery program and
concluded that its Monument Butte field, located 30 miles to the west, had
similar geological and reservoir characteristics. An enhanced oil recovery
unit was formed, and in November 1987, a pilot enhanced oil recovery project
using waterflood technology commenced. Based
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on the initial results, Lomax expanded the program in 1992. In October 1992,
the DOE selected Lomax in cooperation with the University of Utah, for a co-
funded program to study Green River enhanced oil recovery results. An
extensive study ensued utilizing full and side wall cores, advanced wireline
logging technology, computer derived reservoir simulation and laboratory
analysis of crude oil and associated natural gas samples.
In November 1996, the DOE concluded that the utilization of conventional
waterflooding technology could produce significant enhanced oil recoveries
from pressure depleted reservoirs in Green River formations in the 1,400-acre
region of the Monument Butte Unit of the Greater Monument Butte Region, which
includes the Company's three prospect areas. The methods and techniques
employed in the project were predicted by the DOE to be applicable to an area
of about 300 square miles, which is included within the Greater Monument Butte
Region. The DOE concluded that the primary recovery would account for 5% of
the original oil in place. In addition, the DOE concluded that the Lomax
enhanced oil recovery program may increase the ultimate recovery to 21% of
original oil in place.
Recent Enhanced Oil Recovery Projects. Since 1992, nine additional
waterflood projects around the Monument Butte Unit have been commenced. In
addition to the Company's development areas, certain of the units involved in
these projects include the Wells Draw unit (operated by Enserch Exploration,
Inc.) and the Jonah unit (operated by Equitable Resources Energy Company).
Although the enhanced oil recovery techniques studied by the DOE in the
Monument Butte Unit were commenced after a number of years of primary
production, Lomax and other operators in the Uinta Basin have experienced
increases in production and reserves in other fields by initiating waterfloods
during initial production from new wells. The Company's Antelope Creek field
contains the largest single unit of contiguous acreage currently undergoing
enhanced oil recovery (waterflood) operations in the Greater Monument Butte
Region.
Development Approach to the Greater Monument Butte Region. The Company
believes that it can achieve results similar to those experienced by other
operators utilizing waterflood techniques in the Monument Butte, Red Wash and
Wonsits fields in the Greater Monument Butte Region. The Company's enhanced
oil recovery development strategy utilizes waterflood techniques designed to
rebuild and maintain reservoir pressure, which are similar to the techniques
studied by the DOE. Waterflooding involves the injection of water into a
reservoir forcing oil through the formation toward producing wells in the
development area and driving free natural gas in the reservoir back into oil
solution, creating greater pressure within the reservoir and making the oil
more mobile, and increasing the rate of production and ultimate recoverable
volumes.
The Company believes that primary oil recovery, i.e., without waterflooding,
results in the production of approximately 5% of the original oil in place for
wells in the Lower Green River formation of the Greater Monument Butte Region.
By utilizing waterflood techniques, the Company hopes to increase recoveries
from these wells to approximately 25% of the original oil in place. By
introducing enhanced oil recovery techniques during primary production, the
Company believes that cumulative and daily production may increase. Based on
the results of the Company and other operators in the region, the Company
believes that the sands prevalent in the Lower Green River formation of the
Antelope Creek field are analogous to the sands from the same formation of the
Monument Butte, Red Wash and Wonsits fields. The Company is implementing a
similar enhanced oil recovery program in the Antelope Creek field in the
Greater Monument Butte Region. The Company believes that the preliminary
results of its enhanced oil recovery project are comparable to those
recognized by the DOE study and that wells are responding to the waterflood.
When the Company begins enhanced oil recovery development of a field, it
generally drills four wells on 160 acres (based on 40-acre spacing) and uses
one of the four wells as an injection well for its waterflood repressurization
program. In order to optimize the recovery of hydrocarbons through enhanced
oil recovery techniques, the Company utilizes a variety of open hole logs and
other analytical techniques to categorize the different formations in the
Greater Monument Butte Region. The Company plans to drill and evaluate at
least four wells in a group before determining which well to operate as the
water injection well.
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<PAGE>
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations
into the existing and planned infrastructure, including gathering systems,
water distribution and other surface facilities. The Company currently
estimates that the average cost to drill, complete and install the necessary
surface and waterflood facilities will be approximately $400,000 per producing
or injection well. Historically, the Company has been able to minimize cycle
time from drilling to hook-up of wells, which the Company believes should
accelerate cash flow and improve ultimate project economics.
In the future, the Company may consider other enhanced oil recovery
techniques to increase production of oil and natural gas. For example, the
Company anticipates that it may inject produced natural gas, imbibition agents
or surfactants into reservoirs in an effort to further enhance ultimate oil
recovery and increase production rates.
The Company's major projects in the Uinta Basin include:
Antelope Creek Field. The Antelope Creek field lies in the western portion
of the Greater Monument Butte Region. Production in this field first occurred
in July 1983. The potential producing formations in this field are the Uinta,
Upper Green River, Lower Green River, Wasatch and Mesa Verde. The Company owns
a 50% working interest in, and is the operator of, approximately 20,912 gross
(12,668 net) acres within the field.
The Company began operations in the Antelope Creek field in February 1994
and is currently implementing enhanced oil recovery projects using waterflood
technology in 16 separate horizons in the Lower Green River formation. The
initial pilot program commenced in September 1994, and the preliminary
response for affected producing wells has been consistent with the DOE study.
To date, the Company has recorded responses in eight of the 18 horizons and
expects to experience responses in additional horizons as the waterflood
program matures. In July 1997, the Company completed construction of its water
distribution and injection system. This system, which has the capacity to
carry 15,000 Bbls of water per day, includes 43 miles of low and high pressure
steel and polypropylene pipe buried below the frost line. The Company believes
that the system, which was designed to last 50 years, offers operating
flexibility and redundant water supplies and provides lower cost heated water
for completion and production operations. In addition, the Company initiated a
natural gas injection pilot in February 1997 to determine the effectiveness of
natural gas as an alternative or supplement to water as an injection medium.
At June 30, 1997, the Company had drilled 86 gross (43 net) production wells
in the Antelope Creek field and converted 11 gross (5.5 net) wells to
injection wells. At June 30, 1997, the Company owned 136 gross (68 net) wells
in the Antelope Creek field, all of which are operated by the Company. These
wells range in depth from 5,000 feet to greater than 7,000 feet. Average gross
daily production from the Antelope Creek field in July 1997 was 1,607 Bbls of
oil and 2,976 Mcf of natural gas. Approximately 350 gross wells (approximately
260 of which are expected to be utilized as production wells) remain to be
drilled within the current acreage position based on 40-acre spacing.
Duchesne Field. The Duchesne field is located five miles northwest of the
Antelope Creek field. This field was discovered in 1951, and 31 wells have
been drilled in an area of approximately 11,360 acres. The primary producing
formations in this field are the Upper and Lower Green River and Wasatch at
depths ranging from 1,300 to 8,500 feet. In addition to the Lower Green River
formation enhanced oil recovery potential, there is established oil production
from the Wasatch and Upper Green River formations within the field and
adjacent acreage.
The Company began operating in the Duchesne field in February 1994 in
connection with its acquisition of interests in this field and the Antelope
Creek field. At June 30, 1997, the Company owned approximately 11,360 gross
and net acres and operated six active producing wells, not including two wells
currently awaiting completion, and 23 shut-in wells in anticipation of
implementation of waterflood projects and Wasatch formation
40
<PAGE>
recompletions. The Company owns 100% of the working interest in the field.
Average daily production from the Duchesne field in 1996 was 20 Bbls of oil
and 70 Mcf of natural gas.
The Company has yet to commence waterflooding this field. As a result of
geological similarities to the Antelope Creek field, however, the Company
intends during the first half of 1998 to initiate a pilot waterflood area
within the field targeting known Lower Green River oil reservoirs for enhanced
oil recovery. In addition, the Company drilled and completed two wells in the
Upper Green River formation in August 1997. The Company expects that these
wells will begin commercial production in August 1997. In August 1997, the
Company also began operations to recomplete seven existing well bores in the
Wasatch formation at depths of approximately 7,500 feet.
Natural Buttes Extension Development Area. The Natural Buttes Extension
development area is located in the eastern part of the Greater Monument Butte
Region and lies at the northern edge of the Greater Natural Buttes natural gas
field. The project lies within the Green River enhanced oil recovery project
area identified in the DOE study and is bordered on three sides by existing
Green River oil fields. To date, no wells have been drilled in the Company's
approximately 13,253 gross and net acres in the Natural Buttes Extension
development area. As in the Antelope Creek and Duchesne fields, the Company's
primary development objective is enhanced oil recovery in Lower Green River
oil reservoirs.
Two Green River enhanced oil recovery waterflood projects have been
initiated recently by other operators approximately six miles to the west of
the Natural Buttes Extension development area. In addition, an enhanced oil
recovery gas injection project is located south of the Company's acreage in
the West Willow Creek field. The Wonsits Valley enhanced oil recovery
waterflood project is located approximately four miles to the east. The
Company believes that results from these waterflood projects support
exploratory wells on the Company's acreage in this development area.
In addition, the Natural Buttes Extension Development area is located
adjacent to the northwest extension of the Natural Buttes gas field and is
directly offset by two wells that have produced in excess of 1.0 Bcf of
natural gas each. The Company's independent reservoir engineers have assigned
1.8 Bcf of net proved undeveloped reserves to two Wasatch natural gas
development locations that the Company plans to drill in November 1997.
Current Uinta Basin Development Plan. The Company intends to develop its
Uinta Basin Properties through the drilling of development and exploratory
wells and associated injection wells. The final determination with respect to
the drilling, production and development of wells will be dependent upon a
number of factors, including (i) the results of development activities in the
areas, (ii) the availability of sufficient capital resources by the Company
for drilling, (iii) the approval of the development plan by tribal and other
governmental authorities and (iv) economic and industry conditions at the time
of drilling, including prevailing and anticipated prices for oil and natural
gas and the availability of drilling rigs and crews. The full development of
any area will be dependent upon the commercial success of the Company's
development program. In the event that the results of the initial development
activities in any area do not meet the Company's expectations, the Company
will modify the development of such area.
The Company's acreage in each of these three development areas is held
pursuant to various development agreements with the Ute Indian Tribe, the Ute
Distribution Corporation and fee mineral owners. Under these development
agreements, the Company is responsible for making the key development and
operating decisions for each field. All of the Company's acreage in the
Antelope Creek field and approximately 54% of the Company's acreage in the
Duchesne field is held by production. The Company's acreage in the Natural
Buttes Extension development area and acreage recently leased is subject to
rentals until the Company is able to develop those areas.
Sources of Water for the Company's Enhanced Oil Recovery Programs. The
Company's enhanced oil recovery program in the Uinta Basin 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
41
<PAGE>
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 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 injection 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 in the area and other water customers having a higher
use priority than the Company. In addition, the Company has not yet secured a
water source for the full development of its Natural Buttes Extension
properties. There can be no assurance that water shortages will not occur or
that the Company will be able to renew or enter into new water supply
agreements on commercially reasonable terms or at all. To the extent the
Company is required to pay additional amounts for its supply of water, the
Company's financial condition and results of operations may be adversely
affected. While the Company believes that there will be sufficient volumes of
water available to support its improved oil recovery program and has taken
certain actions to ensure an adequate water supply will be available, in the
event the Company is unable to obtain sufficient quantities of water, the
Company's enhanced oil recovery program and business would be materially
adversely affected.
RATON BASIN. The Raton Basin, which is located in southeastern Colorado and
northeastern New Mexico, is approximately 80 miles long and 50 miles wide. The
Gas Research Institute has estimated that as of 1993 the Raton Basin held 18.0
Tcf of recoverable natural gas reserves from coalbed methane. As of December
31, 1996, cumulative production of approximately 7.9 Bcf of natural gas had
been recovered from approximately 140 coalbed methane wells in the Raton
Basin.
The Company recently acquired properties located in the northern portion of
the Raton Basin in Huerfano County, Colorado. The primary producing reservoir
in the Raton Basin is the Vermejo, which consists of several individual coal
seams at depths ranging from 500 to 5,000 feet. Over 45 million years ago,
plant material accumulated in thick layers in coastal swamps in the Raton
Basin and was subsequently buried and subjected to heat and pressure which
formed the coals. Since these coals were buried, continued mountain building
forces compressed the Raton Basin, creating an extensive series of fractures
in the coal and surrounding rocks. Later, portions of the area was intruded by
hot liquid rock or "magma" from lower in the earth's crust, which cooled to
form two large structures in the center of the Raton Basin known as the
Spanish Peaks. The magma moved up through existing fractures and created
additional fractures that radiate outward from the Spanish Peaks. As the magma
cooled, its heat altered the surrounding rocks, including the Vermejo and
Raton coals beds. The Company believes that the compression of mountain
building and the intrusion of magma into the Raton Basin have enhanced the
ability of the Vermejo and Raton coals to yield coalbed methane.
Development History. Exploratory drilling in the Raton Basin commenced in
1982. The first significant hydrocarbon discovery was coalbed methane natural
gas in 1987; however, early efforts to produce the natural gas were
commercially unsuccessful. During the last ten years, new technology has led
to the development of substantial new reserves of coalbed methane natural gas
in the United States. Application of this technology in the Raton Basin has
resulted in the discovery of additional reserves by other operators in the
area. In addition, the limited natural gas pipeline infrastructure in the
Raton Basin delayed the development of coalbed methane reserves. In December
1994, Colorado Interstate Gas Company completed construction of a 10-inch
pipeline from Weston, Colorado to Trinidad, Colorado, providing an outlet for
Raton Basin natural gas. The Company believes that construction of the
pipeline has allowed operators to increase drilling activity in the Raton
Basin.
Coalbed Methane Production. Coalbed methane production is similar to
traditional natural gas production in terms of the physical producing
facilities and the product produced. However, the subsurface mechanisms that
allow the gas to move to the wellbore and the producing characteristics of
coalbed methane wells are different from traditional natural gas production.
Coal beds produce nearly pure methane gas while traditional gas wells
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normally produce gas that contains small portions of ethane, propane and other
heavier hydrocarbon gases. Methane normally constitutes more than 90% of the
total gases in the production from traditional natural gas wells. The Raton
Basin natural gas does not contain significant amounts of contaminants, such
as hydrogen sulfide, carbon dioxide or nitrogen, that are sometimes present in
traditional natural gas production. Therefore, the properties of the Raton
Basin natural gas, such as heat content per unit volume (Btu), are very close
to the average properties of pipeline natural gas from traditional natural gas
wells.
Coal is a black organic mineral formed from buried deposits of plant
material from ancient coastal swamps. Methane is a common component of coal,
though coals vary in their methane content per ton. Rather than being limited
to open spaces in the coal structure, methane is adsorbed onto the inner coal
surfaces. When the coal is fractured and exposed to lower pressures, the
natural gas leaves the coal. Whether a coal bed will produce commercial
quantities of natural gas depends on its original content of natural gas per
ton of coal, the thickness of the coal bed, the reservoir pressure and the
existence of fractures through which the released natural gas can flow to the
wellhead. Frequently, coal beds are partly or completely saturated with water.
As the water is produced, space is created for natural gas to leave the coal
and flow to the well. Contrary to traditional natural gas wells, new coalbed
methane wells often produce water for several months and then, as the water
production decreases because the coal seams are being drained, and the
pressure decreases, methane gas production increases.
Water Production and Disposal. The Company believes that the water produced
from the Raton Basin coal seams will be low in dissolved solids, allowing the
Company, operating under permits which the Company believes will be issued by
the State of Colorado, to discharge the water into streambeds or stockponds.
However, if nonpotable water is discovered, it may be necessary to install and
operate evaporators or to drill disposal wells to reinject the produced water
back into the underground rock formations adjacent to the coal seams or to
lower sandstone horizons.
Coalbed Methane Technology. Coalbed methane wells are drilled and completed
in a manner similar to traditional natural gas wells, but exploration is
easier because coalbeds are relatively continuous underground and because it
is not essential to find folded or faulted structures that create natural
traps. The coalbed methane is trapped in the molecular structure of the coal
itself until released by pressure reduction in the reservoir brought about by
water removal. The Company intends to complete its wells in the Vermejo and
Raton coal beds.
The ability of natural gas to move through the coal or rocks to the wellbore
from its place of origination in the formation is the key determinant of the
rate at which a well will produce. Coal often provides very little ability for
the natural gas to move through it to the wellbore. Permeability is the
measure of the ability of fluids to move through the rock (coal) under the
influence of a differential pressure. The Raton Basin coals exhibit very good
to excellent permeability. However, in order to establish commercial gas
production rates, the Company must create a permanent conduit between the
individual coal seams and the wellbore. This is accomplished by creating and
propping open artificial fractures within the coal seams so the pathway for
gas migration to the wellbore is enhanced. Similar techniques of fracturing
are used on traditional natural gas and oil wells and have been proven to be
successful on other acreage in the Raton Basin.
The Company also intends to use specialized drilling techniques in the Raton
Basin. Traditional gas wells are drilled with the use of rotary drill bits
cooled and lubricated by drilling fluids. Exposing the Raton Basin coals to
drilling mud may significantly lower the permeability of the coals by plugging
the pores and natural fractures in the coals. The Company, therefore, intends
to use percussion air drilling without traditional drilling muds in drilling
its wells.
