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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
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[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1999
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _____ to _____
Commission File Number: 000-23185
PETROGLYPH ENERGY, INC.
(Exact name of Registrant as specified in its charter)
DELAWARE 74-2826234
(State or other jurisdiction (I.R.S. Employer
of incorporation or Identification No.)
organization)
1302 NORTH GRAND STREET
HUTCHINSON, KANSAS 67501
(Address of principal executive offices) (Zip Code)
(316) 665-8500
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
As of October 31, 1999, 5,458,333 shares of common stock, par value $.01
per share, of Petroglyph Energy, Inc. were outstanding.
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TABLE OF CONTENTS
Page
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Forward Looking Information and Risk Factors.................................................................... 1
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 1999 and December 31, 1998....................... 2
Consolidated Statements of Operations for the Three Months and Nine Months Ended
September 30, 1999 and 1998............................................................... 3
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 1999 and 1998............................................................... 4
Notes to Consolidated Financial Statements....................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 8
Item 3.Quantitative and Qualitative Disclosures About Market Risk.............................................. 14
PART II -- OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K....................................................................... 15
Signatures....................................................................................... 16
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PETROGLYPH ENERGY, INC.
FORWARD LOOKING INFORMATION AND RISK FACTORS
Petroglyph Energy, Inc. (the "Company") or its representatives may make
forward looking statements, oral or written, including statements in this
report's Management's Discussion and Analysis of Financial Condition and Results
of Operations, press releases and filings with the Securities and Exchange
Commission, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and natural gas production, the
number of wells the Company anticipates drilling in quarterly and annual
periods, the Company's projected financial position, results of operations,
business strategy and other plans and objectives for future operations. Although
the Company believes that the expectations reflected in these forward looking
statements are reasonable, there can be no assurance that the actual results or
developments anticipated by the Company will be realized or, even if
substantially realized, that they will have the expected effects on its business
or results of operations. Such forward-looking statements involve known and
unknown risks, uncertainties and other factors which may cause the actual
results, performance or achievements of the Company to be materially different
from any future results, performance or achievements expressed or implied by
such forward-looking statements. Such factors include but are not limited to
risks inherent in drilling and other development activities, the timing and
extent of changes in commodity prices, unforeseen engineering and mechanical or
technological difficulties in drilling wells and implementing enhanced oil or
coalbed methane gas recovery programs, inaccuracies in measurement, the
availability, proximity and capacity of refineries, pipelines and processing
facilities, shortages or delays in the delivery of equipment and services, land
issues, federal, state and tribal regulatory developments and other risks more
fully described in the Company's filings with the Securities and Exchange
Commission. All subsequent oral and written forward looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by these factors. The Company assumes no obligation
to update any of these statements.
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PETROGLYPH ENERGY, INC
Consolidated Balance Sheets
(in thousands)
ASSETS SEPTEMBER 30, DECEMBER 31,
1999 1998
-------------- --------------
(Unaudited) (Audited)
Current Assets:
Cash and cash equivalents $ 274 $ 2,008
Accounts receivable:
Oil and natural gas sales 758 265
Joint interest billing 30 835
Other 61 133
Inventory 1,363 1,234
Prepaid expenses 143 247
-------------- --------------
Total Current Assets 2,629 4,722
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Property and Equipment, successful efforts method at cost:
Proved properties 39,424 32,191
Unproved properties 10,684 10,072
Pipelines, gas gathering and other 10,395 10,025
-------------- --------------
60,503 52,288
Less: Accumulated depletion, depreciation and amortization (12,090) (11,590)
-------------- --------------
Property and equipment, net 48,413 40,698
Other assets, net of accumulated amortization 284 615
-------------- --------------
Total Assets $ 51,326 $ 46,035
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 645 $ 2,088
Oil and natural gas sales 110 280
Current portion of long-term debt -- --
Other 309 403
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Total Current Liabilities 1,064 2,771
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Long-term Debt 15,363 7,500
Deferred Tax Liability 91 452
Stockholders' Equity:
Common Stock, par value $.01 par share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding 55 55
Warrants outstanding 140 --
Paid-in capital 46,134 46,134
Retained earnings (deficit) (11,521) (10,877)
-------------- --------------
Total Stockholders' Equity 34,808 35,312
-------------- --------------
Total Liabilities and Stockholders' Equity $ 51,326 $ 46,035
============== ==============
