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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 March 31, 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 April 30, 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
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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 March 31, 1999 and December 31, 1998........................... 2
Consolidated Statements of Operations for the Three Months Ended
March 31, 1999 and 1998................................................................... 3
Consolidated Statements of Cash Flows for the Three Months Ended
March 31, 1999 and 1998................................................................... 4
Notes to Consolidated Financial Statements....................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 7
Item 3.Quantitative and Qualitative Disclosures About Market Risk.............................................. 11
PART II -- OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K....................................................................... 12
Signatures....................................................................................... 13
</TABLE>
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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
recovery programs, the availability, proximity and capacity of refineries,
pipelines and processing facilities, shortages or delays in the delivery of
equipment and services, land issues, federal, 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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ITEM 1. FINANCIAL STATEMENTS
PETROGLYPH ENERGY, INC
Consolidated Balance Sheets
(in thousands)
<TABLE>
<CAPTION>
ASSETS MARCH 31, DECEMBER 31,
1999 1998
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(Unaudited)
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 532 $ 2,008
Accounts receivable:
Oil and natural gas sales 272 265
Joint interest billing 410 835
Other 79 133
Inventory 1,411 1,234
Prepaid expenses 203 247
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Total Current Assets 2,907 4,722
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Property and Equipment, successful efforts method at cost:
Proved properties 32,878 32,191
Unproved properties 10,540 10,072
Pipelines, gas gathering and other 10,414 10,025
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53,832 52,288
Less: Accumulated depletion, depreciation, and amortization (12,032) (11,590)
------------ ------------
Property and equipment, net 41,800 40,698
Other assets, net of accumulated amortization 447 615
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Total Assets $ 45,154 $ 46,035
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LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 1,022 $ 2,088
Oil and natural gas sales 273 280
Current portion of long-term debt 500 --
Other 283 403
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Total Current Liabilities 2,078 2,771
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Long-term Debt 8,000 7,500
Deferred Tax Liability 204 452
Stockholders' Equity:
Common Stock, par value $.01 par share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding 55 55
Paid-in capital 46,134 46,134
Retained earnings (deficit) (11,317) (10,877)
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Total Stockholders' Equity 34,872 35,312
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Total Liabilities and Stockholders' Equity $ 45,154 $ 46,035
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</TABLE>
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)
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THREE MONTHS ENDED
MARCH 31,
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1999 1998
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Operating Revenues:
Oil sales $ 616 $ 793
Natural gas sales 320 313
Other 79 35
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Total operating revenues 1,015 1,141
Operating Expenses:
Lease operating 501 595
Production taxes 36 60
Exploration costs -- --
Depletion, depreciation and amortization 448 450
General and administrative 475 495
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Total operating expenses 1,460 1,600
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Operating loss (445) (459)
Other Income:
Interest income (expense), net (69) 204
Gain on sales of property and equipment, net -- 28
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Net loss before income taxes (514) (227)
Income Tax Benefit:
Deferred (185) (88)
Current -- --
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Total income tax benefit (185) (88)
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Net loss before change in accounting principle (329) (139)
Change in accounting principle (net of tax) (111) --
------------ ------------
Net loss $ (440) $ (139)
============ ============
Net loss per common share before change in accounting principle
basic and diluted $ (0.06) $ (0.03)
Net loss per common share from change in accounting principle $ (0.02) $ --
------------ ------------
Net loss per common share, basic and diluted $ (0.08) $ (0.03)
============ ============
Weighted average common shares outstanding 5,458,333 5,458,333
============ ============
</TABLE>
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PETROGLYPH ENERGY, INC
Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
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THREE MONTHS ENDED
MARCH 31,
------------------------
1999 1998
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Operating Activities:
Net income (loss) before income taxes $ (440) $ (139)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization 448 457
Gain on sales of property and equipment, net -- (28)
Expense of capitalized organization costs
due to change in accounting principle 173 --
Deferred taxes (248) (88)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable 472 (127)
Increase in inventory (177) (541)
(Increase) decrease in prepaid expenses 44 (104)
Decrease in accounts payable and
accrued liabilities (1,193) (1,240)
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Net cash provided by (used in) operating activities: (921) (1,810)
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Investing Activities:
Proceeds from sales of property and equipment -- 33
Additions to oil and natural gas properties, including
exploration costs (1,155) (3,668)
Additions to pipelines, natural gas gathering and other (389) (425)
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Net cash used in investing activities (1,544) (4,060)
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Financing Activities:
Proceeds from issuance of, and draws on, notes payable 1,000 --
Payments for financing costs (11) (10)
---------- ----------
Net cash provided by (used in) financing activities 989 (10)
---------- ----------
Net decrease in cash and cash equivalents (1,476) (5,880)
Cash and Cash Equivalents, beginning of period 2,008 16,679
---------- ----------
Cash and Cash Equivalents, end of period $ 532 $ 10,799
========== ==========
</TABLE>
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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"). See Note 4. 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 March 31, 1999
and the related results of operations for the three-month periods ended March
31, 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) 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 an original borrowing base of $15.0
million 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.
Based on crude oil prices in effect at December 31, 1998, the available
borrowing base was redetermined at March 31, 1999 to $9.0 million. In accordance
with the terms of the Credit Agreement, this borrowing base will be
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reduced to $8.0 million effective June 15, 1999 with the next redetermination
scheduled for June 30, 1999. Accordingly, the Company has reclassified $500,000
of the $8.5 million outstanding under the Credit Agreement as current portion of
long-term debt in anticipation of repayment by June 15, 1999.