Raton Basin Development Plan. The Company recently acquired oil and natural
gas leases covering approximately 56,000 gross and net acres in the Raton
Basin. The Company intends to include much of its acreage in this area in a
federal exploratory unit of land that is governed by federal rules because
federal leases are included in the unit. Under an exploratory unit agreement,
production from any well in the unit will extend all of the leases in the unit
beyond their primary term. In addition, production and expenses are shared
among the individual lessors and lessees in the unit.
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Initially, the Company plans to spend up to approximately $5.0 million to
conduct a pilot project to study the feasibility of a full-scale coalbed
methane project. Should the pilot project be successful, the Company could
drill up to 200 wells on 160-acre spacing over the life of the project.
WILCOX TREND. The Wilcox Trend, which is located in Victoria and DeWitt
Counties in the Gulf Coast region of South Texas, is a high potential, multi-
pay province that lends itself to 3-D seismic exploration due to its
substantial structural and stratigraphic complexity. As of May 31, 1997,
cumulative production of approximately 12 MBbls of oil and 53 Bcf of natural
gas had been recovered from approximately 25 wells in the Company's properties
in the Helen Gohlke field.
On September 1, 1994, the Company purchased a 100% working interest in 5,079
gross and net acres in the Helen Gohlke field located within the Wilcox Trend.
The Company currently operates 13 producing oil and natural gas wells and two
disposal wells in this field. The Company is currently conducting a 3-D
seismic survey of the field and, subject to the results of the survey,
anticipates drilling one to three wells in the fourth quarter of 1997 or first
quarter of 1998. Average daily production from the Helen Gohlke field in
December 1996 was 70 Bbls of oil and 205 Mcf of natural gas.
MARKETING ARRANGEMENTS
The price received by the Company for its oil and natural gas production
depends on numerous factors beyond the Company's control, including
seasonality, the condition of the United States economy, particularly the
manufacturing sector, foreign imports, political conditions in other oil-
producing and natural gas-producing countries, the actions of OPEC and
domestic government regulation, legislation and policies. Decreases in the
prices of oil and natural gas could have an adverse effect on the carrying
value of the Company's proved reserves and the Company's revenues,
profitability and cash flow.
In June 1994, the Company entered into a contract to sell its oil production
from certain leases of its Utah properties to an industry participant. The
price under this contract is agreed upon monthly and is generally based on
such purchaser's posted prices. This contract will continue in effect until
terminated by either party. During the three years ended December 31, 1996,
the volumes sold under this contract totaled approximately 66 MBbls, 101 MBbls
and 61 MBbls, respectively, at an average sales price per Bbl for each year of
$16.51, $17.09 and $19.33.
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 a
refinery. This contract is effective until May 31, 1998 and calls for the
Company to receive a per Bbl price equal to the current month NYMEX closing
price for sweet crude, averaged over the month in which the crude is sold,
less an agreed upon adjustment.
In July 1997, the Company entered into a modification of its crude oil sales
contract to sell its black wax production from the Antelope Creek field to a
major oil company at a price equal to posting, less an agreed upon adjustment
to cover handling and gathering costs. This contract will continue in effect
until terminated by either party. In addition to the sales contract discussed
above, the purchaser has the option under an Oil Production Call Agreement to
purchase all or any portion of the oil produced from the Antelope Creek field
at the current market price. The option, which has no expiration date, allows
the purchaser to purchase the Company's oil production at a price that
approximates the market price for oil produced by the Company.
HEDGING ACTIVITIES
The Company historically has used various financial instruments such as
collars, swaps and futures contracts in an attempt to manage its price risk
with regard to a portion of the Company's crude and natural gas production.
Monthly settlements on these financial instruments are typically based on
differences between the fixed prices specified in the instruments and the
settlement price of certain future contracts quoted on the NYMEX or certain
44
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other indices. The instruments which have been historically used by the
Company have not had a contractual obligation which requires or allows the
future physical delivery of the hedged products. 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.
Approximately 378 MBbls of oil of the Company's expected oil production
through December 31, 1999 is subject to collars with a floor price of $17.00
and a ceiling price of $20.75.
The Company monitors oil markets and the Company's actual performance
compared to the estimates used in entering into hedging arrangements. If
material variations occur from those anticipated when a hedging arrangement is
made, the Company takes actions intended to minimize any risk through
appropriate market actions. The Company attempts to manage its exposure to
counterparty nonperformance risk through the selection of financially
responsible counterparties.
OIL AND NATURAL GAS RESERVES
The Company's estimated total proved reserves of oil and natural gas as of
December 31, 1994, 1995 and 1996 and June 30, 1997 were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------------- AS OF JUNE 30,
1994 1995 1996 1997
------------------ ------------------ ------------------ ------------------
OIL NATURAL OIL NATURAL OIL NATURAL OIL NATURAL
(MBBLS) GAS (MMCF) (MBBLS) GAS (MMCF) (MBBLS) GAS (MMCF) (MBBLS) GAS (MMCF)
------- ---------- ------- ---------- ------- ---------- ------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved developed:
Utah................... 247 1,156 870 1,219 568 1,600 1,685 3,696
Other.................. 958 6,151 691 5,440 297 1,410 164 1,155
----- ----- ----- ----- ----- ------ ----- ------
Total................. 1,205 7,307 1,561 6,659 865 3,010 1,849 4,851
Proved undeveloped:
Utah................... -- -- -- -- 5,262 15,802 5,875 16,059
Other.................. -- -- -- -- -- -- -- --
----- ----- ----- ----- ----- ------ ----- ------
Total................. -- -- -- -- 5,262 15,802 5,875 16,059
----- ----- ----- ----- ----- ------ ----- ------
Total proved.......... 1,205 7,307 1,561 6,659 6,127 18,812 7,724 20,910
===== ===== ===== ===== ===== ====== ===== ======
</TABLE>
45
<PAGE>
The following table sets forth the future net cash flows from the Company's
estimated proved reserves:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------ AS OF JUNE 30,
1994 1995 1996 1997
------- ------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Future net cash flow before income
taxes:
Utah................................ $ 5,776 $10,019 $117,101 $82,122
Other............................... 10,882 12,412 6,699 2,273
------- ------- -------- -------
Total............................. $16,658 $22,431 $123,800 $84,395
======= ======= ======== =======
Future net cash flow before income
taxes, discounted at 10%:
Utah................................ $ 4,126 $ 7,421 $ 59,447 $41,230
Other............................... 7,301 7,553 4,656 1,641
------- ------- -------- -------
Total............................. $11,427 $14,974 $ 64,103 $42,871
======= ======= ======== =======
</TABLE>
The reserve estimates reflected above for 1994, 1995 and 1996 were prepared
by the Company. The reserve estimates for June 30, 1997 were prepared by
Keeling, the Company's petroleum engineers, and are part of a report on the
Company's oil and natural gas properties, a summary of which is set forth
herein as Appendix A.
In accordance with applicable requirements of the Commission, estimates of
the Company's proved reserves and future net revenues are made using sales
prices estimated to be in effect as of the date of such reserve estimates and
are held constant throughout the life of the properties (except to the extent
a contract specifically provides for escalation). Estimated quantities of
proved reserves and future net revenues therefrom are affected by oil and
natural gas prices, which have fluctuated widely in recent years. There are
numerous uncertainties inherent in estimating oil and natural gas reserves and
their estimated values, including many factors beyond the control of the
producer. The reserve data set forth in this Prospectus represents only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. In addition, the Company's use of enhanced oil recovery techniques
requires greater development expenditures than traditional drilling
strategies. The Company expects to drill a number of wells utilizing
waterflood technology in the future. The Company's waterflood program involves
greater risk of mechanical problems than conventional development programs. As
a result, estimates of different engineers, including those used by the
Company, may vary. In addition, estimates of reserves are subject to revision
based upon actual production, results of future development and exploration
activities, prevailing natural gas and oil prices, operating costs and other
factors, which revisions may be material. Accordingly, reserve estimates are
often different from the quantities of natural gas and oil that are ultimately
recovered and are highly dependent upon the accuracy of the assumptions upon
which they are based. The Company's estimated proved reserves have not been
filed with or included in reports to any federal agency. See "Risk Factors--
Uncertainty of Reserve Information and Future Net Revenue Estimates."
46
<PAGE>
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated. At June 30, 1997, the Company
was in the process of completing 7 gross (3.5 net) wells as producers.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------- SIX MONTHS ENDED
1994 1995 1996 JUNE 30, 1997
--------- --------- --------- -----------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- -----------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil........................... 1 .5 -- -- -- -- 2 2
Natural gas................... -- -- -- -- -- -- -- --
Nonproductive................. 1 .5 3 2.5 -- -- -- --
--- --- --- --- --- --- ------- --------
Total....................... 2 1 3 2.5 -- -- 2 2
=== === === === === === ======= ========
Development:
Oil........................... 7 3.5 9 4.5 38 19 31 15.5
Natural gas................... 3 2 2 1 -- -- -- --
Nonproductive................. 1 .5 -- -- -- -- -- --
--- --- --- --- --- --- ------- --------
Total....................... 11 6 11 5.5 38 19 31 15.5
=== === === === === === ======= ========
Total:
Productive.................... 11 6 11 5.5 38 19 33 17.5
Nonproductive................. 2 1 3 2.5 -- -- -- --
--- --- --- --- --- --- ------- --------
Total....................... 13 7 14 8 38 19 33 17.5
=== === === === === === ======= ========
</TABLE>
As a result of the Company's drilling results to date, the Company believes
that the nature of the geology in the Lower Green River formation in the
Greater Monument Butte Region is characterized by the presence of hydrocarbons
throughout the region and, as a consequence, the distinction between
exploratory and development wells in this region is not as important as it is
in other oil and natural gas producing areas.
The Company does not own any drilling rigs; therefore, all of its drilling
activities are conducted by independent contractors under standard drilling
contracts.
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership interest as of June
30, 1997 in productive oil and natural gas wells in the development areas
indicated.
<TABLE>
<CAPTION>
OIL NATURAL GAS TOTAL
--------- ------------ ---------
AREA GROSS NET GROSS NET GROSS NET
- ---- ----- --- ------ ----- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Utah:
Antelope Creek Field......................... 94 47 -- -- 94 47
Duchesne Field............................... 6 6 -- -- 6 6
Natural Buttes Extension..................... -- -- -- -- -- --
--- --- ----- ----- --- ---
Total ...................................... 100 53 -- -- 100 53
Colorado....................................... -- -- -- -- -- --
Other.......................................... 11 10 8 6 19 16
--- --- ----- ----- --- ---
Total...................................... 111 63 8 6 119 69
=== === ===== ===== === ===
</TABLE>
In addition, as of June 30, 1997, the Company had 10 gross (5 net) active
water injection wells on its acreage in the Uinta Basin.
47
<PAGE>
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth the production volumes, average sales prices
and average production costs associated with the Company's sale of oil and
natural gas for the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------ ----------------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1) HISTORICAL
----------------------- ------------ ---------- ------------ ----------
1994 1995 1996 1996 1996 1996 1997
------- ------- ------- ------------ ---------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Net production:
Oil (Bbls)............. 110,373 182,704 262,910 213,535 141,775 94,542 117,770
Natural gas (Mcf)...... 485,062 659,202 553,770 461,292 358,420 271,431 243,095
Oil equivalent (BOE)... 191,217 292,571 355,205 290,417 201,512 139,781 158,286
Average sales price(2):
Oil (per Bbl):
Utah................... $ 16.23 $ 17.01 $ 15.82 $ 15.25 $ 17.46 $ 15.53 $ 13.87
Other.................. 14.42 18.66 20.35 20.35 19.32 19.32 20.05
Weighted average(3).... 14.89 17.61 16.96 16.83 17.94 17.01 14.65
Natural gas (per Mcf):
Utah................... $ 1.73 $ 1.40 $ 1.64 $ 1.41 $ 1.37 $ 1.34 $ 1.99
Other.................. 1.60 1.69 1.96 1.96 1.90 1.90 2.72
Weighted average....... 1.64 1.54 1.80 1.75 1.65 1.74 2.11
Average lease operating
expenses including
production and property
taxes (per BOE):
Utah................... $ 9.95 $ 6.06 $ 5.21 $ 4.53 $ 6.08 $ 4.92 $ 4.13
Other.................. 8.40 11.68 11.99 11.99 9.36 9.36 17.45(4)
Weighted average....... 8.84 8.37 7.37 7.43 7.19 7.09 5.93
</TABLE>
- --------
(1) Reflects results of operations as if the June 1, 1996 disposition of the
50% interest in the Antelope Creek properties had occurred on January 1,
1996.
(2) Before deduction of property taxes.
(3) Excluding the effects of losses from crude oil hedging transactions and
amortization of deferred revenue, the weighted average sales price per Bbl
of oil was $20.22 for the year ended December 31, 1996, $18.22 for the
historical six months ended June 30, 1996, $17.43 for the pro forma six
months ended June 30, 1996 and $15.96 for the historical six months ended
June 30, 1997.
(4) Excluding the effects of a workover and bottomhole repair to a well that
totaled $131,000, the average lease operating expense for the other
properties for the six months ended June 30, 1997 was $11.37 per BOE.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth the costs incurred by the Company in its
development, exploration and acquisition activities during the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------- SIX MONTHS ENDED
1994 1995 1996 JUNE 30, 1997
---------- ---------- ---------- ----------------
<S> <C> <C> <C> <C>
Acquisition costs:
Unproved properties......... $ 52,685 $ 8,206 $ 490,487 $ 416,601
Proved properties........... 5,193,043 4,718,201 -- --
Development costs............. 1,311,272 3,448,972 6,983,715 4,057,976
Exploration costs............. 69,570 316,089 -- --
Improved recovery costs....... 271,276 154,023 327,027 99,531
---------- ---------- ---------- ----------
Total..................... $6,897,846 $8,645,491 $7,801,229 $4,574,108
========== ========== ========== ==========
</TABLE>
48
<PAGE>
ACREAGE
The following table sets forth, as of June 30, 1997, the gross and net acres
of developed and undeveloped oil and natural gas leases which the Company
holds or has the right to acquire.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------ ------------- --------------
AREA GROSS NET GROSS NET GROSS NET
- ---- ------ ----- ------ ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
Utah:
Antelope Creek Field................ 5,600 2,880 15,312 9,788 20,912 12,668
Duchesne Field...................... 1,240 1,240 10,120 10,120 11,360 11,360
Natural Buttes Extension............ -- -- 13,253 13,253 13,253 13,253
------ ----- ------ ------ ------- ------
Total.............................. 6,840 4,120 38,685 33,161 45,525 37,281
Colorado.............................. -- -- 55,927 55,927 55,927 55,927
Other................................. 6,279 5,663 -- -- 6,279 5,663
------ ----- ------ ------ ------- ------
Total............................. 13,119 9,783 94,612 89,088 107,731 98,871
====== ===== ====== ====== ======= ======
</TABLE>
ACQUISITIONS
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.
COMPETITION
The Company operates in the highly competitive areas of oil and natural gas
exploration, exploitation, acquisition and production with other companies,
many of which have substantially larger financial resources, operations,
staffs and facilities. In seeking to acquire desirable producing properties or
new leases for future exploration and in marketing its oil and natural gas
production, the Company faces intense competition from both major and
independent oil and natural gas companies. In addition to the development of
its existing proved reserves, the Company expects that its inventory of
unproved drilling locations will be the primary source of new reserves,
production and cash flow over the next few years. The Company's properties in
the Uinta Basin constitute the majority of the Company's existing inventory.
Approximately 82% of the Company's fiscal year 1997 capital expenditure budget
is expected to be associated with drilling and acreage acquisition activity in
the Uinta Basin. There can be no assurance that the Uinta Basin will yield
substantial economic returns. Failure of the Uinta Basin to yield significant
quantities of economically attractive reserves in production 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. In addition, recent heavy drilling
activity by a number of operators in the Uinta Basin may reduce or limit the
availability of equipment and supplies or reduce demand for the Company's
production, either of which would impact the Company more adversely than if
the Company were geographically diversified.
The Company's competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs. Many of its
49
<PAGE>
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than the Company's and which,
in many instances, have been engaged in the energy business for a much longer
time than the Company. Such companies may be able to pay more for productive
oil and natural gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects
than the Company's financial or human resources permit. The Company's ability
to acquire additional properties and to discover reserves in the future will
be dependent upon its ability to evaluate and select suitable properties and
to consummate transactions in a highly competitive environment.
OPERATING HAZARDS AND UNINSURED RISKS
Oil and natural gas drilling activities are subject to many risks, including
the risk that no commercially productive reservoirs will be encountered. There
can be no assurance that new wells drilled by the Company will be productive
or that the Company will recover all or any portion of its investment.
Drilling for oil and natural gas may involve unprofitable efforts, not only
from dry holes, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs. The cost of drilling, completing and operating wells is often
uncertain. In addition, the Company's use of enhanced oil recovery techniques
for its Uinta Basin properties requires greater development expenditures than
alternative primary production strategies. In order to accomplish enhanced oil
recovery, the Company expects to drill a number of wells utilizing waterflood
technology in the future. The Company's waterflood program involves greater
risk of mechanical problems than conventional development programs. The
Company's drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, many of which are beyond the Company's control,
including economic conditions, title problems, water shortages, weather
conditions, compliance with governmental and tribal requirements and shortages
or delays in the delivery of equipment and services. The Company's future
drilling activities may not be successful and, if unsuccessful, such failure
may have a material adverse effect on the Company's future results of
operations and financial condition.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures and spills, any of which can
result in the loss of hydrocarbons, environmental pollution, personal injury
claims and other damage to properties of the Company and others. As protection
against operating hazards, the Company maintains insurance coverage against
some, but not all, potential losses. The Company may elect to self-insure in
circumstances in which management believes that the cost of insurance,
although available, is excessive relative to the risks presented. The
occurrence of an event that is not covered, or not fully covered, by third-
party insurance could have a material adverse effect on the Company's
business, financial condition and results of operations.