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC
Consolidated Statements of Operations
(in thousands, except per share data)
(Unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- ------------------------------
1999 1998 1999 1998
---------------- -------------- --------------- --------------
Operating Revenues:
Oil sales $ 1,139 $ 728 $ 2,359 $ 2,221
Natural gas sales 310 349 936 949
Other 62 49 202 122
---------------- -------------- --------------- --------------
Total operating revenues 1,511 1,126 3,497 3,292
Operating Expenses:
Lease operating 831 443 1,782 1,480
Production taxes 120 53 220 154
Exploration costs 21 - 21 -
Depletion, depreciation and amortization 423 482 1,248 1,373
General and administrative 626 525 1,530 1,535
---------------- -------------- --------------- --------------
Total operating expenses 2,021 1,503 4,801 4,542
---------------- -------------- --------------- --------------
Operating loss (510) (377) (1,304) (1,250)
Other Income:
Interest income (expense), net (190) 50 (387) 393
Gain on sales of property and equipment, net (17) 3 860 59
---------------- -------------- --------------- --------------
Net loss before income taxes (717) (324) (831) (798)
Income Tax Benefit:
Deferred (270) (97) (299) (282)
Current - - - -
---------------- -------------- --------------- --------------
Total income tax benefit (270) (97) (299) (282)
---------------- -------------- --------------- --------------
Net loss before change in accounting principle (447) (227) (532) (516)
Change in accounting principle (net of income tax effect) - - (111) -
---------------- -------------- --------------- --------------
Net loss $ (447) $ (227) $ (643) $ (516)
================ ============== =============== ==============
Net loss per common share before change in accounting
principle, basic and diluted $ (0.08) $ (0.04) $ (0.10) $ (0.09)
Net loss per common share from change in accounting principle $ - $ - $ (0.02) $ -
---------------- -------------- --------------- --------------
Net loss per common share, basic and diluted $ (0.08) $ (0.04) $ (0.12) $ (0.09)
================ ============== =============== ==============
Weighted average common shares outstanding 5,458,333 5,458,333 5,458,333 5,458,333
================ ============== =============== ==============
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC
Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------
1999 1998
-------------- ------------
Operating Activities:
Net loss before income taxes $ (643) $ (516)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization 1,263 1,373
Gain on sales of property and equipment, net (859) (59)
Exploration costs 21 --
Expense of capitalized organization costs
due to change in accounting principle 173 --
Write-off of officer note receivable 176 --
Deferred taxes (361) (282)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable 359 (1,226)
Increase in inventory (183) (507)
(Increase) decrease in prepaid expenses 104 (167)
Decrease in accounts payable and
accrued liabilities (1,707) (417)
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Net cash used in operating activities: (1,657) (1,801)
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Investing Activities:
Proceeds from sales of property and equipment 1,503 88
Additions to oil and natural gas properties, including
exploration costs (9,005) (13,583)
Additions to pipelines, natural gas gathering and other (561) (1,435)
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Net cash used in investing activities (8,063) (14,930)
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Financing Activities:
Proceeds from issuance of, and draws on, notes payable 8,000 2,000
Payments on notes payable -- (37)
Payments for financing costs (14) (46)
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Net cash provided by financing activities 7,986 1,917
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Net decrease in cash and cash equivalents (1,734) (14,814)
Cash and Cash Equivalents, beginning of period 2,008 16,679
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Cash and Cash Equivalents, end of period $ 274 $ 1,865
========== ==========
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC.
Notes to Consolidated Financial Statements
(1) ORGANIZATION AND BASIS OF PRESENTATION
Petroglyph Energy, Inc. ("Petroglyph" or the "Company") was incorporated in
Delaware in April 1997 for the purpose of consolidating and continuing the
activities previously conducted by Petroglyph Gas Partners, L.P. ("PGP" or the
"Partnership"). PGP was a Delaware limited partnership, which was organized on
April 15, 1993 to acquire, explore for, produce and sell oil, natural gas and
related hydrocarbons. The sole general partner of PGP was Petroglyph Energy,
Inc., a Kansas corporation ("PEI"). Petroglyph Gas Partners II, L.P. ("PGP II")
was a Delaware limited partnership, which was organized on April 15, 1995 to
acquire, explore for, produce and sell oil, natural gas and related
hydrocarbons. The sole general partner of PGP II was PEI (1% interest) and the
sole limited partner was PGP (99% interest). Pursuant to the terms of an
Exchange Agreement dated August 22, 1997 (the "Exchange Agreement"), the Company
acquired all of the outstanding partnership interests of the Partnership and all
of the stock of PEI in exchange for shares of Common Stock of the Company (the
"Conversion"). The Conversion and other transactions contemplated by the
Exchange Agreement were consummated on October 24, 1997, immediately prior to
the closing of the initial public offering of the Company's Common Stock (the
"Offering"). The Conversion was accounted for as a transfer of assets and
liabilities between affiliates under common control in October 1997 and resulted
in no change in carrying values of these assets and liabilities.
On June 30, 1998, all properties owned by PGP, PGP II, and PEI were
transferred into the Company and the three entities (PGP, PGP II, and PEI) were
dissolved.
The accompanying consolidated financial statements of Petroglyph include
the assets, liabilities and results of operations of its wholly owned
subsidiary, Petroglyph Operating Company, Inc. ("POCI"). POCI is a subchapter C
corporation. POCI is the designated operator of all wells for which the Company
has acquired operating rights. Accordingly, all producing overhead and
supervision fees were charged to the joint accounts by POCI. All material
intercompany transactions and balances have been eliminated in the preparation
of the accompanying consolidated financial statements.
The Company's operations are primarily focused in the Uinta Basin of Utah
and the Raton Basin of Colorado with additional operations in DeWitt and
Victoria Counties in South Texas.
The accompanying consolidated financial statements of Petroglyph, with the
exception of the consolidated balance sheet at December 31, 1998, have not been
audited by independent public accountants. In the opinion of the Company's
management, the accompanying consolidated financial statements reflect all
adjustments necessary to present fairly the financial position at September 30,
1999 and the related results of operations for the three month and nine-month
periods ended September 30, 1999 and 1998. All such adjustments are of a normal
recurring nature. These interim results are not necessarily indicative of
results for a full year.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules and
regulations of the Securities and Exchange Commission.
(2) SIGNIFICANT EVENTS
A. CHANGE OF CONTROL
On August 18, 1999, III Exploration Company, an Idaho corporation ("III"),
completed the purchase (the "Purchase") from Robert A. Christensen, a director
and executive officer of the Company, David R. Albin, a director of the Company,
Kenneth A. Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster,
Bruce B. Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural
Gas Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of common stock, $.01 par value of the Company.
According to the Schedule 13D filed with the Securities and Exchange
Commission by III on August 30, 1999, III is controlled by Intermountain
Industries, Inc., an Idaho corporation ("Intermountain"). The stock purchase was
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effected through a privately negotiated sale between the Sellers and
Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999 (collectively, the "Agreement"), with a purchase price of $3.00
per share. The source of funds for the Purchase came from working capital of
Intermountain. As a result of the Purchase, Intermountain, through its ownership
of III, now owns approximately 50.4% of the outstanding Common Stock of the
Company.
Intermountain, a closely-held holding company exempt from the provisions of
the Public Utility Holding Company Act of 1935, except for Section 9(a)(2),
through its subsidiaries operates the largest natural gas distribution utility
in Idaho, the largest end-use natural gas marketing business in the northwest
United States and has producing oil and gas properties in the Rocky Mountain
region, including the Uinta Basin of Utah.
Related to the sale, David Albin, Kenneth Hersh and Robert Christensen
tendered their resignations from the Company's Board of Directors. Mr.
Christensen also resigned as an executive officer of the Company, but will
remain as an engineering advisor. After discussing the resignations with
Intermountain, the remaining members of the Company's Board of Directors
nominated William C. Glynn, Richard Hokin and Eugene C. Thomas, who are also
members of Intermountain's Board of Directors, to fill the vacancies created on
the Board of Directors by the resignations.
B. ANTELOPE CREEK ACQUISITION
During August 1999, Petroglyph Energy, Inc. acquired the remaining 50%
working interest in the Antelope Creek Field in the Uinta Basin of Utah (the
"Antelope Creek Property") from its non-operated working interest partner,
Williams Production Rocky Mountain Company ("Williams"), for a purchase price of
$6.9 million (the "Antelope Creek Acquisition"). The Antelope Creek Acquisition,
which was effective August 1, 1999, gives the Company a 100% working interest in
the Antelope Creek Property.
(3) LONG-TERM DEBT
Effective September 30, 1998, the Company entered into a credit agreement
with the Chase Manhattan Bank ("Chase") (the "Credit Agreement"). The Credit
Agreement established a credit facility for the Company of up to $50.0 million
with a two-year revolving line and a borrowing base to be redetermined
quarterly. The revolving credit facility expires on September 30, 2000, at which
time all outstanding balances will convert to a term loan expiring on September
30, 2003. Interest on outstanding borrowings is calculated, at the Company's
option, at either Chase's prime rate or the London Interbank Offer Rate plus a
margin determined by the amount outstanding under the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition, the
borrowing base was increased to $11.0 million and the quarterly redetermination
scheduled for September 30, 1999 was waived. The next redetermination is
scheduled to occur on or before December 31, 1999.
In order to finance the Antelope Creek Acquisition, the Company and Chase
entered into Amendment No. 1 to the Credit Agreement, dated as of August 20,
1999, pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III. The Notes required the Company to deliver to III
a stock purchase warrant to acquire 150,000 shares of Common Stock of the
Company at an exercise price of $3.00 per share and the ability for III to
obtain additional stock purchase warrants over the life of the Notes. The number
of future stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The maximum
number of shares of Common Stock issuable under the stock purchase warrants for
any given period is limited to 250,000 shares in any one year, 400,000 over the
first three years and 750,000 over the five-year life of the notes. The Company
may redeem the Notes at par without penalty at any time. Upon redemption of the
Notes, any remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining purchase
price of the Antelope Creek Acquisition and for working capital needs.