REGULATION
Regulation of Oil and Natural Gas Production. The Company's oil and natural
gas exploration, production and related operations are subject to extensive
rules and regulations promulgated by federal, state and local authorities and
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and natural gas
industry increases the Company's cost of doing business and affects its
profitability. Although the Company believes it is in substantial compliance
with all applicable laws and regulations, because such rules and regulations
are frequently amended or reinterpreted, the Company is unable to predict the
future cost or impact of complying with such laws.
The State of Utah and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural
gas. Such states also have statutes or regulations addressing conservation
matters, including provisions for the unitization or pooling of oil and
natural gas properties, the establishment of maximum rates of production from
wells, and the regulation of spacing, plugging and abandonment of such wells.
50
<PAGE>
Federal Regulation of Natural Gas. The Federal Energy Regulatory Commission
("FERC") regulates interstate natural gas transportation rates and service
conditions, which affect the marketing of natural gas produced by the Company,
as well as the revenues received by the Company for sales of such production.
Since the mid-1980's, FERC has issued a series of orders, culminating in Order
Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the
marketing and transportation of natural gas. Order 636 mandates a fundamental
restructuring of interstate pipeline sales and transportation service,
including the unbundling by interstate pipelines of the sale, transportation,
storage and other components of the city-gate sales services such pipelines
previously performed. One of FERC's purposes in issuing the order was to
increase competition within all phases of the natural gas industry. In July
1996, the United States Court of Appeals for the District of Columbia Circuit
largely upheld Order 636. A number of parties have appealed this ruling to the
Supreme Court and proceedings on remanded issues are currently ongoing at
FERC. In addition, numerous parties have filed for review of Order 636, as
well as orders in individual pipeline restructuring proceedings. Because these
orders may be modified as a result of the appeals, it is difficult to predict
the ultimate impact of the orders on the Company and its natural gas marketing
efforts. Generally, Order 636 has eliminated or substantially reduced the
interstate pipelines' traditional role as wholesalers of natural gas in favor
of providing only storage and transportation service, and has substantially
increased competition and volatility in natural gas markets.
The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to markets. Effective January
1, 1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such
rates to inflation, subject to certain conditions and limitations. The Company
is not able to predict with certainty the effect, if any, of these regulations
on its operations. However, the regulations may increase transportation costs
or reduce well head prices for oil and natural gas liquids.
Bureau of Indian Affairs. A substantial part of the Company's producing
properties in the Uinta Basin are operated under oil and natural gas leases
issued by the Ute Indian Tribe, which is under the supervision of the Bureau
of Indian Affairs. These activities must comply with rules and orders that
regulate aspects of the oil and natural gas industry, including drilling and
operating on leased land and the calculation and payment of royalties to the
federal government or the Ute Indian Tribe. Operations on Ute Indian tribal
lands must also comply with significant restrictive requirements of the
governing body of the Ute Indians. For example, such leases typically require
the operator to obtain an environmental impact statement based on planned
drilling activity. To the extent an operator wishes to drill additional wells,
it will be required to obtain a new assessment. In addition, leases with the
Ute Indian Tribe require that the operator agree to protect certain
archeological and ancestral ruins located on the acreage and to actively
recruit members of the Ute Indian Tribe to work on the drilling operations.
Environmental Matters. The Company's operations and properties are subject
to extensive and changing federal, state and local laws and regulations
relating to environmental protection, including the generation, storage,
handling, emission, transportation and discharge of materials into the
environment, and relating to safety and health. The recent trend in
environmental legislation and regulation generally is toward stricter
standards, and this trend will likely continue. These laws and regulations may
(i) require the acquisition of a permit or other authorization before
construction or drilling commences and for certain other activities; (ii)
limit or prohibit construction, drilling and other activities on certain lands
lying within wilderness and other protected areas; and (iii) impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various of the Company's operations are subject to
revocation, modification and renewal by issuing authorities. Governmental
authorities have the power to enforce their regulations, and violations are
subject to fines or injunctions, or both. In the opinion of management, the
Company is in substantial compliance with current applicable environmental
laws and regulations, and the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. Nevertheless,
changes in existing environmental laws and regulations or in interpretations
thereof could have a significant impact on the Company, as well as the oil and
natural gas industry in general.
The Comprehensive Environmental, Response, Compensation, and Liability Act
("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons
51
<PAGE>
who disposed of or arranged for the disposal of "hazardous substances" found
at such sites. It is not uncommon for the neighboring land owners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment. The Federal
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes
govern the disposal of "solid waste" and "hazardous waste" and authorize the
imposition of substantial fines and penalties for noncompliance. Although
CERCLA currently excludes petroleum from its definition of "hazardous
substance," state laws affecting the Company's operations impose clean-up
liability relating to petroleum and petroleum related products. In addition,
although RCRA classifies certain oil field wastes as "non-hazardous," such
exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal
requirements.
The Company has acquired leasehold interests in numerous properties that for
many years have produced oil and natural gas. Although the previous owners of
these interests may have used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have
been disposed of or released on or under the properties. In addition, some of
the Company's properties may be operated in the future by third parties over
whom the Company has no control. Notwithstanding the Company's lack of control
over properties operated by others, the failure of the operator to comply with
applicable environmental regulations may, in certain circumstances, adversely
impact the Company.
NEPA. The National Environmental Policy Act ("NEPA") is applicable to many
of the Company's activities and operations. NEPA is a broad procedural statute
intended to ensure that federal agencies consider the environmental impact of
their actions by requiring such agencies to prepare environmental impact
statements ("EIS") in connection with all federal activities that
significantly affect the environment. Although NEPA is a procedural statute
only applicable to the federal government, a large portion of the Company's
Uinta Basin acreage is located either on federal land or Ute tribal land
jointly administered with the federal government. The Bureau of Land
Management's issuance of drilling permits and the Secretary of the Interior's
approval of plans of operation and lease agreements all constitute federal
action within the scope of NEPA. Consequently, unless the responsible agency
determines that the Company's drilling activities will not materially impact
the environment, the responsible agency will be required to prepare an EIS in
conjunction with the issuance of any permit or approval.
ESA. The Endangered Species Act ("ESA") seeks to ensure that activities do
not jeopardize endangered or threatened animal, fish and plant species, nor
destroy or modify the critical habitat of such species. Under ESA, exploration
and production operations, as well as actions by federal agencies, may not
significantly impair or jeopardize the species or its habitat. ESA provides
for criminal penalties for willful violations of the Act. Other statutes that
provide protection to animal and plant species and that may apply to the
Company's operations include, but are not necessarily limited to, the Fish and
Wildlife Coordination Act, the Fishery Conservation and Management Act, the
Migratory Bird Treaty Act and the National Historic Preservation Act. Although
the Company believes that its operations are in substantial compliance with
such statutes, any change in these statutes or any reclassification of a
species as endangered could subject the Company to significant expense to
modify its operations or could force the Company to discontinue certain
operations altogether.
ABANDONMENT COSTS
The Company is responsible for payment of its working interest share of
plugging and abandonment costs on its oil and natural gas properties. Based on
its experience, the Company anticipates that the ultimate aggregate salvage
value of lease and well equipment located on its properties will exceed the
costs of abandoning such properties. There can be no assurance, however, that
the Company will be successful in avoiding additional expenses in connection
with the abandonment of any of its properties. In addition, abandonment costs
and their timing may change due to many factors including actual production
results, inflation rates and changes in environmental laws and regulations.
52
<PAGE>
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary
royalty interests, liens incident to operating agreements, liens for current
taxes and other burdens which the Company believes do not materially interfere
with the use of or affect the value of such properties. The Company's Credit
Agreement is secured by substantially all the Company's oil and natural gas
properties. Presently, the Company keeps in force its leaseholds for 18% of
its net acreage by virtue of production on that acreage in paying quantities.
The remaining acreage is held by lease rentals and similar provisions and
requires production in paying quantities prior to expiration of various time
periods to avoid lease termination.
OTHER FACILITIES
The Company currently leases approximately 3,300 square feet of office space
in Hutchinson, Kansas, where its principal offices are located. A significant
portion of the Company's principal offices are leased through Hutch Realty
LLC, an affiliate of the Company.
EMPLOYEES
As of September 30, 1997, the Company had 45 full-time employees, none of
whom is represented by any labor union. Included in the total were 18
corporate employees located in the Company's office in Hutchinson, Kansas. The
Company considers its relations with its employees to be good.
LEGAL PROCEEDINGS
The Company is not a party to any material pending legal proceedings.
53
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the directors
and executive officers of the Company as of September 30, 1997:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Robert C. Murdock........................ 40 President, Chief Executive Officer
and Chairman of the Board
Robert A. Christensen.................... 51 Executive Vice President, Chief
Technical Officer and Director
Sidney Kennard Smith..................... 53 Executive Vice President and Chief
Operating Officer
Tim A. Lucas............................. 33 Vice President, Chief Financial
Officer and Treasurer
David R. Albin........................... 38 Director
Kenneth A. Hersh......................... 34 Director
A. J. Schwartz........................... 45 Director
</TABLE>
Set forth below is a description of the backgrounds of the directors and
executive officers of the Company.
Robert C. Murdock has served as President, Chief Executive Officer and
Chairman of the Board of the Company since its inception in 1993. From 1985
until the formation of the Company, Mr. Murdock was President of GasTrak
Holdings, Inc., a natural gas gathering and marketing company. From 1982 to
1985, Mr. Murdock held various staff and management positions with Panhandle
Eastern Pipe Line Company, where he was responsible for the development and
implementation of special marketing programs, natural gas supply acquisitions,
natural gas supply planning and forecasting, and for developing computer
management systems for natural gas contract administration.
Robert A. Christensen has served as Executive Vice President and Director of
the Company since its inception in April 1993, and currently functions as
Chief Technical Officer with primary responsibility for property acquisition
evaluations, business development and strategic alliance formation. From April
1993 to 1996, Mr. Christensen served as President of Petroglyph Operating
Company, Inc., a wholly owned operating subsidiary of the Company. From
January 1992 to April 1993, Mr. Christensen was the President of Bishop
Resources, Inc., where he was responsible for managing the oil and natural gas
assets of the company. From April 1988 to April 1993, Mr. Christensen was
Manager of Project Development for Management Resources Group, Ltd. From
November 1985 to April 1988, Mr. Christensen was an independent consultant in
engineering operations and economic evaluations, primarily in Kansas. Prior to
November 1985, Mr. Christensen held various positions with independent oil and
natural gas exploration and production companies, as well as a major service
company. He is a member of the Society of Petroleum Engineers, the Society of
Professional Well Log Analysts and has completed the James M. Smith and
William T. Cobb course in waterflooding.
Sidney Kennard Smith has served as Executive Vice President and Chief
Operating Officer of the Company since January 1994, and was responsible for
accounting, financial planning and budgeting through December 1995. Currently
Mr. Smith serves as President of Petroglyph Operating Company. From June 1992
through 1993, Mr. Smith was a principal and treasurer of TKS Consulting, where
he performed economic and financial analysis, as well as served as an expert
witness in state and federal court and regulatory agency hearings. From
February 1986 to May 1992, Mr. Smith served as Vice President of Finance for
Gage Corporation, a natural gas development and processing company. From
August 1982 to July 1985, Mr. Smith was Treasurer and Controller for Sparkman
Energy Corporation. Mr. Smith is a Certified Public Accountant and is a member
of the American Institute of Certified Public Accountants and the Texas and
Oklahoma Societies of Certified Public Accountants.
54
<PAGE>
Tim A. Lucas has served as Vice President, Chief Financial Officer and
Treasurer of the Company since July 1997. Mr. Lucas previously served as
Senior Financial Manager for Cross Oil Refining & Marketing, Inc. from 1994 to
1997. From 1989 to 1994, Mr. Lucas worked in the energy group of the audit
division of Arthur Andersen, LLP. Mr. Lucas is a Certified Public Accountant
and a member of the American Institute of Certified Public Accountants and the
Oklahoma Society of Certified Public Accountants.
David R. Albin has served as a director of the Company since its inception.
Since 1988, Mr. Albin has been a manager of the NGP investment funds, which
were organized to make direct equity investments in the North American oil and
natural gas industry. From December 1984 until November 1988, Mr. Albin was
employed by Bass Investment Limited Partnership, where he was responsible for
portfolio management. Mr. Albin serves as a director of Offshore Energy
Development Corporation and Titan Exploration, Inc.
Kenneth A. Hersh has served as a director of the Company since its
inception. Since 1989, Mr. Hersh has been a manager of the NGP investment
funds, which were organized to make direct equity investments in the North
American oil and natural gas industry. From 1985 to 1987, Mr. Hersh was
employed by the investment banking division of Morgan Stanley & Co.
Incorporated, where he was a member of the Energy Group specializing in oil
and natural gas financing and merger and acquisition transactions. Mr. Hersh
serves as a director of Pioneer Natural Resources Company, HS Resources, Inc.
and Titan Exploration, Inc.
A. J. Schwartz has served as a director of the Company since April 1997.
Since 1980, Mr. Schwartz has been a shareholder in the law firm of Morris,
Laing, Evans, Brock & Kennedy, Chartered.
All directors are elected to serve until the next annual meeting of
stockholders and until their successors are elected and qualified. Executive
officers are generally elected annually by the Board of Directors to serve,
subject to the discretion of the Board of Directors, until their successors
are elected or appointed.
COMMITTEES OF THE BOARD
Upon completion of the Offering, the Company will establish standing audit
and compensation committees of the Board of Directors. Messrs. Albin and Hersh
are expected to be members of the Audit Committee and the Compensation
Committee. The Audit Committee will review the functions of the Company's
management and independent accountants pertaining to the Company's financial
statements and perform such other related duties and functions as are deemed
appropriate by the Audit Committee or the Board of Directors. The Compensation
Committee of the Board of Directors will recommend to the Board of Directors
the base salaries, bonuses and other incentive compensation for the Company's
officers. The Board of Directors is expected to designate the Compensation
Committee as the administrator of the Company's 1997 Incentive Plan. See
"Executive Compensation and Other Information--1997 Incentive Plan."
DIRECTOR COMPENSATION
Directors who are also employees of the Company are not separately
compensated for serving on the Board of Directors. Directors who are not
employees of the Company receive $5,000 per year for their services as
directors. In addition, the Company reimburses them for the expenses incurred
in connection with attending meetings of the Board of Directors and its
committees.
LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
In accordance with Section 102(b)(7) of the Delaware General Corporation Law
(the "DGCL"), the Company's Certificate of Incorporation includes a provision
eliminating the personal liability of members of its Board of Directors to the
corporation or its stockholders for monetary damages for breach of fiduciary
as a director. Such provision does not eliminate or limit the liability of a
director (1) for any breach of a director's duty of loyalty to the corporation
or its stockholders, (2) for acts or omissions not in good faith or which
involve intentional misconduct or a knowing violation of law, (3) for paying
an unlawful dividend or approving an illegal
55
<PAGE>
stock repurchase (as provided in Section 174 of the DGCL), or (4) for any
transaction from which the director derived an improper personal benefit.
The Company has entered into indemnity agreements with each of its executive
officers and directors that provide for indemnification in certain instances
against liability and expenses incurred in connection with proceedings brought
by or in the right of the Company or by third parties by reason of a person
serving as an officer or director of the Company.
The Company believes that these provisions and agreements will assist the
Company in attracting and retaining qualified individuals to serve as
directors and officers.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of the Board members expected to be named as members of the
Compensation Committee is or has been an employee of the Company. No executive
officer of the Company serves as a member of the board of directors or
compensation committee of any entity that has one or more executive officers
serving as a member of the Company's Board of Directors or Compensation
Committee. Messrs. Murdock, Christensen, Smith, Albin and Hersh, or their
affiliates, have acquired capital stock of the Company. See "Certain
Transactions" and "Principal Stockholders."
56
<PAGE>
EXECUTIVE COMPENSATION AND OTHER INFORMATION
SUMMARY COMPENSATION TABLE
The following table sets forth all compensation paid for the last fiscal
year to the Company's Chief Executive Officer. None of the Company's other
executive officer's annual salary and bonus exceeded $100,000 for the fiscal
year ended December 31, 1996. Upon completion of the Offering, the Company
intends to increase the annual salary of each of Robert C. Murdock, Robert A.
Christensen and Sidney Kennard Smith to $125,000.
<TABLE>
<CAPTION>
ANNUAL COMPENSATION
-------------------------------------
NAME AND OTHER ANNUAL ALL OTHER
PRINCIPAL POSITION SALARY($) BONUS($) COMPENSATION($)(1) COMPENSATION($)(2)
------------------ --------- -------- ------------------ ------------------
<S> <C> <C> <C> <C>
Robert C. Murdock....... 85,800 5,000 -- 475
President and Chief
Executive Officer
</TABLE>
- --------
(1) Other Annual Compensation does not include perquisites and other personal
benefits because the aggregate amount of such compensation does not exceed
the lesser of (i) $50,000 or (ii) 10% of individual combined salary and
bonus for the year.
(2) Consists of premiums paid by the Company under a life insurance program.