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(4) COMMITMENTS
The Company has hedged a portion of its future production with crude oil
collars based on a floor price and a ceiling price indexed to the NYMEX light
crude future settlement price. Oil hedge contracts currently in place are:
DURATION VOLUME FLOOR CEILING
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January 1999 - December 1999 13,250 Bbl/month $17.00 $22.00
January 2000 - December 2000 12,000 Bbl/month $17.00 $20.00
AVERAGE PRICE
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September 1999 - December 1999 12,000 Bbl/month $21.00
January 2000 - June 2000 12,000 Bbl/month $20.05
The Company has contracted for the sale of its natural gas production and
taken hedge positions to effect the following volumes and prices:
DURATION VOLUME AVERAGE PRICE
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Utah: October 1999 - September 2000 1,500 MMBtu/day $2.01 MMBtu ($2.33 MCF)
Texas: August 1999 - March 2000 1,000 MMBtu/day $2.2275 MMBtu ($2.29 MCF)
April 2000 - March 2001 1,000 MMBtu/day $2.2425 MMBtu ($2.31 MCF)
The Company uses price hedging arrangements and fixed price natural gas
sales contracts as described above to reduce price risk on a portion of its oil
and natural gas production.
In September 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for fiscal years beginning after June 15, 2000. With its
current hedge contracts, management believes SFAS No. 133 will have no impact on
the financial statements of the Company.
During July 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately
37 miles of 10-inch steel pipeline from near Trinidad, Colorado to the Company's
Raton Basin coalbed methane development area approximately 6 miles southwest of
Walsenburg, Colorado. The pipeline was placed in service in January 1999 with a
delivery capacity of approximately 50 MMcf per day and would provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company has committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity beginning February 1, 1999
and ending January 31, 2009. The commitment begins at a minimum volume of
2,000 Mcf per day and increases after each three-month period by 1,000 Mcf per
day, with a maximum commitment of 10,000 Mcf per day. At the end of the first
two-year period the Company has the option to: 1) continue the agreement with a
minimum volume of 16,000 Mcf per day, 2) increase the minimum volume to
32,000 Mcf per day, or 3) eliminate the commitment. The cost of eliminating the
commitment is the cost of the pipeline ($6.4 million) less a credit applied for
the Company's Raton Basin commercial gas production up to 16,000 Mcf per day.
This cost could be applied as a credit to transportation elsewhere on CIG's
system. The Company can reduce the minimum monthly commitment by selling its
available pipeline capacity at market rates. Net commitment fees paid to CIG
totaling $82,000 and $151,000 for the three and nine-month periods ending
September 30, 1999, respectively, are reflected as lease operating expense in
the Company's consolidated statements of operations.
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ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. The
Company's strategy is to increase its reserves, production and cash flow through
(i) the development of its drillsite inventory, (ii) the exploitation of its
existing reserve base, (iii) the control of operations of its core properties,
(iv) the acquisition of additional property interests, and (v) the development
of a strong financial position that affords the Company the financial
flexibility to execute its business strategy.
OPERATING DATA
The following table sets forth certain operating data of the Company for
the periods presented.
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
Production Data:
Oil (Bbls)........................ 64,838 67,131 158,329 201,644
Natural gas (Mcf)................. 160,476 180,936 489,480 473,604
Total (BOE)....................... 91,584 97,287 239,909 280,578
Average Daily Production:
Oil (Bbls)........................ 705 730 580 739
Natural gas (Mcf)................. 1,744 1,967 1,793 1,735
Total (BOE)....................... 995 1,057 879 1,028
Average Sales Price per Unit (1):
Oil (per Bbl) (2)................. $ 17.56 $ 10.84 $ 14.90 $ 11.01
Natural gas (per Mcf)............. $ 1.94 $ 1.93 $ 1.91 $ 2.00
Costs Per BOE:
Lease operating expenses.......... $ 9.08 $ 4.56 $ 7.43 $ 5.27
Production and property taxes..... $ 1.31 $ 0.55 $ 0.92 $ 0.55
Depletion, depreciation and
amortization................... $ 4.62 $ 4.95 $ 5.20 $ 4.89
General and administrative........ $ 6.83 $ 5.39 $ 6.38 $ 5.47
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(1) Before deduction of production taxes.
(2) Excluding the effects of crude oil hedging transactions, the weighted
average sales price per Bbl of oil was $18.45 and $9.25 for the three
months, and $14.27 and $9.86 for the nine months ended September 30, 1999
and 1998, respectively.
Bbl - Barrel
Mcf - Thousand cubic feet
BOE - Barrels of oil equivalent (six Mcf equal one Bbl)
The Company uses the successful efforts method of accounting for its oil
and natural gas activities. Costs to acquire mineral interests in oil and
natural gas properties, to drill and equip exploratory wells that result in
proved reserves, and to drill and equip development wells are capitalized. Costs
to drill exploratory wells that do not result in proved reserves, costs of
geological, geophysical and seismic testing, and costs of carrying and retaining
properties that do not contain proved reserves are expensed. Costs of
significant nonproducing properties, wells in the process of being drilled and
development projects are excluded from depletion until such time as the related
project is developed and proved reserves are established or impairment is
determined.