OPTION GRANTS AND EXERCISES
During the Company's most recent fiscal year, no options to purchase Common
Stock of the Company were granted to or exercised or held by Mr. Murdock. The
executive officers of the Company are eligible to participate in the Company's
1997 Incentive Plan, and it is expected that such officers will receive grants
in the future.
EMPLOYMENT AGREEMENTS
Each of Messrs. Murdock, Christensen and Smith and Tim A. Lucas is a party
to a confidentiality and noncompete agreement with the Company. Each such
agreement provides that if the Company terminates the employee's employment
other than for cause, the Company may elect, at its option, to make severance
payments to such employee in an amount equal to the employee's salary for a
period not less than six months or greater than 18 months. The Company may
discontinue such payments for any reason.
1997 INCENTIVE 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") as
of the completion of the Offering. The purpose of the 1997 Incentive Plan is
to attract and retain key employees, to encourage their sense of
proprietorship and to stimulate the active interest of such persons in the
development and financial success of the Company.
Participants in the 1997 Incentive Plan are selected by the Board of
Directors or such committee of the Board as is designated by the Board to
administer the 1997 Incentive Plan (upon completion of the Offering, the
Compensation Committee of the Board of Directors) from among those persons who
hold positions of responsibility and whose performance, in the judgment of the
Compensation Committee, can have a significant
effect on the success of the Company. An aggregate of 375,000 shares of Common
Stock have been authorized and reserved for issuance pursuant to the 1997
Incentive Plan. As of August 22, 1997, options have been granted to
participants under the 1997 Incentive Plan to purchase a total of 260,000
shares of Common Stock at an exercise price per share equal to the Price to
Public set forth on the cover page of this Prospectus. One-third of these
options vest on each of the first through third anniversaries of the date of
grant. Messrs. Murdock, Christensen, Smith and Lucas have been granted options
to purchase 80,000, 80,000, 80,000 and 20,000 shares, respectively.
Subject to the provisions of the 1997 Incentive Plan, the Compensation
Committee will be authorized to determine the type or types of awards made to
each participant and the terms, conditions and limitations applicable to each
award. In addition, the Compensation Committee will have the exclusive power
to interpret the 1997 Incentive Plan and to adopt such rules and regulations
as it may deem necessary or appropriate in keeping with the objectives of the
1997 Incentive Plan.
57
<PAGE>
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.
CERTAIN TRANSACTIONS
Each of Messrs. Murdock, Christensen and Smith personally guaranteed
indebtedness owed to Petroglyph Gas Partners, L.P. by its general partner by
an affiliate. The outstanding principal balance plus accrued interest of this
affiliate loan, as of June 30, 1997 was $340,988. In connection with the
Conversion, the Company will make loans to each of Messrs. Murdock,
Christensen and Smith. The proceeds of those loans will be contributed by
Messrs. Murdock, Christensen and Smith to the capital of their affiliate and
applied to retire the outstanding affiliate indebtedness and discharge their
personal guarantees. The loans to be made to Messrs. Murdock, Christensen and
Smith will be evidenced by promissory notes bearing interest at a rate of 9.0%
per annum, maturing June 30, 1999. Assuming that the Conversion is completed
on October 31, 1997, the principal balance of these promissory notes would be
$150,353, $150,353 and $53,066 for Messrs. Murdock, Christensen and Smith,
respectively.
The Company leases its office building from Hutch Realty LLC ("Hutch"), an
entity controlled by certain directors and executive officers of the Company.
Rentals paid to Hutch for such lease were $17,400 for the six months ended
June 30, 1996. Rentals paid during 1994, 1995 and 1996 totaled $24,000,
$39,200 and $34,800, respectively.
On August 22, 1997, the Company and NGP entered into a financial advisory
services agreement whereby NGP has agreed to provide financial advisory
services to the Company for a quarterly fee of $13,750. In addition, NGP will
be reimbursed for its out of pocket expenses incurred in performing such
services. The agreement is for a one year term and can be terminated by NGP at
the end of any fiscal quarter. Under the agreement, NGP will assist the
Company in managing its public and private financing activities, its public
financial reporting obligations, its budgeting and planning processes, and its
investor relations program, as well as provide ongoing strategic advice. NGP
will not receive any other transaction-related compensation for its advisory
assistance.
For the year ended December 31, 1996, the Company paid legal fees of
$109,000 to the law firm of Morris, Laing, Evans, Brock & Kennedy, Chartered,
where A. J. Schwartz, a director of the Company, is a shareholder. For the six
months ended June 30, 1997, the Company paid legal fees of $81,000 to Morris,
Laing, Evans, Brock & Kennedy, Chartered.
58
<PAGE>
PRINCIPAL STOCKHOLDERS
The following table sets forth the names and addresses of each of the
Company's stockholders who beneficially owns more than five percent of the
Company's Common Stock, the number of shares beneficially owned by such
stockholders and the percentage of the Common Stock so owned as of October 20,
1997, assuming in each case the Conversion had been consummated on October 20,
1997.
<TABLE>
<CAPTION>
PERCENTAGE OF
SHARES OWNED
-----------------
NUMBER OF PRIOR TO AFTER
NAME AND ADDRESS OF BENEFICIAL OWNER SHARES OWNED OFFERING OFFERING
- ------------------------------------ ------------ -------- --------
<S> <C> <C> <C>
Natural Gas Partners, L.P. ...................... 1,137,883 40.16% 21.34%
777 Main Street, Suite 2700
Fort Worth, Texas 76102
Natural Gas Partners II, L.P. ................... 648,920 22.90% 12.17%
777 Main Street, Suite 2700
Fort Worth, Texas 76102
Natural Gas Partners III, L.P. .................. 728,291 25.70% 13.66%
777 Main Street, Suite 2700
Fort Worth, Texas 76102
R. Gamble Baldwin(1)............................. 1,155,290 40.77% 21.66%
c/o Natural Gas Partners, L.P.
777 Main Street, Suite 2700
Fort Worth, Texas 76102
</TABLE>
- --------
(1) Includes (i) 17,407 shares held by Mr. Baldwin and (ii) 1,137,883 shares
held by Natural Gas Partners, L.P., over which Mr. Baldwin exercises
voting and investment power. R. Gamble Baldwin is the sole general partner
of G.F.W. Energy, L.P., which is the sole general partner of Natural Gas
Partners, L.P.
The following table sets forth information as of October 20, 1997 (assuming
the Conversion had been consummated on such date) with respect to the shares
of Common Stock beneficially owned by each of the Company's directors, the
Company's executive officers and all directors and executive officers as a
group and the percent of the outstanding Common Stock owned by each, assuming
that the Offering is consummated without the Underwriters' over-allotment
option being exercised.
<TABLE>
<CAPTION>
PERCENTAGE OF
SHARES OWNED
-----------------
NUMBER OF PRIOR TO AFTER
DIRECTOR AND EXECUTIVE OFFICERS SHARES OWNED OFFERING OFFERING
- ------------------------------- ------------ -------- --------
<S> <C> <C> <C>
David R. Albin(1)(2)............................ 1,429,431 50.45% 26.80%
Kenneth A. Hersh(1)(3).......................... 1,390,266 49.07% 26.07%
A. J. Schwartz.................................. -- -- --
Robert C. Murdock............................... 96,043 3.39% 1.80%
Robert A. Christensen........................... 96,043 3.39% 1.80%
Sidney Kennard Smith............................ 33,898 1.20% *
Tim A. Lucas.................................... -- -- --
All executive officers and directors as a group
(7 persons).................................... 1,668,470 58.89% 31.28%
</TABLE>
- --------
* Represents less than 1% of outstanding Common Stock.
(1) David R. Albin and Kenneth A. Hersh are each managing members of the
general partner of Natural Gas Partners II, L.P. and Natural Gas Partners
III, L.P. As such, Mr. Albin and Mr. Hersh may be deemed to share voting
and investment power with respect to the 1,377,211 shares beneficially
owned by Natural Gas Partners II, L.P. and Natural Gas Partners III, L.P.
and these shares are included in the total number of shares reported for
each. Each of Mr. Albin and Mr. Hersh disclaims beneficial ownership of
such shares.
(2) Includes 52,220 shares held in trust for Mr. Albin.
(3) Includes 13,055 shares owned by Mr. Hersh.
Each of the parties to the Exchange Agreement receiving shares of Common
Stock in the Conversion entered into that certain Stockholders Agreement dated
as of August 22, 1997 in order to provide certain controls over the continuity
of ownership of the original investors in the Company. Pursuant to such
Stockholders Agreement, each stockholder has agreed to refrain from effecting
certain transfers of its shares of Common Stock unless the other parties to
the Stockholders Agreement have been afforded an opportunity to join in such
transfer on the same terms.
59
<PAGE>
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 25,000,000 shares of
Common Stock, par value $.01 per share, and 5,000,000 shares of preferred
stock, par value $.01 per share ("Preferred Stock"). Of such authorized
shares, 5,333,333 shares of Common Stock will be issued and outstanding upon
completion of the Offering (5,708,333 shares if the Underwriters' over-
allotment option is exercised in full). As of September 30, 1997 the Company
had outstanding 2,833,333 shares of Common Stock held of record by 11
stockholders. In addition to the issued and outstanding Common Stock, options
and warrants to purchase up to an aggregate of 269,280 shares of Common Stock
are outstanding.
COMMON STOCK
The holders of Common Stock are entitled to one vote for each share held of
record on all matters submitted to the stockholders. See "Risk Factors--
Control by Existing Stockholders." The Bylaws permit the holders of a majority
of the Company's outstanding Common Stock to call a special meeting of the
Stockholders and, not more than once during each calendar year, holders of 10%
or more of the Company's outstanding Common Stock may call a special meeting
of stockholders. Each share of Common Stock is entitled to participate equally
in dividends, if, as and when declared by the Company's Board of Directors,
and in the distribution of assets in the event of liquidation, subject in all
cases to any prior rights of outstanding shares of Preferred Stock. The
Company has never paid cash dividends on its Common Stock. The shares of
Common Stock have no preemptive or conversion rights, redemption rights, or
sinking fund provisions. The outstanding shares of Common Stock are, and the
shares of Common Stock offered hereby upon issuance and sale will be, duly
authorized, validly issued, fully paid and nonassessable.
PREFERRED STOCK
The Company has no outstanding Preferred Stock. The Company is authorized to
issue 5,000,000 shares of Preferred Stock. The Company's Board of Directors
may establish, without stockholder approval, one or more classes or series of
Preferred Stock having the number of shares, designations, relative voting
rights, dividend rates, liquidation and other rights, preferences, and
limitations that the Board of Directors may designate. The Company believes
that this power to issue Preferred Stock will provide flexibility in
connection with possible corporate transactions. The issuance of Preferred
Stock, however, could adversely affect the voting power of holders of Common
Stock and restrict their rights to receive payments upon liquidation of the
Company. It could also have the effect of delaying, deferring or preventing a
change in control of the Company. The Company currently does not plan to issue
shares of Preferred Stock.
WARRANTS
In connection with the execution of the Credit Agreement, on September 15,
1997, the Company granted to Chase warrants (the "Warrants") to purchase up to
9,280 shares of Common Stock at a nominal exercise price.
CERTAIN PROVISIONS OF THE COMPANY'S CHARTER AND BYLAWS AND DELAWARE LAW
PROVISIONS
The Company's Certificate of Incorporation and Bylaws contain provisions
which may have the effect of delaying, deferring or preventing a change in
control of the Company. These provisions, among other things, provide for
noncumulative election of the Board of Directors, impose certain procedural
requirements on stockholders of the Company who wish to make nominations for
the election of directors or propose other actions at stockholders' meetings
and require an 80% supermajority vote of the Board of Directors in order to
approve amendments to the Company's Bylaws. Furthermore, the Company's Bylaws
provide that special meetings of the stockholders may only be called by a
majority of the votes entitled to be cast by the stockholders at the meeting
except for, no more than once per year, in a meeting called by the holders of
10% of the votes entitled to be cast at such meeting. In addition, the
Company's Certificate of Incorporation authorizes the Board to issue up to
5,000,000 shares of preferred stock without stockholder approval and to set
the rights, preferences and other designations, including voting rights, of
those shares as the Board of Directors may determine. These provisions, alone
or in combination with each other and with the matters described in "Risk
Factors--Control
60
<PAGE>
by Existing Stockholders," may discourage transactions involving actual or
potential changes of control of the Company, including transactions that
otherwise could involve payment of a premium over prevailing market prices to
holders of Common Stock.
The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law. Generally, Section 203 prohibits the Company
from engaging in a "business combination" (as defined in Section 203) with an
"interested stockholder" (defined generally as a person owning 15% or more of
the Company's outstanding voting stock) for three years following the date
that person becomes an interested stockholder, unless (a) before that person
became an interested stockholder, the Company's Board of Directors approved
the transaction in which the interested stockholder became an interested
stockholder or approved the business combination; (b) upon completion of the
transaction that resulted in the interested stockholder's becoming an
interested stockholder, the interested stockholder owns at least 85% of the
voting stock outstanding at the time the transaction commenced (excluding
stock held by directors who are also officers of the Company and by employee
stock plans that do not provide employees with the right to determine
confidentially whether shares held subject to the plan will be tendered in a
tender or exchange offer); or (c) following the transaction in which that
person became an interested stockholder, the business combination is approved
by the Company's Board of Directors and authorized at a meeting of
stockholders by the affirmative vote of the holders of at least two-thirds of
the outstanding voting stock not owned by the interested stockholder.
Under Section 203, these restrictions also do not apply to certain business
combinations proposed by an interested stockholder following the announcement
or notification of one of certain extraordinary transactions involving the
Company and a person who was not an interested stockholder during the previous
three years or who became an interested stockholder with the approval of a
majority of the Company's directors, if that extraordinary transaction is
approved or not opposed by a majority of the directors who were directors
before any person became an interested stockholder in the previous three years
or who were recommended for election or elected to succeed such directors by a
majority of such directors then in office.
REGISTRATION RIGHTS
The Company has entered into a Registration Rights Agreement (the
"Registration Rights Agreement") with Natural Gas Partners, L.P., Natural Gas
Partners II, L.P., Natural Gas Partners III, L.P., Robert C. Murdock, Robert
A. Christensen, Sidney Kennard Smith, the Albin Income Trust, R. Gamble
Baldwin, John S. Foster, Kenneth A. Hersh and Bruce B. Selkirk, III (the
"Shareholder Parties"). Pursuant to the Registration Rights Agreement, on up
to three separate occasions, commencing on the 180th day following the date of
the Company's initial registration statement under the securities laws,
Shareholder Parties owning at least 35% of the outstanding shares then subject
to such agreement may require the Company to register shares held by them
under applicable securities laws, provided that the shares to be registered
have an estimated aggregate offering price to the public of at least $5.0
million. The Registration Rights Agreement also provides that the Shareholder
Parties have piggyback registration rights pursuant to which such persons may
include shares of Common Stock held by them in certain registrations initiated
by the Company or by any other holder of the Company's Common Stock. The
piggyback rights are subject to customary cutback provisions. The Registration
Rights Agreement provides for customary indemnities by the Company in favor of
persons including shares in a registration pursuant to the Registration Rights
Agreement, and by such persons in favor of the Company, with respect to
information to be included in the relevant registration statement. These
registration rights have been waived in connection with this offering and for
180 days after the date of this Prospectus.
The Company and Chase have entered into a registration rights agreement
covering the Common Stock issuable upon exercise of the Warrants pursuant to
which the Company has granted Chase certain incidental, or "piggyback",
registration rights. In addition, beginning three years after the date of this
Prospectus, Chase has certain demand registration rights. The Company may, at
its option, repurchase the shares issuable to Chase upon conversion of the
Warrants in lieu of registering such shares.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Common Stock is American Stock
Transfer & Trust Company.
61
<PAGE>
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the Offering, the Company will have a total of 5,333,333
shares of Common Stock outstanding. Of these shares, the 2,500,000 shares of
Common Stock offered hereby (2,875,000 shares if the Underwriters' over-
allotment option is exercised in full) will be freely tradeable without
restriction or registration under the Securities Act by persons other than
"affiliates" of the Company, as defined under the Securities Act. The
remaining 2,833,333 shares of Common Stock outstanding will be "restricted"
securities as that term is defined by Rule 144 as promulgated under the
Securities Act.
In general, under Rule 144 as currently in effect, a person (or persons
whose sales are aggregated) who has beneficially owned restricted shares for
at least one year, including persons who may be deemed to be "affiliates" of
the Company would be entitled to sell, within any three-month period, a number
of shares that does not exceed the greater of one percent of the number of
shares of Common Stock then outstanding (approximately 53,000 shares upon
completion of the Offering) or the average weekly trading volume of the Common
Stock during the four calendar weeks preceding the filing of a Form 144 with
respect to such sale. Sales under Rule 144 are also subject to certain manner
of sale provisions and notice requirements, and to the availability of current
public information about the Company. In addition, a person who is not deemed
to have been an affiliate of the Company at any time during the 90 days
preceding a sale, and who has beneficially owned the shares proposed to be
sold for at least two years, would be entitled to sell such shares under Rule
144(k) without regard to the requirements described above.
Under Rule 144 (and subject to the conditions thereof, including the volume
limitations described above), the Company believes that the earliest date on
which any of its restricted securities currently outstanding will be eligible
for sale under Rule 144 is the first anniversary of the completion of the
Offering. All 2,833,333 of the restricted shares are subject to lockup
restrictions. Pursuant to these restrictions, the holders of these restricted
shares, including all the Company's executive officers and directors, have
agreed that they will not, directly or indirectly, offer, sell, offer to sell,
contract to sell, pledge, grant any option to purchase or otherwise sell or
dispose (or announce any offer, sale, offer of sale, contract to sell, pledge,
grant of any options to purchase or sale or disposition) of any shares of
Common Stock or other capital stock of the Company, or any securities
convertible into, or exercisable or exchangeable for, any shares of Common
Stock or other capital stock of the Company without the prior written consent
of Prudential Securities Incorporated, on behalf of the Underwriters, for a
period of 180 days from the date of this Prospectus. Prudential Securities
Incorporated may, in its sole discretion, at any time and without notice,
release all or any portion of the securities subject to such agreements. The
holders of approximately 2,833,333 shares of Common Stock and their permitted
transferees have demand registration rights to require the Company to register
such shares under the Securities Act beginning 180 days after the date of this
Prospectus. Registration and sale of such shares could have an adverse effect
on the market price of the Common Stock. See "Description of Capital Stock--
Registration Rights."
The Company intends to file a registration statement under the Securities
Act to register Common Stock to be issued pursuant to the exercise of options,
including options under the 1997 Incentive Plan.
Prior to the Offering, there has been no public market for the Common Stock
and no predictions can be made of the effect, if any, that the sale or
availability for sale of shares of additional Common Stock will have on the
market price of the Common Stock. Nevertheless, sales of substantial amounts
of such shares in the public market, or the perception that such sales could
occur, could materially and adversely affect the market price of the Common
Stock and could impair the Company's future ability to raise capital through
an offering of its equity securities.
62
<PAGE>
UNDERWRITING
The Underwriters named below (the "Underwriters"), for whom Prudential
Securities Incorporated, Oppenheimer & Co., Inc. and Johnson Rice & Company
L.L.C. are acting as Representatives (the "Representatives"), have severally
agreed, subject to the terms and conditions contained in the Underwriting
Agreement, to purchase from the Company the number of shares of Common Stock
set forth below opposite their respective names:
<TABLE>
<CAPTION>
NUMBER
UNDERWRITER OF SHARES
----------- ---------
<S> <C>
Prudential Securities Incorporated................................ 732,500
Oppenheimer & Co., Inc. .......................................... 732,500
Johnson Rice & Company L.L.C. .................................... 366,250
ABN AMRO Chicago Corporation...................................... 53,500
BT Alex Brown Incorporated........................................ 53,500
Donaldson, Lufkin & Jenrette Securities Corporation............... 53,500
Howard, Weil, Labouisse, Friedrichs Incorporated.................. 53,500
Jefferies & Company, Inc. ........................................ 53,500
Lehman Brothers Inc. ............................................. 53,500
PaineWebber Incorporated.......................................... 53,500
Smith Barney Inc. ................................................ 53,500
Ladenburg, Thalmann & Co. Inc. ................................... 26,750
McDonald & Company Securities, Inc. .............................. 26,750
Petrie Parkman & Co. ............................................. 26,750
Rauscher Pierce Refsnes, Inc. .................................... 26,750
Raymond James & Associates, Inc. ................................. 26,750
Stephens Inc. .................................................... 26,750
George K. Baum & Company.......................................... 13,375
Gaines, Berland Inc. ............................................. 13,375
Hanifen, Imhoff Inc. ............................................. 13,375
Hoak Breedlove Wesneski & Co. .................................... 13,375
Kirkpatrick, Pettis, Smith, Polian Inc. .......................... 13,375
Lowenbaum & Company Incorporated.................................. 13,375
---------
Total........................................................... 2,500,000
=========
</TABLE>
The Company is obligated to sell, and the Underwriters are obligated to
purchase, all of the shares of Common Stock offered hereby if any are
purchased.
The Underwriters, through the Representatives, have advised the Company that
they propose to offer the shares of Common Stock initially at the public
offering price set forth on the cover page of this Prospectus; that the
Underwriters may allow to selected dealers a concession of $0.50 per share;
and that such dealers may reallow a concession of $0.10 per share to certain
other dealers. After the initial public offering, the offering price and the
concessions may be changed by the Representatives.
The Company has granted to the Underwriters an option, exercisable for 30
days from the date of this Prospectus, to purchase up to 375,000 additional
shares of Common Stock at the initial public offering price less underwriting
discounts and commissions, as set forth on the cover page of this Prospectus.
The Underwriters may exercise such option solely for the purpose of covering
over-allotments incurred in the sale of the shares of Common Stock offered
hereby. To the extent such option to purchase is exercised, each Underwriter
will become obligated, subject to certain conditions, to purchase
approximately the same percentage of such additional shares as the number of
shares set forth opposite each Underwriters' name in the preceding table bears
to 2,500,000.
The Company, its executive officers and directors, and all of the Company's
stockholders have agreed that they will not, directly or indirectly, offer,
sell, offer to sell, contract to sell, pledge, grant any option to purchase,
63
<PAGE>
or otherwise sell or dispose of (or announce any offer, sale, offer of sale,
contract of sale, pledge, grant of any option to purchase or other sale or
disposition) of any shares of Common Stock or other capital stock of the
Company or any securities convertible into, or exercisable or exchangeable
for, any shares of Common Stock or other capital stock of the Company without
the prior written consent of Prudential Securities Incorporated, on behalf of
the Underwriters, for a period of 180 days after the date of this Prospectus,
except issuances pursuant to the exercise of employee stock options.
Prudential Securities Incorporated may, in its sole discretion, at any time
and without notice, release all or any portion of the securities subject to
such agreements.
The Company has agreed to indemnify the several Underwriters or to
contribute to losses arising out of certain liabilities, including liabilities
under the Securities Act.
The Representatives have informed the Company that the Underwriters do not
intend to confirm sales to any accounts over which they exercise discretionary
authority.
Prior to the Offering, there has been no public market for the Common Stock
of the Company. Consequently, the initial public offering price for the Common
Stock has been determined through negotiations between the Company and the
Representatives of the Underwriters. Among the factors considered in making
such determination were the prevailing market conditions, the results of
operations of the Company in recent periods relevant to its prospects and the
prospects for its industry in general, the management of the Company and the
market prices of securities for companies in businesses similar to that of the
Company.
In connection with this Offering, certain Underwriters and selling group
members and their respective affiliates may engage in transactions that
stabilize, maintain or otherwise affect the market price of the Common Stock.
Such transactions may include stabilization transactions effected in
accordance with Rule 104 of Regulation M, pursuant to which such persons may
bid for or purchase Common Stock for the purpose of stabilizing its market
price. The Underwriters also may create a short position for the account of
the Underwriters by selling more Common Stock in connection with the Offering
than they are committed to purchase from the Company, and in such case may
purchase Common Stock in the open market following completion of the Offering
to cover all or a portion of such short position. The Underwriters may also
cover all or a portion of such short position, up to 375,000 shares of Common
Stock, by exercising the Underwriters' over-allotment option referred to
above. In addition, Prudential Securities Incorporated, on behalf of the
Underwriters, may impose "penalty bids" under contractual arrangements with
the Underwriters whereby it may reclaim from an Underwriter (or dealer
participating in the Offering) for the account of the other Underwriters, the
selling concession with respect to Common Stock that is distributed in the
Offering but subsequently purchased for the account of the Underwriters in the
open market. Any of the transactions described in this paragraph may result in
the maintenance of the price of the Common Stock at a level above that which
might otherwise prevail in the open market. None of the transactions described
in this paragraph is required, and, if they are undertaken, they may be
discontinued at any time.
64
<PAGE>
LEGAL MATTERS
The validity of the Common Stock offered hereby will be passed upon for the
Company by Thompson & Knight, P.C., Dallas, Texas. Certain matters will be
passed upon for the Underwriters by Baker & Botts, L.L.P., Houston, Texas.
EXPERTS
The audited financial statements included in the registration statement, to
the extent and for the periods indicated in their reports, have been audited
by Arthur Andersen LLP, independent public accountants, as indicated in their
reports with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
reports.
The information appearing in this Prospectus regarding proved reserves of
the Company as of June 30, 1997 and the related future net revenues and the
present value thereof is derived, as to the extent described herein, from the
reserve report prepared by Lee Keeling and Associates, Inc., independent oil
and natural gas engineers, and, to such extent, are included herein in
reliance upon the authority of such firm as experts with respect to such
reports.
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-1 (as amended and together with all exhibits thereto, the "Registration
Statement") under the Securities Act, with respect to the shares of Common
Stock offered by this Prospectus. This Prospectus constitutes a part of the
Registration Statement and does not contain all of the information set forth
in the Registration Statement, certain parts of which are omitted from this
Prospectus as permitted by the rules and regulations of the Commission.
Statements in this Prospectus about the contents of any contract or other
document are not necessarily complete; reference is made in each instance to
the copy of the contract or other document filed as an exhibit to the
Registration Statement. Each such statement is qualified in all respects by
such reference. The Registration Statement and accompanying exhibits and
schedules may by inspected and copies may be obtained (at prescribed rates) at
the public reference facilities of the Commission at Judiciary Plaza, 450
Fifth Street, N.W., Room 1024, Washington, D.C. 20549. Copies of the
Registration Statement may also be inspected at the Commission's regional
offices at 7 World Trade Center, Suite 1300, New York, New York 10048 and
Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-
2511. In addition, the Company expects that the Common Stock will be listed on
the Nasdaq National Market, 1735 K Street, N.W., Washington, D.C. 20006-1500,
where such material may also be inspected and copied.
As a result of the Offering, the Company will become subject to the
information and periodic reporting requirements of the Securities Exchange Act
of 1934, as amended (the "Exchange Act"), and, in accordance therewith, will
file periodic reports, proxy statements and other information with the
Commission. Such periodic reports, proxy statements and other information will
be available for inspection and copying at the public reference facilities and
regional offices referred to above. In addition, these reports, proxy
statements and other information may also be obtained from the web site that
the Commission maintains at http://www.sec.gov.
65
<PAGE>
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and natural gas industry and this Prospectus. Unless otherwise
indicated in this Prospectus, natural gas volumes are stated at the legal
pressure base of the state or area in which the reserves are located and at 60
degrees Fahrenheit.
Average Finding Costs. The average amount of total capital expenditures,
including acquisition costs, and exploration and abandonment costs for oil and
natural gas activities divided by the amount of proved reserves (expressed in
BOE) added in the specified period (including the effect on proved reserves or
reserve revisions).
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
BOE. Barrels of oil equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu or British thermal unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Coalbed methane. Methane gas from coals in the ground, extracted using
conventional oil and natural gas industry drilling and completion methodology.
The gas produced is usually over 90% methane, with a small percentage of
ethane and impurities such as carbon dioxide and nitrogen. Methane is the
principal component of natural gas. Coalbed methane shares the same markets as
conventional natural gas, via the natural gas pipeline infrastructure.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Condensate. A hydrocarbon mixture that becomes liquid and separates from
natural gas when the natural gas is produced and is similar to oil.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry well. A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion of an oil or natural gas
well.
Exploratory well. A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which the Company has a working interest.
LOE. Lease operating expenses.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
66
<PAGE>
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMcf. One million cubic feet of natural gas.
Net acres or net wells. Gross acres or wells multiplied, in each case, by
the percentage working interest owned by the Company.
Net production. Production that is owned by the Company less royalties and
production due others.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration,
development, and production of an oil or natural gas well or lease.
Original oil in place. The estimated number of barrels of crude oil in known
reservoirs prior to any production.
Present Value of Future Net Revenues or PV-10. The present value of
estimated future net revenues to be generated from the production of proved
reserves, net of estimated production and ad valorem taxes, future capital
costs and operating expenses, using prices and costs in effect as of the date
indicated, without giving effect to federal income taxes. The future net
revenues have been discounted at an annual rate of 10% to determine their
"present value." The present value is shown to indicate the effect of time on
the value of the revenue stream and should not be construed as being the fair
market value of the properties.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and natural gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery will be included as "proved
developed reserves" only after testing by a pilot project or after the
operation of an installed program has confirmed through production response
that increased recovery will be achieved.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by natural gas-oil and/or oil-water contacts, if
any; and (B) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information on
fluid contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
ii. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
iii. Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas and natural gas liquids that
67
<PAGE>
may occur in undrilled prospects; and (D) crude oil, natural gas and
natural gas liquids that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved undeveloped reserves. Reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reserve replacement cost. Total cost incurred for exploration and
development, divided by reserves added from all sources, including reserve
discoveries, extensions and improved recovery additions, net revisions to
reserve estimates and purchases of reserves-in-place.
Reserves. Proved reserves.
Royalty. An interest in an oil and natural gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalties may be either landowner's royalties,
which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of
the leasehold in connection with a transfer to a subsequent owner.
Spud. Start drilling a new well (or restart).
3-D seismic. Seismic data that are acquired and processed to yield a three-
dimensional picture of the subsurface.
Tcf. One trillion cubic feet of natural gas.
Undeveloped acreage. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether or not such acreage contains
proved reserves. Included within undeveloped acreage are those lease acres
(held by production under the terms of a lease) that are not within the
spacing unit containing, or acreage assigned to, the productive well holding
such lease.
Waterflood. The injection of water into a reservoir to fill pores vacated by
produced fluids, thus maintaining reservoir pressure and assisting production.
Working interest. An interest in an oil and natural gas lease that gives the
owner of the interest the right to drill for and produce oil and natural gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a working
interest owner is entitled will always be smaller than the share of costs that
the working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties. For example, the owner of a
100% working interest in a lease burdened only by a landowner's royalty of
12.5% would be required to pay 100% of the costs of a well but would be
entitled to retain 87.5% of the production.
Workover. Operations on a producing well to restore or increase production.
68
<PAGE>
INDEX TO FINANCIAL STATEMENTS
FINANCIAL STATEMENTS OF PETROGLYPH ENERGY, INC.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................................. F-2
Combined Balance Sheets as of June 30, 1997 and as of December 31, 1996
and 1995................................................................. F-3
Combined Statements of Operations for the Years Ended December 31, 1994,
1995 and 1996 and for the Six Month Periods Ended June 30, 1996 and
1997..................................................................... F-4
Combined Statements of Change in Owners' Equity for the Years Ended
December 31, 1994, 1995 and 1996 and for the Six Month Periods Ended June
30, 1996 and 1997........................................................ F-5
Combined Statements of Cash Flows for the Years Ended December 31, 1994,
1995 and 1995 and for the Six Month Periods Ended June 30, 1996 and
1997..................................................................... F-6
Notes to Combined Financial Statements.................................... F-7
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Petroglyph Energy, Inc.:
We have audited the accompanying combined balance sheets of Petroglyph
Energy, Inc. (a Delaware corporation) and subsidiary as of December 31, 1996
and 1995, and the related combined statements of operations, changes in
owners' equity, and cash flows for each of the three years in the period ended
December 31, 1996. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the combined financial position of Petroglyph
Energy, Inc. and subsidiary as of December 31, 1996 and 1995 and the results
of its operations and cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
/s/ Arthur Andersen LLP
Dallas, Texas
August 20, 1997
F-2
<PAGE>
PETROGLYPH ENERGY, INC.