One gross (.5 net) well was drilled as a dry hole in South Texas and no
wells were completed during the three months ended September 30, 1999. This
compares with 12 gross and net wells drilled and 12 gross (9.5 net) wells
completed during the three months ended September 30, 1998.
RESULTS OF OPERATIONS
Three Months Ended September 30, 1999 Compared to Three Months Ended
September 30, 1998
OPERATING REVENUES
Third quarter 1999 operating revenues increased 34% to $1,511,000 compared
to $1,126,000 for the same period in 1998. Oil prices during the third quarter
1999 increased $6.72 (62%) to $17.56 per barrel compared to the third quarter
1998. This price includes a third quarter hedge loss of $0.89 per barrel in 1999
compared to $1.59 hedge gain in 1998. The gas price was essentially flat between
periods at $1.94 and $1.93 per Mcf for 1999 and 1998, respectively. However, the
1999 third quarter price includes $0.35 per Mcf hedge loss. There was no gas
hedge effect for the 1998 period.
Oil sales volumes declined 3% to 64,800 Bbls and gas volumes fell 11% to
160,500 Mcf in the third quarter of 1999 compared to the 1998 period. Third
quarter 1999 sales include volumes totaling 24,393 Bbls and 27,023 Mcf
attributable to the purchase of 50% of the Antelope Creek Field. Excluding the
Antelope Creek Acquisition, oil sales volumes declined 40% from the prior year
due to suspension of development in the Antelope Creek Field mid-year 1998
coupled with the conversion of six wells from producers to injectors between
periods.
OPERATING EXPENSES
Lease operating expense for the third quarter 1999 of $831,000 was $388,000
(87%) greater than the comparable period in 1998. The 1999 figure includes
$106,000 in compressor rentals attributable to the sale of the Texas and
Antelope Creek compressors, $82,000 in CIG commitment fees, and $272,000 in
lease operating expense attributable to the Antelope Creek Acquisition. None of
these costs were present in the third quarter of 1998. As a result of these
increases and the production declines noted above, average LOE rose $4.52 to
$9.08 per barrel.
Third quarter 1999 general and administrative expense increased 19% to
$626,000 compared to the comparable quarter in 1998. This amount included a
one-time, non-cash charge of $176,000 associated with forgiveness of debt owed
to the Company by a former executive officer. In exchange for the debt
forgiveness, the officer relinquished his rights under a severance agreement,
which had a potential cash value of $250,000. Absent this charge, general and
administrative expense decreased $75,000 to $450,000 compared to $525,000 for
the third quarter of 1998 as a result of cost reduction measures implemented in
the first quarter of 1999.
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OTHER INCOME (EXPENSE)
Other operating revenues increased to $62,000 during the third quarter 1999
from $49,000 for the same period in 1998. Gas transportation income from Texas
wells is the principal reason for this increase.
Net interest expense for the third quarter 1999 was $190,000 compared to
net interest income of $50,000 for third quarter 1998. This represents the
decline in invested cash after the Offering to a net debt position at the end of
1998.
RESULTS OF OPERATIONS
Nine Months Ended September 30, 1999 Compared to Nine Months Ended
September 30, 1998
OPERATING REVENUE
Operating revenues of $3,497,000 for the first nine months of 1999 were 6%
greater than revenues for the same period in 1998. The average year to date oil
price for 1999 was $14.90 per barrel, inclusive of $0.63 per barrel hedge gain.
This compares to $11.01 per barrel for the 1998 period, including $1.16 per
barrel hedge gain. Not including hedging adjustments, the Company's average oil
price rose 45% between periods. The average realized gas price for the first
nine months of 1999 was $1.91 per Mcf after subtracting $0.14 per Mcf hedge
loss. For the same period in 1998 the average gas price was $2.00 per Mcf with
no hedge adjustments.
Oil sales volumes fell 21% to 158,300 barrels for the first nine months of
1999 compared to 201,600 barrels for the same period in 1998. Excluding the
Antelope Creek Acquisition, oil sales volumes declined 34% from the prior year
due to suspension of development in the Antelope Creek Field mid-year 1998
coupled with the conversion of six wells from producers to injectors since the
end of the third quarter 1998. A similar decline in Antelope Creek gas
production was mitigated by gas sales from wells drilled in the fourth quarter
of 1998 and the first quarter of 1999 in the Helen Gohlke Field in Texas.
Company gas sales for the first nine months of 1999 of 489,500 Mcf were 3%
greater than gas sales for the same period in 1998.