COMBINED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ JUNE 30,
1995 1996 1997
----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents.............. $ 1,074,936 $ 1,577,632 $ 372,452
Accounts receivable:
Oil and natural gas sales............. 709,843 1,178,287 1,008,584
Joint interest billing................ 20,206 152,118 1,551,248
Other................................. 204,224 85,037 105,268
----------- ----------- -----------
934,273 1,415,442 2,665,100
Inventory.............................. 485,545 1,064,802 1,742,567
Prepaid expenses....................... 128,606 125,045 211,765
----------- ----------- -----------
Total Current Assets................. 2,623,360 4,182,921 4,991,884
----------- ----------- -----------
Property and Equipment, Successful
efforts method at cost:
Proved properties...................... 15,360,707 13,266,674 16,338,467
Unproved properties.................... 485,138 1,269,873 1,653,604
Pipelines, gas gathering and other..... 3,008,635 3,429,985 5,295,258
----------- ----------- -----------
18,854,480 17,966,532 23,287,329
Less--Accumulated depreciation,
depletion, and amortization........... (4,188,222) (5,083,655) (5,785,851)
----------- ----------- -----------
Property and equipment, net........... 14,666,258 12,882,877 17,501,478
----------- ----------- -----------
Note receivable from directors.......... 246,500 246,500 246,500
Other assets, net....................... 61,932 157,809 804,745
----------- ----------- -----------
Total Assets......................... $17,598,050 $17,470,107 $23,544,607
=========== =========== ===========
LIABILITIES AND OWNERS' EQUITY
Current Liabilities:
Accounts payable and accrued
liabilities:
Trade................................. $ 1,258,459 $ 3,768,143 $ 4,853,255
Oil and natural gas sales............. 170,329 657,287 776,898
Deferred revenue...................... -- 45,860 --
Current portion of long-term debt..... -- 24,697 28,333
Other................................. 61,922 227,686 329,149
----------- ----------- -----------
Total Current Liabilities............ 1,490,710 4,723,673 5,987,635
----------- ----------- -----------
Long term debt.......................... 3,900,000 51,800 5,034,910
----------- ----------- -----------
Owners' equity.......................... 12,207,340 12,694,634 12,522,062
----------- ----------- -----------
Total Liabilities and Owners' Equi-
ty..................................... $17,598,050 $17,470,107 $23,544,607
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------- --------------------------
1994 1995 1996 1996 1997
----------- ----------- ----------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil sales.............. $ 1,643,985 $ 3,216,901 $ 4,458,769 $ 2,543,744 $ 1,724,768
Natural gas sales...... 796,240 1,015,863 998,920 591,973 513,363
Other.................. 44,766 36,050 -- -- 68,958
----------- ----------- ----------- ------------ ------------
Total operating
revenues........... 2,484,991 4,268,814 5,457,689 3,135,717 2,307,089
----------- ----------- ----------- ------------ ------------
Operating Expenses:
Lease operating........ 1,601,460 2,260,303 2,368,973 1,328,971 840,658
Production taxes....... 89,084 187,563 248,848 120,841 97,839
Exploration costs...... 69,570 375,649 68,818 41,610 --
Depreciation,
depletion, and
amortization.......... 1,977,121 2,302,515 2,805,693 1,277,317 1,020,221
Impairments............ -- 109,209 -- -- --
General and
administrative........ 956,129 1,063,708 902,409 590,248 546,307
----------- ----------- ----------- ------------ ------------
Total operating
expenses........... 4,693,364 6,298,947 6,394,741 3,358,987 2,505,025
----------- ----------- ----------- ------------ ------------
Operating Loss.......... (2,208,373) (2,030,133) (937,052) (223,270) (197,936)
Other Income (Expenses):
Interest income
(expense), net........ (93,327) (215,669) 40,580 15,543 19,009
Gain (loss) on sales of
property and equip-
ment, net............. 44,048 (138,614) 1,383,766 1,173,801 6,355
----------- ----------- ----------- ------------ ------------
Net income (loss) before
income taxes........... (2,257,652) (2,384,416) 487,294 966,074 (172,572)
----------- ----------- ----------- ------------ ------------
Pro Forma Income Tax
Expense (Benefit):
Current................ -- -- (222,169) 334,485 --
Deferred............... -- -- 412,213 42,284 --
----------- ----------- ----------- ------------ ------------
Total Pro Forma
Income Tax Expense
(Benefit).......... -- -- 190,044 376,769 --
----------- ----------- ----------- ------------ ------------
Pro Forma Net Income
(Loss)................. $(2,257,652) $(2,384,416) $ 297,250 $ 589,305 $ (172,572)
=========== =========== =========== ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF CHANGES IN OWNERS' EQUITY
FOR THE PERIODS ENDED JUNE 30, 1997 (UNAUDITED), DECEMBER 31, 1996, 1995 AND
1994
<TABLE>
<S> <C>
BALANCE, DECEMBER 31, 1993......................................... $ 2,217,884
Contributions..................................................... 6,631,524
Net loss before income taxes...................................... (2,257,652)
-----------
BALANCE, DECEMBER 31, 1994......................................... 6,591,756
Contributions..................................................... 8,000,000
Net loss before income taxes...................................... (2,384,416)
-----------
BALANCE, DECEMBER 31, 1995......................................... 12,207,340
Contributions..................................................... --
Net income before income taxes.................................... 487,294
-----------
BALANCE, DECEMBER 31, 1996......................................... 12,694,634
Contributions..................................................... --
Net loss before income taxes...................................... (172,572)
-----------
BALANCE, JUNE 30, 1997 (UNAUDITED)................................. $12,522,062
===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
PETROGLYPH ENERGY, INC.
COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------ ----------------------
1994 1995 1996 1996 1997
----------- ----------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Operating Activities:
Net income (loss) be-
fore income taxes..... $(2,257,652) $(2,384,416) $ 487,294 $ 966,074 $ (172,572)
Adjustments to
reconcile net income
(loss) to net cash
used in operating
activities--
Depreciation, deple-
tion, and amortiza-
tion................. 1,977,121 2,302,515 2,805,693 1,277,317 1,020,221
(Gain) loss on sales
of property and
equipment, net....... (44,048) 138,614 (1,383,766) (1,173,801) (6,355)
Amortization of de-
ferred revenue ...... -- -- (524,140) (52,951) (45,860)
Impairments........... -- 109,209 -- -- --
Exploration Costs..... 69,570 316,089 -- -- --
Property abandon-
ments................ -- 59,560 68,818 41,610 --
Amortization of fi-
nancing costs........ 22,085 66,255 -- -- --
Proceeds from deferred
revenue............... -- -- 570,000 570,000 --
Changes in assets and
liabilities--
Increase in accounts
receivable........... (710,600) (100,937) (481,169) (844,932) (1,249,658)
(Increase) decrease in
inventory............ (201,211) (275,151) (579,257) 5,460 (677,765)
(Increase) decrease in
prepaid expenses .... (41,439) (82,715) 3,561 (24,847) (86,720)
Increase (decrease) in
accounts payable and
accrued liabilities.. 1,119,024 197,759 3,162,406 141,672 1,306,186
----------- ----------- ---------- ---------- ----------
Net cash provided by
(used in) operating
activities.......... (67,150) 346,782 4,129,440 905,602 87,477
Investing Activities:
Proceeds from sales of
property and equip-
ment.................. 145,277 805,869 8,968,274 7,412,043 739,628
Additions to oil and
natural gas
properties, including
exploration costs..... (6,897,846) (8,645,491) (7,801,229) (4,468,080) (4,574,108)
Additions to pipelines,
gas gathering and oth-
er.................... (1,378,884) (1,797,955) (863,911) (127,656) (1,792,915)
Maturity of certifi-
cates of deposit...... -- 57,925 -- -- --
----------- ----------- ---------- ---------- ----------
Net cash provide by
(used in) investing
activities.......... (8,131,453) (9,579,652) 303,134 2,816,307 (5,627,395)
Financing Activities:
Contributions by part-
ners.................. 6,631,524 8,000,000 -- -- --
Note receivable from
general partner....... (246,500) -- -- -- --
Proceeds from issuance
of, and draws on,
notes payable......... 1,800,000 7,400,000 2,085,024 2,000,000 5,000,000
Payments on note pay-
able.................. -- (5,300,000) (5,908,527) (2,100,000) (13,254)
Payments for organiza-
tion and financing
costs................. (66,255) (50,620) (106,375) -- (652,008)
----------- ----------- ---------- ---------- ----------
Net cash provided by
(used in) financing
activities.......... 8,118,769 10,049,380 (3,929,878) (100,000) 4,334,738
----------- ----------- ---------- ---------- ----------
Net increase (decrease)
in cash and cash
equivalents............ (79,834) 816,510 502,696 3,621,909 (1,205,180)
Cash and cash
equivalents, beginning
of period.............. 338,260 258,426 1,074,936 1,074,936 1,577,632
----------- ----------- ---------- ---------- ----------
Cash and cash
equivalents, end of
period................. $ 258,426 $ 1,074,936 $1,577,632 $4,696,845 $ 372,452
=========== =========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1994, 1995, AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
1. ORGANIZATION:
Petroglyph Energy, Inc. ("Petroglyph" or the "Company") was incorporated in
Delaware in April 1997 for the purpose of consolidating and continuing the
activities previously conducted by Petroglyph Gas Partners, L.P. ("PGP" or the
"Partnership"). PGP is a Delaware limited partnership, which was organized on
April 15, 1993 to acquire, explore for, produce and sell oil, natural gas, and
related hydrocarbons. The general partner is Petroglyph Energy, Inc., a Kansas
corporation ("PEI"), and the primary limited partner is Natural Gas Partners,
L.P. ("NGP"). Petroglyph Gas Partners II, L.P. ("PGP II") is a Delaware
limited partnership, which was organized on April 15, 1995 to acquire, explore
for, produce and sell oil, natural gas and related hydrocarbons. The general
partner of PGP II is PEI (1% interest) and the limited partner is PGP (99%
interest). Pursuant to the terms of an Exchange Agreement dated August 22,
1997 (the "Exchange Agreement"), the Company will acquire 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
will be consummated immediately prior to the closing of the initial public
offering of the Company's Common Stock (the "Offering"). The Conversion will
be accounted for as a transfer of assets and liabilities between affiliates
under common control and will result in no change in carrying values of these
assets and liabilities.
The accompanying combined financial statements of Petroglyph include the
assets, liabilities and results of operations of PGP, its wholly owned
subsidiary, Petroglyph Operating Company, Inc. ("POCI"), and PGP's
proportionate share of assets, liabilities and revenues and expenses of PGP
II. PGP owned a 99% interest in PGP II as of December 31, 1996 and 1995 and
June 30, 1997. POCI is a subchapter C corporation. POCI is the designated
operator of all wells for which PGP has acquired operating rights.
Accordingly, all producing overhead and supervision fees were charged to the
joint accounts by POCI. All material intercompany transactions and balances
have been eliminated in the preparation of the accompanying combined financial
statements.
The Company's operations are primarily focused in the Uinta Basin of Utah
and the Raton Basin of Colorado.
Amounts presented in these Notes as of June 30, 1997 and for the six month
periods ended June 30, 1997 and 1996 are all unaudited but include all
adjustments (consisting of normal recurring accruals only) which management
considers necessary to present fairly the Company's combined financial
position as of June 30, 1997, and the combined statements of operations and
cash flows for the six month periods ended June 30, 1996 and 1997.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
MANAGEMENT'S USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
F-7
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:--(CONTINUED)
SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest during 1996, 1995 and 1994 totaled $250,000,
$266,000 and $46,000, respectively. Cash payments for interest during the six
months ended June 30, 1997 and 1996 were $23,000 and $197,000, respectively.
The Company did not make any cash payments for income taxes during 1996, 1995,
1994, or for the six month periods ended June 30, 1997 and 1996 based on its
partnership structure in effect during those periods.
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful accounts,
the amounts of which are immaterial as of June 30, 1997, December 31, 1996 and
1995.
INVENTORY
Inventories consist primarily of tubular goods and oil field materials and
supplies, which the Company plans to utilize in its ongoing exploration and
development activities and are carried at the lower of weighted average
historical cost or market value.
PROPERTY AND EQUIPMENT
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil
and natural gas properties whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized on a unit-of-
production basis over the respective properties' remaining proved reserves.
Amortization of capitalized costs is provided on a prospect-by-prospect basis.
Leasehold costs are capitalized when incurred. Unproved oil and natural gas
properties with significant acquisition costs are periodically assessed and
any impairment in value is charged to exploration costs. The costs of unproved
properties which are not individually significant are assessed periodically in
the aggregate based on historical experience, and any impairment in value is
charged to exploration costs. The costs of unproved properties that are
determined to be productive are transferred to proved oil and natural gas
properties. The Company does not capitalize general and administrative costs
related to drilling and development activities.
Exploration costs, including geological and geophysical expenses, property
abandonments and annual delay rentals, are charged to expense as incurred.
Exploratory drilling costs, if any, including the cost of stratigraphic test
wells, are initially capitalized but charged to expense if and when the well
is determined to be unsuccessful.
The Company adopted the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," in connection with its
formation. SFAS No. 121 requires that proved oil and natural gas properties be
assessed for an impairment in their carrying value whenever events or changes
in circumstances indicate that such carrying value may not be recoverable.
SFAS No. 121 requires that this assessment be performed by comparing the
anticipated future net cash flows to the net carrying value of oil and natural
gas properties. This assessment must generally be performed on a property-by-
property basis. The Company recognized impairments of $109,209 in 1995. No
such impairments were required in the years ended December 31, 1994 and
December 31, 1996 or the six month periods ended June 30, 1996 and 1997.
F-8
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:--(CONTINUED)
Pipelines, Gas Gathering and Other
Other property and equipment is primarily comprised of a field water
distribution system and a natural gas gathering system located in the Uinta
Basin, field building and land, office equipment, furniture and fixtures and
automobiles. The gathering system and the field water distribution system are
amortized on a unit-of-production basis over the remaining proved reserves
attributable to the properties served. These other items are amortized on a
straight-line basis over their estimated useful lives which range from three
to forty years.
ORGANIZATION AND FINANCING COSTS
Organization costs are amortized on a straight-line basis over a period not
to exceed 5 years and are presented net of accumulated amortization of
$54,531, $49,459 and $28,012 at June 30, 1997 and December 31, 1996 and 1995,
respectively. Amortization of $21,447, $14,610 and $7,860 is included in
depreciation, depletion and amortization expense in the accompanying
consolidated statements of operations for the years ended December 31, 1996,
1995 and 1994, respectively. Amortization of $5,072 and $11,782 is included in
depreciation, depletion and amortization expense in the consolidated statement
of operations for the six month periods ended June 30, 1997 and 1996,
respectively. Organization costs at June 30, 1997 and December 31, 1996 are
primarily comprised of costs related to the Offering. Organization costs for
periods prior to December 31, 1996 were comprised of costs related to the
formation of PGP and PGP II, which were amortized over a period of three
years.
Costs related to the issuance of the Company's notes payable are deferred
and amortized on a straight-line basis over the life of the related borrowing.
Such amortization costs of $66,255 and $22,085 are included in interest
expense in the accompanying statements of operations for the years ended
December 31, 1995 and 1994, respectively. Amortization costs for the six month
periods ended June 30, 1997 and June 30, 1996, and for the year ended December
31, 1996 were not significant.
INTEREST EXPENSE
Interest expense includes amortization of deferred debt issuance costs and
is presented net of interest income of $147,295 and $33,311 for the years
ended December 31, 1996 and 1995, respectively. Interest income totalled
$70,207 and $63,115 for the six month periods ended June 30, 1997 and 1996,
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 approximately $44,000 for the
six months ended June 30, 1997 and $195,000 and $114,000 for the years ended
December 31, 1996 and 1995, respectively. No interest was capitalized during
1994.
REVENUE RECOGNITION AND NATURAL GAS BALANCING
The Company utilizes the entitlement method of accounting for recording
revenues whereby revenues are recognized based on the Company's revenue
interest in the amount of oil and natural gas production. The amount of oil
and natural gas sold may differ from the amount which the Company is entitled
based on its revenue interests in the properties. The Company had no
significant natural gas balancing positions at June 30, 1997, December 31,
1996 and 1995.
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
F-9
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:--(CONTINUED)
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 will adopt 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 will be required
to recognize approximately $2.4 million in deferred tax liabilities and income
tax expense on the date of the Conversion.
Upon the Conversion, the Company became taxable as a corporation. Pro forma
income tax information for the year ended December 31, 1996, presented in the
accompanying combined statements of operations and in Note 6, reflects the
income tax expense (benefit), net income (loss) and net income (loss) per
common share as if all Partnership income for 1996 had been subject to
corporate federal income tax, exclusive of the effects of recording the
Company's net deferred tax liabilities upon the Conversion.
DERIVATIVES
The Company uses derivatives on a limited basis to hedge against interest
rate and product prices risks, as opposed to their use for trading purposes.
The Company's policy is to ensure that a correlation exists between the
financial instruments and the Company's pricing in its sales contracts prior
to entering into such contracts. Gains and losses on commodity futures
contracts and other price risk management instruments are recognized in oil
and natural gas revenues when the hedged transaction occurs. Cash flows
related to derivative transactions are included in operating activities.
STOCK BASED COMPENSATION
Upon Conversion, the Company will adopt 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. 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. As of June 30, 1997 and December 31, 1996 there would be no
impact from adoption of APB No. 25 or SFAS No. 123 as no stock options,
warrants or grants had been issued at such dates and none will be issued until
the date of the Conversion.
3. ACQUISITIONS AND DISPOSITIONS:
In February 1994, the Company purchased a 50% working interest in the
existing Antelope Creek and Duchesne fields in the Uinta Basin for $4.5
million. In September 1995, the Company acquired for total consideration of
$5.6 million the remaining 50% interest of its joint venture partners, Inland
Resources, in the Utah properties. The consideration consisted of $3.1 million
in cash plus assumption of Inland's outstanding debt of $2.5 million, which
was specifically collateralized by Inland's investment in the Utah properties.
The assumption of outstanding debt is not reflected on the accompanying
statement of cash flows as it is a noncash transaction. These acquisitions
were accounted for using the purchase method of accounting.
Effective September 1, 1994, the Company acquired Southwest Oil and Land's
interest in the Victoria properties in Victoria and DeWitt counties located in
Texas for approximately $1.6 million.
In June 1996, the Company sold a 50% working interest in its Antelope Creek
field properties to an industry partner. The Company retained a 50% working
interest and continues to serve as operator of the property. In exchange for
the sale of the interest in the Antelope Creek field, the Company received
$7.5 million, as adjusted,
F-10
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
3. ACQUISITIONS AND DISPOSITIONS:--(CONTINUED)
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 will pay 25% of
the development costs of the Antelope Creek field from the date of the
agreement until approximately $21 million in total development costs have been
incurred. At June 30, 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 will continue in
effect until such time as 67,389 barrels of equivalent production related to
the NPI has been produced from the Antelope Creek field. The NPI entitles 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 has been
assigned to the sale of the NPI and recorded as deferred revenue. This amount
was determined based on the projected net profits to be received from the sale
of the barrels of oil equivalent production related to the NPI. As these
barrels of oil equivalent production are produced and NPI proceeds are
disbursed to the holder of the NPI, an equal amount of the deferred revenue is
recognized as oil and natural gas revenue. Through December 31, 1996, the
Company had recognized $524,140 of revenue related to this NPI. The remaining
$45,860 was recognized during the six months ended June 30, 1997.