OPERATING EXPENSES
Lease operating expenses increased 20% to $1,782,000 for the first nine
months of 1999 compared to $1,480,000 for the comparable period in 1998. LOE for
1999 includes $151,000 in CIG commitment fees, $226,000 in compressor rentals,
and $272,000 in lease operating expense attributable to the Antelope Creek
Acquisition. None of these costs were present in the first nine months of 1998.
Absent these charges, which are not comparable between periods, LOE decreased
$347,000, or 23%, between the first nine months of 1999 and the same period in
1998.
Because of the operating expense increases and production declines noted
above, LOE per barrel rose $2.16 to $7.43 per BOE for the first nine months of
1999 compared to the same period in 1998.
Year to date general and administrative expense for 1999 of $1,530,000 was
essentially flat to the comparable period in 1998. However, the 1999 figure
included a one-time, non-cash charge of $176,000 associated with forgiveness of
debt owed to the Company by a former executive officer. In exchange for the debt
forgiveness, the officer relinquished his rights under a severance agreement,
which had a potential cash value of $250,000. Cost reductions begun in the
fourth quarter of 1998 and completed in 1999 have resulted in decreased general
and administrative expense. The 1999 amounts include $82,000 in severance costs
incurred during the first half of year. Not including these unusual items,
general and administrative expense decreased $253,000, or 17%, between the
nine-month periods of 1999 and 1998.
OTHER INCOME (EXPENSES)
Other operating income, principally natural gas transportation revenues,
rose 66% to $202,000 for the first nine months of 1999 compared to the same
period in 1998. This increase is due to gas transported from the new Texas wells
mentioned above.
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Net interest expense for the first nine months of 1999 was $387,000,
compared to net interest income of $393,300 for the same period in 1998. This
represents the decline in invested cash after the Offering to a net debt
position at the end of 1998.
Gain on sale of property was $860,000 for the first nine months of 1999
compared to $59,000 for the comparable 1998 period due to an increase in asset
sales activity between periods.
CHANGE IN ACCOUNTING PRINCIPLE
The Company is required to comply with Statement of Position ("SOP") 98-5,
Reporting on the Costs of Start-Up Activities, for fiscal years beginning after
December 15, 1998. This SOP requires start-up and organizational costs be
expensed as incurred. It also requires start-up and organizational costs
previously capitalized be expensed and that the resulting one-time expense be
accounted for as a change in accounting principle. Accordingly, the Company has
shown as a change in accounting principle an $111,000 expense, which represents
net capitalized organizational costs of $173,000 and the associated income tax
benefit of $62,000.
SIGNIFICANT EVENTS
CHANGE OF CONTROL
On August 18, 1999, III Exploration Company, an Idaho corporation ("III"),
completed the purchase from Robert A. Christensen, a director and executive
officer of the Company, David R. Albin, a director of the Company, Kenneth A.
Hersh, a director of the Company, R. Gamble Baldwin, John S. Foster, Bruce B.
Selkirk, III, Albin Income Trust, Natural Gas Partners, L.P., Natural Gas
Partners II, L.P. and Natural Gas Partners III, L.P. (collectively, the
"Sellers") of 2,753,392 shares of common stock, $.01 par value of the Company.
According to the Schedule 13D filed with the Securities and Exchange
Commission by III on August 30, 1999, III is controlled by Intermountain
Industries, Inc., an Idaho corporation ("Intermountain"). The stock purchase was
effected through a privately negotiated sale between the Sellers and
Intermountain, pursuant to Letter Agreements dated as of August 13, 1999 and
July 29, 1999 (collectively, the "Agreement"), with a purchase price of $3.00
per share. The source of funds for the Purchase came from working capital of
Intermountain. As a result of this purchase, Intermountain, through its
ownership of III, now owns approximately 50.4% of the outstanding Common Stock
of the Company.
CHANGES IN BOARD OF DIRECTORS
Related to the sale, David Albin, Kenneth Hersh and Robert Christensen
tendered their resignations from the Company's Board of Directors. Mr.
Christensen also resigned as an executive officer of the Company, but will
remain as an engineering advisor. After discussing the resignations with
Intermountain, the remaining members of the Company's Board of Directors
nominated William C. Glynn, Richard Hokin and Eugene C. Thomas, who are also
members of Intermountain's Board of Directors, to fill the vacancies created on
the Board of Directors by the resignations.
Since 1982, Richard Hokin, 59, has been a member of the board of
Intermountain and has served as Chairman of it and of each of its subsidiaries
since 1984. Mr. Hokin has been a director of Displaytech, Inc., a developer and
manufacturer of microelectronic displays, since 1995. He has held the position
of Managing Partner of Century Partners, an investment partnership, since 1996.
From 1984 through 1987, Mr. Hokin served as a Director of the Pacific Coast Gas
Association.
William C. Glynn, 54, has served as President of Intermountain and each of
its subsidiaries from 1987 to the present. Mr. Glynn is a member of and has
served as Chairman of the Board of Directors of the Pacific Coast Gas
Association. He is also a member of the Board of Directors of the American Gas
Association.