The following unaudited Pro Forma Condensed Combined Statements of
Operations for the six month period ended June 30, 1996, and for the years
ended December 31, 1996 and 1995 give effect to the Antelope Creek disposition
as if the sale had been consummated at January 1, 1996 and 1995. Pro forma
combined balance sheets at June 30, 1997 and December 31, 1996 are not
necessary as the historical combined balance sheets at June 30, 1997 and
December 31, 1996 include the effect of the disposition. The unaudited pro
forma data is presented for illustrative purposes only and is not necessarily
indicative of the operating results that would have occurred had the
transaction been consummated at the dates indicated, nor are they necessarily
indicative of future operating results.
PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, SIX MONTHS
----------------------- ENDED
1995 1996 JUNE 30, 1996
----------- ---------- -------------
<S> <C> <C> <C>
Oil and natural gas revenues........... $ 3,678,764 $4,400,689 $2,078,717
Other revenues......................... 36,050 -- --
----------- ---------- ----------
Total Revenues....................... 3,714,814 4,400,689 2,078,717
Lease operating expenses............... 2,085,303 1,953,973 913,971
Production taxes....................... 143,563 204,848 76,841
Exploration costs...................... 335,649 68,818 41,610
Depreciation, depletion, and amortiza-
tion.................................. 1,920,515 2,358,693 830,317
Impairments............................ 109,209 -- --
General and administrative expenses.... 1,063,708 902,409 590,248
----------- ---------- ----------
Total Expenses....................... 5,657,947 5,488,741 2,452,987
Interest income (expense), net......... (147,669) 147,580 122,543
Gain (loss) on sale of assets.......... (138,614) 69,766 (140,199)
----------- ---------- ----------
Net loss before taxes.................. (2,229,416) (870,706) (391,926)
----------- ---------- ----------
Net loss............................... $(2,229,416) $ (870,706) $ (391,926)
=========== ========== ==========
</TABLE>
F-11
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
4. TRANSACTIONS WITH AFFILIATES:
The Company has a note receivable from certain executive officers for
$246,500 at June 30, 1997, December 31, 1996 and 1995. This note bears
interest at a rate of 11% and has no set maturity date. As of July 1, 1997,
the interest rate on this note was changed to 9%.
The Company leases its office building from an affiliate. Rentals paid to
the affiliate for such leases were $17,400 for each of the six month periods
ended June 30, 1997 and 1996 (unaudited). Rentals paid during 1996, 1995 and
1994 totaled $34,800, $39,200 and $24,000, respectively. These rentals are
included in general and administrative expense in the accompanying financial
statements.
In August 1997, the Company and NGP entered into a financial advisory
services agreement whereby NGP has agreed to provide financial advisory
services to the Company for a quarterly fee of $13,750. In addition, NGP will
be reimbursed for its out of pocket expenses incurred in performing such
services. The agreement is for a one year term and can be terminated by NGP at
the end of any fiscal quarter. Under the agreement, NGP will assist the
Company in managing its public and private financing activities, its public
financial reporting obligations, its budgeting and planning processes, and its
investor relations program, as well as provide ongoing strategic advice. NGP
will not receive any other transaction-related compensation for its advisory
assistance.
For the year ended December 31, 1996, the Company paid legal fees of
$109,000 to the law firm of Morris, Laing, Evans, Brock & Kennedy, Chartered,
where A.J. Schwartz, a director of the Company, is a partner. For the six
months ended June 30, 1997, the Company paid legal fees to Morris, Laing,
Evans, Brock & Kennedy, Chartered of $81,000.
5. LONG-TERM DEBT:
At December 31, 1994, the Company had a note payable to Enron Capital and
Trade Resources ("ECTR") for $1,800,000. As stated in the ECTR note agreement,
the first $1,500,000 of loans were to be designated as production loans, and
amounts after this initial amount were to be designated as development loans
related to the Company's Utah properties. The note bore interest at a rate
equal to the prime rate plus 1.5% for the production loan and the prime rate
plus 4.0% for the development loan. The note was paid in full September 1995.
The Company negotiated a $10,000,000 loan facility with Texas Commerce Bank
National Association ("TCB") of Dallas, Texas, as agent for a group of
financial institutions, in May 1995. The loan facility is collateralized by
the Company's oil and natural gas properties located in Utah and contains
certain financial covenants with which the Company was in compliance at June
30, 1997 and December 31, 1995 and 1996. The loan facility is a combination
credit facility with a revolving credit agreement, which expired on May 25,
1997, at which time all balances outstanding under the revolving credit
agreement were to convert to a term loan, expiring on October 1, 1999. The
revolving loan facility was redetermined at $7.5 million on July 2, 1997. This
effectively allowed the Company to continue to borrow on the facility in place
at June 30, 1997. Subsequent to the redetermination, the Company has borrowed
an additional $2.5 million for a total outstanding obligation under this
facility of $7.5 million at August 22, 1997. Interest on the revolver is at
TCB's prime plus .375% and on the term loan is at TCB prime plus .75%. The
Company is currently negotiating and has agreed to terms with TCB to provide
an additional $2.5 million to the Company through an amendment to the loan
facility. As part of this negotiation, the agent was changed from TCB to The
Chase Manhattan Bank; however, the group of lenders remains unchanged.
F-12
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
5. LONG-TERM DEBT:--(CONTINUED)
In July 1996, the Company used proceeds received from the sale of oil and
gas properties to pay in full the outstanding balance of $5.9 million on the
revolver. The revolver was still open at December 31, 1996, although there is
no outstanding balance due as of that date. The availability to the Company
under this revolver at December 31, 1996 was $7.5 million. The Company pays a
commitment fee of three-eighths of 1% on the unused portion of the available
borrowings under the Revolver. There were no outstanding amount under this
line of credit at December 31, 1996. As of June 30, 1997, the Company had
drawn approximately $5,000,000 upon its revolving line of credit to provide
funding for the 1997 development expenditures on the Company's Utah
properties. As of August 22, 1997, $7,500,000 was outstanding under the
Revolver.
In September 1996, the Company entered into a term loan with a local lender
covering four vehicles. The principal balance was $85,000 and bears interest
at an annual rate of 7.5%. The loan matures on September 16, 1999 and is
secured by the four vehicles. At December 31, 1996, the outstanding balance is
$76,497, $51,800 of which is presented as long-term debt in the accompanying
Combined Statement of Assets, Liabilities and Owners' Equity. At June 30,
1997, the outstanding balance of this loan is $63,243, $34,910 of which is
presented as long-term debt.
Aggregate maturities of long-term debt at December 31, 1996 and June 30,
1997 are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1996 JUNE 30, 1997
----------------- -------------
(UNAUDITED)
<S> <C> <C>
1997....................................... $24,697 --
1998....................................... 28,800 $ 28,333
1999....................................... 23,000 5,034,910
2000....................................... -- --
</TABLE>
6. PRO FORMA INCOME TAXES:
The pro forma effective income tax rate for the Company was different than
the statutory federal income tax rate for the periods shown below, for the
following reasons (in thousands):
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------ ------------------
1994 1995 1996 1997 1996
--------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Pro Forma Income Tax expense
(benefit) at the federal
statutory rate of 35%....... $(790,178) $(834,546) $170,552 $(60,400) $338,126
Pro Forma State income tax
expense (benefit)........... (90,306) (95,377) 19,492 (6,903) 38,643
Pro Forma Net operating loss
utilized by partners........ 880,484 929,923 -- 67,303 --
--------- --------- -------- -------- --------
$ -- $ -- $190,044 $ -- $376,769
========= ========= ======== ======== ========
</TABLE>
Components of pro forma income tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, JUNE 30,
------------------- -------------------
1994 1995 1996 1996 1997
---- ---- --------- ---------- --------
<S> <C> <C> <C> <C> <C>
Current............................. -- -- $(222,169) $334,485 --
Deferred............................ -- -- 412,213 42,284 --
--- --- --------- ---------- -----
Total............................. -- -- $ 190,044 376,769 --
=== === ========= ========== =====
</TABLE>
F-13
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
6. PRO FORMA 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 pro forma net deferred tax liability positions as
of December 31, 1995 and 1996 and June 30, 1997 are summarized below:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- JUNE 30,
1995 1996 1997
--------- ----------- -----------
<S> <C> <C> <C>
Inventory............................. $ (53,820) $ (53,820) $ (43,602)
Property and equipment................ (855,515) (1,267,728) (2,361,705)
--------- ----------- -----------
Total............................... $(909,335) $(1,321,548) $(2,405,307)
========= =========== ===========
</TABLE>
The pro forma net deferred tax liability as of June 30, 1997 is
approximately the amount that the Company expects will be required to be
recognized as income tax expense on the date of the Conversion discussed in
Note 2.
7. DERIVATIVES, SALES CONTRACTS AND SIGNIFICANT CUSTOMERS:
DERIVATIVES AND SALES CONTRACTS
The Company accounts for forward sales transactions as hedging activities
and, accordingly, records all gains and losses in oil and natural gas revenues
in the period the hedged production is sold. Included in oil revenue is a net
loss of $128,400 in 1996. Losses incurred during 1994 and 1995 were not
significant. Losses included in oil revenue for the six month periods ended
June 30, 1996 and 1997, are $39,800 and $113,800, respectively. Included in
natural gas revenues in 1997 is a net loss of $42,000.
In August 1994, the Company entered into a financial swap arrangement
covering the sale of 549,000 barrels of oil production from January 1996 to
December 1999, at a floor price of $17.00 per Bbl and a ceiling price of
$20.75 per Bbl. This agreement was terminated in October of 1995, for which
the Company received a premium of $170,000. This premium is included in oil
revenue for the year ended December 31, 1995 in the accompanying Combined
Statement of Operations.
In January 1995, the Company entered into an additional swap arrangement
covering the sale of 4,000 Bbls per month from February 1995 to January 1996,
at a floor price of $17.00 per Bbl and a ceiling price of $19.00 per Bbl. This
agreement was terminated in October 1995. In September 1995, the Company
assumed the obligations of a former joint interest owner under a financial
swap arrangement. This agreement covers the sale of 549,000 Bbls from January
1996 to December 1999 at a floor price of $17.00 per Bbl and a ceiling price
of $20.75 per Bbl. At June 30, 1997, this contract was outstanding and calls
for the remaining sale of 378,000 barrels of oil over the next three years as
follows:
<TABLE>
<CAPTION>
YEAR BBLS
---- -------
<S> <C>
1997................................. 69,000
1998................................. 150,000
1999................................. 159,000
-------
Total.............................. 378,000
=======
</TABLE>
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
F-14
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
7. DERIVATIVES, SALES CONTRACTS, AND SIGNIFICANT CUSTOMERS:--(CONTINUED)
based on this purchaser's posted price for Yellow or Black Wax production, as
applicable. This contract will continue in effect until terminated by either
party upon giving proper notice. During the three years ended December 31,
1996, the volumes sold under this contract totaled 65,931, 101,115 and 60,663
Bbls, respectively, at an average sales price per Bbl for each year of $16.51,
$17.09 and $19.33. For the six month period ended June 30, 1997, the Company
sold 28,359 Bbls under this contract at an average price of $15.36
(unaudited).
In January of 1996, the Company entered into a contract to sell Black Wax
production from its Utah leases to Purchaser "B". The price under this
contract is based on the monthly average of the NYMEX price for West Texas
Intermediate ("WTI") crude oil, less $.50 per Bbl, adjusted for the pricing
differential related to the gravity difference between Purchaser B's Utah
Black Wax posting and WTI, less $2.50 per
Bbl to cover gathering costs and quality differential. During the year ended
December 31, 1996, the Company sold 59,048 Bbls of oil under this contract at
an average price of $19.69 per Bbl. This contract was cancelled effective
January 1, 1997.
In July 1997, the Company entered into a modification of its crude oil sales
contract to sell all of its equity share of Black Wax crude oil production
from the Antelope Creek field to Purchaser "C" at a per Bbl price equal to
posting, less $2.00 per Bbl to cover handling and gathering costs. This
contract supersedes the contract which the Company had with this purchaser
from February 1994 through June 1997. This contract will continue in effect
until terminated by either party upon giving proper notice. For the six month
period ended June 1, 1997, the Company sold 49,633 Bbls under this contract at
an average price of $15.32 per Bbl (unaudited).
In June 1997, the Company entered into a crude oil contract to sell Black
Wax production from certain of its oil tank batteries in Antelope Creek to
Purchaser "D". This contract is effective until May 31, 1998 and calls for the
Company to receive a per Bbl price equal to the current month NYMEX closing
price for sweet crude, averaged over the month in which the crude is sold,
less an agreed upon fixed adjustment. This contract replaces a contract the
Company had with Purchaser "D" for the month of April 1997. Volumes sold under
this contract totaled 19,623 Bbls at an average price of $15.37 for the six
months ended June 30, 1997.
In addition to the sales contracts discussed above, Purchaser "C" has a call
on all of the Company's share of oil production from the Antelope Creek field,
which has priority over all other sales contracts. Under the terms of the Oil
Production Call Agreement (the "Call Agreement"), which the Company assumed in
connection with its acquisition of its initial interest in the Antelope Creek
field, this purchaser has the option to purchase all or any portion of the oil
produced from the Antelope Creek field at the current market price for the
gravity and type of oil produced and delivered by the Company. The Call
Agreement was assumed by the Company on the date it acquired its interest in
the Antelope Creek field and has no expiration date. In the event Purchaser
"C" exercises the call option, the Company will not be penalized under its
other sales contracts for failure to deliver volumes thereunder.
SIGNIFICANT CUSTOMERS
The Company's revenues are derived principally from uncollateralized sales
to customers in the oil and gas industry. The concentration of credit risk in
a single industry affects the Company's overall exposure to credit risk
because customers may be significantly affected by changes in economic and
other conditions. In addition, the Company sells a significant portion of its
oil and natural gas revenue each year to a few customers. Oil sales to three
purchasers in 1996 were approximately 26%, 26% and 12% of total 1996 oil and
gas revenues. Oil sales to one purchaser in 1995 was approximately 43% of
total 1995 oil and natural gas revenues. Oil sales to two purchasers in 1994
were approximately 45% and 12% of total 1994 oil and natural gas revenues.
Natural gas
F-15
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
7. DERIVATIVES, SALES CONTRACTS, AND SIGNIFICANT CUSTOMERS:--(CONTINUED)
sales to one purchaser in 1994 were approximately 23% of total 1994 oil and
natural gas revenues. Oil sales to three purchasers during the six month
period ended June 30, 1997, were approximately 34%, 20% and 14% of total oil
and natural gas revenues for the same period. Natural gas sales to one
purchaser for the six month period ended June 30, 1997 were approximately 20%
of total oil and natural gas sales for the same period. The Company does not
believe that the loss of these purchasers would adversely impact its ability
to market its production.
8. 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 June 30, 1997 and at December 31, 1995
and 1996. The fair value of the Company's bank borrowings approximate their
carrying value because the borrowings bear interest at market rates. The
Company does not have any investments in debt or equity securities at June 30,
1997, or at December 31, 1995 or 1996. The fair value of the Company's
outstanding oil price swap arrangement, described in the preceding note, has
an estimated fair value of $(255,000), $170,000 and $(576,000) at June 30,
1997, December 31, 1995 and 1996, respectively. These estimates are based on
quoted market values.
9. STOCK INCENTIVE 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 Board of
Directors or such committee of the Board as is designated by the Board to
administer the 1997 Incentive Plan (upon completion of the Offering, the
Compensation Committee of the Board of Directors) from among those who hold
positions of responsibility and whose performance, in the judgment of the
Compensation Committee, can have a significant effect on the success of the
Company. An aggregate of 375,000 shares of Common Stock have been authorized
and reserved for issuance pursuant to the 1997 Incentive Plan. As of August
22, 1997, options have been granted to the participants under the 1997
Incentive Plan to purchase a total of 260,000 shares of Common Stock to
participants at an exercise price per share equal to the Price to Public set
forth on the cover page of this Prospectus. One-third of these options will
vest each year on the anniversary date of the offering.
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.
F-16
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
10. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company leases offices and office equipment in its primary locations
under non-cancelable operating leases. As of June 30, 1997 and December 31,
1996, minimum future lease payments for all non-cancelable lease agreements
are as follows:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, 1996 JUNE 30, 1997
----------------- ----------------
(UNAUDITED)
<S> <C> <C>
1997......................................... $22,882 $ 5,134
1998......................................... 9,650 8,518
1999......................................... 8,100 8,100
2000......................................... 7,425 7,425
2001......................................... -- --
------- -------
Total...................................... $48,057 $29,177
======= =======
</TABLE>
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $56,142, $50,543 and $41,548 in 1994, 1995 and 1996,
respectively. Amounts incurred by the Company under these same leases for the
six month periods ended June 30, 1997 and 1996 are $22,659 and $17,696,
respectively (unaudited).
LITIGATION
The Company and its subsidiary are involved in certain litigation and
certain governmental proceedings arising in the normal course of business.
Company management and legal counsel do not believe that ultimate resolution
of these claims will have a material effect on the Company's financial
position or results of operations.
OTHER COMMITMENTS
On December 9, 1996, the Company entered into an agreement with an industry
partner whereby the industry partner would pay for the costs of a three-
dimensional seismic survey on the Company's leasehold interests in the Helen
Gohlke field, located in Victoria County, 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
F-17
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
10. COMMITMENTS AND CONTINGENCIES:--(CONTINUED)
other activities on certain lands lying within wilderness and other protected
areas; and impose substantial liabilities for pollution resulting from the
Company's operations. The permits required for various of the Company's
operations are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance
with their regulations, and violations are subject to fines or injunction, or
both. In the opinion of management, the Company is in substantial compliance
with current applicable environmental laws and regulations, and the Company
has no material commitments for capital expenditures to comply with existing
environmental requirements. Nevertheless, changes in existing environmental
laws and regulations or in interpretations thereof could have a significant
impact on the Company, as well as the oil and natural gas industry in general.
11. SUBSEQUENT EVENTS:
On February 28, 1997, the Company sold its Arco Fee properties, located in
Texas, for approximately $600,000. The Company recognized a gain of
approximately $120,000 on this sale.
In July of 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. 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 $300,000. 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 is obligated to pay
$200,000 by July, 1998, and an additional $41,000 by July, 1999.
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED):
All of the Company's operations are directly related to oil and natural gas
producing activities located in the United States, therefore, a separate
result of operations disclosure is not necessary.
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,
-------------------------------- SIX MONTHS ENDED
1994 1995 1996 JUNE 30, 1997
---------- ---------- ---------- ----------------
<S> <C> <C> <C> <C>
Acquisition
Unproved Properties......... $ 52,685 $ 8,206 $ 490,487 $ 416,601
Proved Properties........... 5,193,043 4,718,201 -- --
Development................... 1,311,272 3,448,972 6,983,715 4,057,976
Exploration................... 69,570 316,089 -- --
Improved recovery costs....... 271,276 154,023 327,027 99,531
---------- ---------- ---------- ----------
Total..................... $6,897,846 $8,645,491 $7,801,229 $4,574,108
========== ========== ========== ==========
</TABLE>
PROVED RESERVES
Independent petroleum engineers have estimated the Company's proved oil and
natural gas reserves as of June 30, 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
F-18
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED):--(CONTINUED)
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed reserves are the quantities expected to be recovered through
existing wells with existing equipment and operating methods. Due to the
inherent uncertainties and the limited nature of reservoir data, such
estimates are subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of these reserves
may be substantially different from the original estimate. Revisions result
primarily from new information obtained from development drilling and
production history and from changes in economic factors.
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows ("standardized
measure") and changes in such cash flows are prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include
the use of year-end prices for oil and natural gas and year-end costs for
estimated future
development and production expenditures to produce year-end estimated proved
reserves. Discounted future net cash flows are calculated using a 10% rate.
Estimated future income taxes are calculated by applying year-end statutory
rates to future pre-tax net cash flows, less the tax basis of related assets
and applicable tax credits.
The standardized measure does not represent management's estimate of the
Company's future cash flows or the value of the proved oil and natural gas
reserves. Probable and possible reserves, which may become proved in the
future, are excluded from the calculations. Furthermore, year-end prices used
to determine the standardized measure of discounted cash flows are influenced
by seasonal demand and other factors and may not be the most representative in
estimating future revenues or reserve data.
F-19
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING ACTIVITIES
(UNAUDITED):--(CONTINUED)
<TABLE>
<CAPTION>
OIL NATURAL GAS
(BBLS) (MCF)
--------- -----------
<S> <C> <C>
PROVED RESERVES:
December 31, 1993....................................... 525,882 2,786,957
Revisions.............................................. (331,422) 282,725
Extensions, additions and discoveries.................. 405,070 788,305
Production............................................. (110,373) (485,062)
Purchases of reserves.................................. 741,579 4,096,791
Sales in place......................................... (25,767) (162,357)
--------- ----------
December 31, 1994....................................... 1,204,969 7,307,359
Revisions.............................................. (295,013) (698,765)
Extensions, additions and discoveries.................. 291,097 181,797
Production............................................. (182,704) (659,202)
Purchases of reserves.................................. 628,789 694,187
Sales in place......................................... (86,046) (166,216)
--------- ----------
December 31, 1995....................................... 1,561,092 6,659,160
Revisions.............................................. (801,535) (3,146,699)
Extensions, additions and discoveries.................. 6,440,869 18,448,489
Production............................................. (262,910) (553,770)
Purchases of reserves.................................. -- --
Sales in place......................................... (810,380) (2,594,717)
--------- ----------
December 31, 1996....................................... 6,127,136 18,812,463
Revisions.............................................. 1,292,689 1,580,650
Extensions, additions and discoveries.................. 578,757 760,047
Production............................................. (117,770) (243,095)
Purchases of reserves.................................. -- --
Sales in place......................................... (156,675) --
--------- ----------
June 30, 1997........................................... 7,724,137 20,910,065
========= ==========
PROVED DEVELOPED RESERVES:
December 31, 1993...................................... 525,882 2,786,957
========= ==========
December 31, 1994...................................... 1,204,969 7,307,359
========= ==========
December 31, 1995...................................... 1,561,092 6,659,160
========= ==========
December 31, 1996...................................... 865,018 3,010,401
========= ==========
June 30, 1997.......................................... 1,849,412 4,850,895
========= ==========
</TABLE>
F-20
<PAGE>
PETROGLYPH ENERGY, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1994, 1995 AND 1996
JUNE 30, 1996 AND 1997 (UNAUDITED)
12. SUPPLEMENTAL FINANCIAL INFORMATION OIL AND NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED):--(CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------- JUNE 30,
1994 1995 1996 1997
----------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Future cash inflows..... $36,973,132 $40,419,081 $184,248,490 $149,594,640
Future costs:
Production............. (20,315,350) (17,987,575) (43,993,010) (47,054,005)
Development............ -- -- (16,455,901) (18,145,975)
----------- ----------- ------------ ------------
Future net cash flows
before income tax...... 16,657,782 22,431,506 123,799,579 84,394,660
Future income tax....... (2,032,872) (3,032,875) (32,657,687) (21,458,867)
----------- ----------- ------------ ------------
Future net cash flows... 14,624,910 19,398,631 91,141,892 62,935,793
10% annual discount..... (4,264,268) (6,027,926) (43,117,804) (31,917,544)
----------- ----------- ------------ ------------
Standardized Measure.... $10,360,642 $13,370,705 $ 48,024,088 $ 31,018,249
=========== =========== ============ ============
Changes in Standardized Measure of Discounted Future Net Cash Flows
<CAPTION>
DECEMBER 31,
-------------------------------------- JUNE 30,
1994 1995 1996 1997
----------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Standardized Measure,
January 1.............. $ 3,295,195 $10,360,642 $ 13,370,705 $ 48,024,088
Revisions:
Prices and costs....... (1,696,963) (525,763) 4,839,954 (29,472,218)
Quantity estimates..... 52,989 (989,701) 6,000,942 7,745,031
Accretion of discount.. 418,262 1,169,449 1,484,547 3,460,353
Future development
costs................. -- -- (15,068,164) 439,331
Income tax............. (178,573) (269,251) (14,604,066) 4,971,181
Production rates and
other................. (237,342) (1,227,766) 1,901,254 (5,480,645)
----------- ----------- ------------ ------------
Net revisions....... (1,641,627) (1,843,032) (15,445,533) (18,336,967)
Extensions, additions
and discoveries........ 1,943,705 3,728,389 56,781,465 2,332,717
Production.............. (434,154) (1,156,297) (2,390,023) (1,199,752)
Development costs....... -- -- -- 1,305,230
Purchases in place...... 7,450,474 2,609,642 -- --
Sales in place.......... (252,951) (328,639) (4,292,526) (1,107,067)
----------- ----------- ------------ ------------
Net change.......... 7,065,447 3,010,063 34,653,383 (17,005,839)
----------- ----------- ------------ ------------
Standardized Measure,
End of period.......... $10,360,642 $13,370,705 $ 48,024,088 $ 31,018,249
=========== =========== ============ ============
</TABLE>
Year-end weighted average oil prices used in the estimation of proved
reserves and calculation of the standardized measure were $17.01, $18.00, and
$19.50 per Bbl at December 31, 1994, 1995, and 1996, respectively. Year-end
weighted average gas prices were $1.45, $1.85, and $3.37 per Mcf at December
31, 1994, 1995, and 1996, respectively. Weighted average oil and natural gas
prices used in the estimation proved reserves and calculation of the
standardized measure at June 30, 1997 are $15.09 per Bbl and $1.71 per Mcf,
respectively.
Price and cost revisions are primarily the net result of changes in period-end
prices, based on beginning of period reserve estimates.
The Company's proved oil and natural gas reserves at June 30, 1997, using
weighted average oil and natural gas prices for the twelve months ending June
30, 1997 of $17.19 per Bbl of oil and $2.12 per Mcf of natural gas, would have
been 11,389,034 BOE, as compared to 11,209,147 BOE using oil and natural gas
prices in effect at June 30, 1997. The standardized measure of the Company's
proved oil and natural gas reserves using the weighted average prices for such
twelve month period would have been $40,406,588, as compared to $31,018,249
using oil and natural gas prices in effect at June 30, 1997.
F-21
<PAGE>
EXHIBIT 1
PETROGLYPH ENERGY, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
The following table indicates the calculation of the Company's ratio of
earnings to fixed charges for the six month period ended June 30, 1997, and for
each of the four years in the period ended December 31, 1996:
<TABLE>
<CAPTION>
JUNE 30,
1993 1994 1995 1996 1997
--------- ----------- ----------- -------- ---------
<S> <C> <C> <C> <C> <C>
Net income (loss)....... $(123,636) $(2,257,652) $(2,384,416) $487,294 $(172,572)
Income tax expense..... -- -- -- -- --
Interest expense....... -- 93,327 363,076 301,863 95,632
Interest portion of
rentals............... -- -- -- -- --
Preferred stock
dividends............. -- -- -- -- --
--------- ----------- ----------- -------- ---------
Earnings (loss) before
provision for taxes and
fixed charges.......... $(123,636) $(2,164,325) $(2,021,340) $789,157 $ (76,940)
--------- ----------- ----------- -------- ---------
Interest expense........ -- $ 93,327 $363,076 $301,863 $ 95,632
Interest portion of
rentals................ -- -- -- -- --
Preferred stock
dividends.............. -- -- -- -- --
Total fixed charges..... -- $93,327 $363,076 $301,863 $ 95,632
--------- ----------- ----------- -------- ---------
Ratio of earnings to
fixed charges.......... -- (23.19) (5.57) 2.61 (0.80)
Excess of fixed charges
over income (loss)..... $(123,636) $(2,257,652) $(2,384,416) $487,294 $(172,572)
</TABLE>
F-22
<PAGE>
[LEE KEELING AND ASSOCIATES, INC. LETTERHEAD]
SEPTEMBER 26, 1997
Petroglyph Energy, Inc.
6209 North Highway 61
Hutchinson, Kansas 67502
Attn: Robert A. Christensen
Gentlemen:
In accordance with your request, we have estimated the proved reserves and
future revenue, as of June 30, 1997, to the interest of Petroglyph Energy,
Inc. and its successors and subsidiaries (collectively "Petroglyph") in
certain oil and natural gas properties located in Utah, Texas and Kansas as
listed in the accompanying tabulations. This report has been prepared using
constant prices and costs and conforms to the guidelines of the Securities and
Exchange Commission ("SEC").
We estimate the net reserves and future net revenues to the Petroglyph
interest, as of June 30, 1997, to be:
<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUES
--------------------- -----------------------------
OIL NATURAL GAS PRESENT WORTH
CATEGORY (BBLS) (MCF) TOTAL DISCOUNTED AT 10%
- -------- --------- ----------- ----------- -----------------
<S> <C> <C> <C> <C>
Proved Developed:
Producing 994,193 2,924,633 $10,434,000 $ 7,826,000
Non-Producing 855,219 1,926,262 7,998,000 4,564,000
Proved Undeveloped 5,874,725 16,059,170 65,963,000 30,481,000
--------- ---------- ----------- -----------
Total Proved 7,724,137 20,910,065 $84,395,000 $42,871,000
========= ========== =========== ===========
</TABLE>
The oil reserves shown include crude oil, condensate and natural gas plant
liquids. Oil volumes are expressed in barrels which are equivalent to 42
United States gallons. Natural Gas volumes are expressed in thousands of
standard cubic feet (Mcf) at the contract temperature and pressure bases.
This report includes summary projections of reserves and future net revenues
for each reserve category. For the purposes of this report, the term "lease"
refers to a single economic projection.
A-1
<PAGE>
The estimated reserves and future net revenues shown in this report are for
proved developed producing, proved developed non-producing and proved
undeveloped reserves. In accordance with SEC guidelines, our estimates do not
include any value for probable or possible reserves which may exist for these
properties. This report does not include any value which could be attributed
to interests in undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.
Future gross revenue to the Petroglyph interest is prior to deducting state
and tribal production taxes and ad valorem taxes. Future net revenues are
computed after deducting these taxes, future capital costs and operating
expenses, but before consideration of federal income taxes. In accordance with
SEC guidelines, the future net revenues have been discounted at an annual rate
of 10% to determine its "present worth." The present worth is shown to
indicate the effect of time on the value of money and should not be construed
as being the fair market value of the properties.
For the purposes of this report, a field inspection of the properties has
not been performed nor has the mechanical operation or condition of the wells
and their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
As requested, oil prices used in this report are based on a June 30, 1997
weighted average posted price of $15.09 per Bbl, adjusted by lease for
gravity, transportation fees and regional posted price differentials. Natural
gas prices used in this report are based on a June 30, 1997 weighted average
price of $1.71 per McF, adjusted by lease for transportation fees and regional
spot market price differentials. Oil, natural gas liquids and natural gas
prices are held constant in accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records of
Petroglyph. As requested, the Petroglyph operated properties include only direct
lease and field level costs. Headquarters general and administrative overhead
expenses of Petroglyph are not included. Lease and well operating costs are held
constant in accordance with SEC guidelines. Capital costs are included as
required for workovers, new development and injection wells and production and
enhanced recovery equipment.
We have made no investigation of potential natural gas volume and value
imbalances which may have resulted from over delivery or underdelivery to the
Petroglyph interest. Therefore, our estimates of reserves and future net
revenues do not include adjustments for the settlement of any such imbalances;
our projections are based on Petroglyph receiving its net revenue interest
share of estimated future gross natural gas production.
This report has been prepared utilizing methods and procedures regularly
used by petroleum engineers to estimate oil and gas reserves for properties of
this type and character. The recovery of oil and natural gas reserves and
projection of producing rates are dependent upon many variable factors
including prudent operation, development of the proposed enhanced recovery
project, injection of water, compression of natural gas when needed, market
demand, installation of lifting equipment, and remedial work when required.
The reserves included in this report have been based upon the assumption that
the wells will be operated in a
A-2
<PAGE>
prudent manner and that the waterflood expansion will proceed as projected.
Actual production results and future well data may yield additional facts, not
presently available to us, which will require an adjustment to our estimates.
The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less
than the estimated amounts. The sales rates, prices received for the reserves,
costs incurred in recovering such reserves and future capital costs may vary
from assumptions included in this report due to governmental policies,
uncertainties of supply and demand and other factors. Also, estimates of
reserves may increase or decrease as a result of future operations.
In evaluating the information at our disposal concerning this report, we
have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and natural gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological
data; therefore, our conclusions necessarily represent only informed
professional judgments.
The titles to the properties have not been examined by Lee Keeling and
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Petroglyph and the nonconfidential files of Lee Keeling and Associates, Inc.
and were accepted as accurate. We are independent petroleum engineers, and
geologists; we do not own an interest in these properties and are not employed
on a contingent basis. Basic geologic and field performance data together with
our engineering work sheets are maintained on file in our office.
Very truly yours,
/s/ Lee Keeling and Associates, Inc.
Lee Keeling and Associates, Inc.
<PAGE>
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY IN-
FORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFER MADE BY THIS PROSPECTUS AND, IF GIVEN
OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS
DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF ANY OFFER TO BUY
ANY SECURITIES OTHER THAN THE SHARES OF COMMON STOCK OFFERED BY THIS PROSPEC-
TUS, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF ANY OFFER TO
BUY THE SHARES OF COMMON STOCK BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OF-
FER OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OF-
FER OR SOLICITATION IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PRO-
SPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY
IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME
SUBSEQUENT TO THE DATE HEREOF.
UNTIL NOVEMBER 14, 1997, ALL DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED
SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED
TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO
DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UN-
SOLD ALLOTMENTS OR SUBSCRIPTIONS.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
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<S> <C>
Prospectus Summary....................................................... 3
Risk Factors............................................................. 10
The Company.............................................................. 19
Use of Proceeds.......................................................... 20
Dividend Policy.......................................................... 20
Dilution................................................................. 21
Capitalization........................................................... 22
Pro Forma Condensed Consolidated Statements of Operations................ 23
Selected Consolidated Financial Data..................................... 26
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 28
Business and Properties.................................................. 36
Management............................................................... 54
Executive Compensation and Other Information............................. 57
Certain Transactions..................................................... 58
Principal Stockholders................................................... 59
Description of Capital Stock............................................. 60
Shares Eligible for Future Sale.......................................... 62
Underwriting............................................................. 63
Legal Matters............................................................ 65
Experts.................................................................. 65
Available Information.................................................... 65
Glossary of Oil and Natural Gas Terms.................................... 66
Index to Financial Statements............................................ F-1
Summary Reserve Report................................................... A-1
</TABLE>
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2,500,000 Shares
LOGO
PETROGLYPH
ENERGY, INC.
Common Stock
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PROSPECTUS
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PRUDENTIAL SECURITIES INCORPORATED
OPPENHEIMER & CO., INC.
JOHNSON RICE & COMPANY L.L.C.
October 20, 1997
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