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Eugene C. Thomas, 68, has served on the Board of Directors of Intermountain
and of each of its subsidiaries since 1984. Mr. Thomas is a partner of Moffatt,
Thomas, Barrett, Rock & Fields, Chtd. and he has acted as general counsel to
Intermountain since 1978. Mr. Thomas is a member of the American Bar Association
and served as its President for 1986-87.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities was $1,657,000 for the nine months ended
September 30, 1999. Current liabilities were reduced $1,707,000. Thus far in
1999 the Company has realized cash of $1,503,000 from the sale of Texas and
Antelope Creek Field compression facilities, surplus vehicles and inventory, and
non-core properties.
The Company expects to generate cash from operations, asset sales,
increased availability under its Credit Agreement, if any, and other capital
sources. The Company believes that a combination of these sources and current
cash on hand will be adequate to support its budgeted working capital and
discretionary capital expenditure programs for at least the next 12 months. The
Company is actively pursuing capital to fund its drilling, development, and
acquisition plans and, if successful, intends to proceed with the further
development of its properties.
CAPITAL EXPENDITURES
During the first nine months of 1999, the Company converted 2 gross (1 net)
producing wells in the Antelope Creek Field to water injectors and began
returning shut-in wells to producing status as a result of oil price increases.
Management believes oil volume declines in the Antelope Creek Field have been
arrested with the recent well remediation program and expects Antelope Creek
Field waterflood response to continue to improve as water injection continues.
Depending on available capital the Company intends to spend up to $6.0 million
converting as many as 34 wells to injectors and drilling up to 8 new wells
during the remainder of 1999 and all of 2000 to increase the field-wide water
injection pattern and enhance production.
In the first half of 1999, the Company completed its water disposal and gas
gathering system infrastructure in the Raton Basin. During the third quarter of
1999, the Company increased the daily water withdrawal rate from the 17 pilot
area wells to approximately 37,000 barrels per day as a result of obtaining a
surface discharge permit from the State of Colorado. The permit provides for a
total discharge rate of up to 240,000 barrels per day, and the Company can
further increase pilot area withdrawal rates by increasing water pump capacity
at individual wells. By the end of the third quarter of 1999, total water
removed from the pilot area wells was 8.2 million barrels. Measured reservoir
pressures had been reduced by approximately 85 psi. The Company has estimated
that commercial gas production will require a reservoir pressure reduction of
approximately 200 psi. All coalbed methane wells in the pilot area are currently
producing some volumes of natural gas, and two wells are now supplying enough
gas to fuel the engines that power their water pumping systems. Currently the
field is producing a total of approximately 100 Mcf per day. While not
commercial in quantity, the gas volumes are being recovered and utilized to
offset fuel costs. Reservoir pressure testing is currently in process which
management believes will allow the Company to understand how much longer it may
take to reduce the pilot area reservoir pressure to the targeted 200 psi
pressure drop and achieve commercial volumes of gas production.
During the first nine months of 1999, the Company drilled 4 gross (2.5 net)
wells and completed 2 gross (1 net) wells in the Helen Gohlke Field in Victoria
and Dewitt Counties, Texas. One gross and net well was a dry hole and was
accrued as exploration expense in 1998; one gross (.5 net) well was expensed as
a dry hole in 1999. This property, which is non-core to the Company's reserve
development strategy, is currently offered for sale.
On August 20, 1999, the Company acquired the remaining 50% working interest
in the Antelope Creek Field in the Uinta Basin of Utah from its non-operated
working interest partner, Williams Production Rocky Mountain Company, for a
purchase price of $6.9 million. This purchase, which was effective August 1,
1999, gives the Company a 100% working interest in the Antelope Creek Property.
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FINANCING
Effective September 30, 1998, the Company entered into the Credit Agreement
with Chase. The Credit Agreement established a credit facility for the Company
of up to $50.0 million with a two-year revolving line and a borrowing base to be
redetermined quarterly. The revolving credit facility expires on September 30,
2000, at which time all outstanding balances will convert to a term loan
expiring on September 30, 2003. Interest on outstanding borrowings is
calculated, at the Company's option, at either Chase's prime rate or the London
Interbank Offer Rate plus a margin determined by the amount outstanding under
the facility.
During August 1999, in conjunction with the Antelope Creek Acquisition, the
borrowing base was increased to $11.0 million and the quarterly redetermination
scheduled for September 30, 1999 was waived. The next redetermination is
scheduled to occur on or before December 31, 1999.
In order to finance the Antelope Creek Acquisition, the Company and Chase
entered into Amendment No. 1 to the Credit Agreement dated as of August 20, 1999
pursuant to which the Company borrowed an additional $2.5 million.
Additionally, the Company sold $5 million of 8% senior subordinated notes
due 2004 (the "Notes") to III. The Notes required the Company to deliver to III
a stock purchase warrant to acquire 150,000 shares of Common Stock of the
Company at an exercise price of $3.00 per share and the ability for III to
obtain additional stock purchase warrants over the life of the Notes. The number
of future stock purchase warrants will be based on the future stock price
performance and the amount and duration of the Notes outstanding. The maximum
number of shares of Common Stock issuable under the stock purchase warrants for
any given period is limited to 250,000 shares in any one year, 400,000 over the
first three years and 750,000 over the five-year life of the notes. The Company
may redeem the Notes at par without penalty at any time. Upon redemption of the
Notes, any remaining unissued and unearned stock purchase warrants will expire.
The Company utilized proceeds from the Notes to finance the remaining purchase
price of the Antelope Creek Acquisition and for working capital needs.
YEAR 2000 ISSUES
The Company is aware of the potential for disruption of its business as a
result of the failure of computer systems which will not properly recognize "00"
in date sensitive information when the year changes to 2000. Such failures are
collectively characterized as the "Year 2000 issue".
Management of the Company has formed a Year 2000 Team (the "Team"),
consisting of managers and knowledgeable employees, to assess and identify the
potential risks of the Year 2000 issue on the Company and to take the necessary
actions to nullify, as much as possible, the impact of the Year 2000 issue. The
Team has developed a program focusing on the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and governmental
entities
The information technology and systems of the Company are believed to be
Year 2000 compliant. Software upgrades and service releases supplied by vendors
have been installed. The processing ability of hardware and computer equipment
with embedded technology has been successfully tested. Most of these upgrades
were system replacements conducted in 1996 and 1997 to improve business
efficiencies and functionality and were not undertaken solely to address the
Year 2000 issues. As such, management believes the Year 2000 issues with respect
to the Company's information technology and systems will not have a significant
effect on the Company's financial position or operations.
The process controls and embedded technology area is essentially complete.
Field level processors, meters and equipment utilized by the Company are not
expected to contain embedded technology such as microprocessors. However, the
Company continues to conduct internal evaluations and hold discussions with
suppliers to ensure appropriate measures are taken to minimize the impact to
operations caused by any unidentified company or third party Year 2000 issues.
The Company also relies on non-information technology systems such as
telephones, facsimile machines, security
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systems and other equipment which may have embedded technology such as
microprocessors, which may or may not be Year 2000 compliant. Management
believes any such disruption is not likely to have a significant effect on the
Company's financial position or operations.
Formal communications have been initiated with vendors, suppliers,
customers and others with whom the Company has significant business
relationships. Approximately 85% of correspondents responded. The Team continues
to evaluate responses and make additional inquiries as needed. The Company is
not currently aware of any third party issues that would cause a significant
business disruption.
The total cost of the Company's Year 2000 program is not expected to be
material to the Company's financial position. The Company anticipates spending
less than $10,000 during the remainder of 1999 for Year 2000 related
modifications and testing.
The Company continues to develop its contingency plans in the unlikely
event that portions of its Year 2000 program are inadequate. The Company
believes that the most likely worst-case Year 2000 scenarios are as follows: (i)
unanticipated Year 2000 induced failures in information systems could cause a
reliance on manual contingency procedures and significantly reduce efficiencies
in the performance of certain normal business activities; and (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
developed to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At September 30, 1999, the Company currently has oil and gas hedge
contracts in place further described in Note 4 (Commitments) to Consolidated
Financial Statements. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company uses hedging
contracts to manage its price risk and limit exposure to short-term fluctuations
in commodity prices. However, should NYMEX oil prices rise above the ceiling
prices in effect for the periods mentioned above, the Company would not receive
the marginal benefit of oil prices in excess of the ceiling prices.
Additionally, the Company is subject to interest rate risk, as $10.5
million owed at September 30, 1999 under the Company's revolving credit facility
accrues interest at floating rates tied to LIBOR. The Company's current average
rate is approximately 7.96%, locked in for 90-day terms.
The Company performed a sensitivity analysis to assess the potential effect
of commodity price risk and interest rate risk and determined that the effect,
if any, of reasonably possible near-term changes in NYMEX oil prices or interest
rates on the Company's financial position, results of operations and cash flow
should not be material.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Financial Data Schedule
(b) Reports Submitted on Form 8-K:
1) Form 8-K, date of report August 18, 1999, reported under
Item 1 and 2, the (i) Change of Control of Registrant and
(ii) the Acquisition of Oil and Gas Properties.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PETROGLYPH ENERGY, INC.
By: /s/ Robert C. Murdock
-------------------------------------
Robert C. Murdock
President & Chief Executive Officer
By: /s/ Tim A. Lucas
------------------------------------
Tim A. Lucas
Vice President & Chief Financial Officer
Date: November 15, 1999
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INDEX TO EXHIBIT
Exhibit
Number Description
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27 Financial Data Schedule