(3) COMMITMENTS
The Company had one open oil hedging contract at March 31, 1999, which
is a crude oil collar on 119,250 Bbls of oil with a floor price of $17.00 per
Bbl and a ceiling price of $22.00 per Bbl indexed to the NYMEX light crude
future settlement price. This contract covers 13,250 Bbls of oil per month for
the remainder of the year.
The Company has contracted for the sale of its current Utah natural gas
production for 12 months beginning October 1998. The average realized price over
the life of this contract should be no less than $1.93 per MMBtu or
approximately $2.20 per Mcf using the Company's current conversion factor.
Utah gas production beginning in October 1999 and Texas gas production
beginning in April 1999 are contracted as follows:
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TERM BEGINNING VOLUME AVERAGE PRICE
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12 months October 1999 1500 MMBtu/day $2.010/MMBtu ($2.33/MCF)
12 months April 1999 1000 MMBtu/day $1.923/MMBtu ($2.01/MCF)
</TABLE>
The Company uses price hedging arrangements and fixed price natural gas
sales contracts as described above to reduce price risk on a portion of its oil
and natural gas production.
In September 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities. The Statement 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. The Statement 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.
Statement 133 is effective for fiscal years beginning after September 15, 1999.
With its current hedge contracts, management believes Statement 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 will provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company has committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity beginning February 1, 1999,
and ending January 31, 2009. The commitment begins at a minimum volume of 2,000
Mcf per day and increases 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 to 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.
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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.
<TABLE>
<CAPTION>
Three Months Ended
March 31,
---------------------------
1999 1998
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<S> <C> <C>
Production Data:
Oil (Bbls) ........................................ 50,612 67,463
Natural gas (Mcf) ................................. 171,498 153,492
Total (BOE) ....................................... 79,195 93,045
Average Daily Production:
Oil (Bbls) ........................................ 562 750
Natural gas (Mcf) ................................. 1,906 1,705
Total (BOE) ....................................... 880 1,034
Average Sales Price per Unit (1):
Oil (per Bbl) (2) ................................. $ 12.18 $ 11.75
Natural gas (per Mcf) ............................. $ 1.86 $ 2.04
Costs Per BOE:
Lease operating expenses .......................... $ 6.33 $ 6.40
Production and property taxes ..................... $ 0.45 $ 0.65
Depletion, depreciation, and
amortization ................................... $ 5.66 $ 4.84
General and administrative ........................ $ 6.00 $ 5.32
</TABLE>
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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 $9.09 and $11.17 for the three
months ended March 31, 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.
During the three months ended March 31, 1999, the Company drilled 3
gross (2 net) wells and completed 2 gross (1 net) wells in Texas. One well was a
dry hole and accrued as exploration expense in 1998. This compares with 13 gross
(8.5 net) wells drilled and 12 gross (6 net) wells completed during the three
months ended March 31, 1998.
RESULTS OF OPERATIONS
Three Months Ended March 31, 1999 Compared to Three Months Ended March
31, 1998
OPERATING REVENUES
Oil revenues decreased 22% to $616,000 for the quarter ended March 31,
1999, as compared to $793,000 for the same period in 1998, as approximately 30
wells were taken out of production in the last half of 1998 due to low oil
prices and conversions to water injection status. Oil production declined 25%
between periods to 50,612 Bbls as producing wells were converted to water
injection in support of the Antelope Creek waterflood project.
Natural gas revenues increased by 2% to $320,000 for the quarter ended
March 31, 1999, as compared to $313,000 for the same period in 1998. Gas
production volumes rose 12% to 171,498 Mcf as increased production from the
Company's successful drilling activities in Texas more than offset volume
reductions in Utah. The volume gains were mitigated by a 9% decline in average
gas price to $1.86 per Mcf compared to the first quarter of 1998.
OPERATING EXPENSES
Lease operating expense of $501,000 declined $.07 per BOE and 16%
overall for the quarter ended March 31, 1999 compared to the same 1998 period.
This decline was primarily a result of the reduction in the number of producing
wells mentioned above.
General and administrative expenses decreased to $475,000 for the
quarter ended March 31, 1999, as compared to $495,000 for the quarter ended
March 31, 1998. The first quarter 1999 figure includes severance charges of
$55,000. The Company has undertaken a 40% reduction in personnel since October
1998. It is expected that this reduction in personnel costs and associated
general and administrative expense will become more pronounced in the remainder
of 1999.
OTHER INCOME (EXPENSES)
Interest expense, net of interest income, for the quarter ended March
31, 1999 was $69,000, as compared to $204,000 net interest income in the first
quarter of 1998. This represents the decline in invested funds from the Offering
to a net debt position at the end of 1998.
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CHANGE IN ACCOUNTING PRINCIPLES
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 $111,200, which represents net
capitalized organizational costs of $173,700 and the associated income tax
benefit of $62,500.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities was $921,000 for the quarter ended
March 31, 1999. Accounts receivable decreased $472,000. The Company used cash on
hand and a $1 million draw under the Credit Agreement to reduce accounts payable
and accrued liabilities by $1,193,000 and to finance $1,544,000 of capital
spending. During the first quarter of 1999 a total of 3 gross (2 net) wells were
drilled and 2 gross (1 net) wells were completed and put to production. In
addition, pipeline infrastructure was completed in the Raton Basin.
The Company expects to utilize future cash flow from operations and
asset sales and cash on hand for its working capital requirements, including a
reduction of $500,000 in its outstanding credit facility balance under the
Credit Agreement by June 15, 1999. The Company believes that cash on hand,
proceeds from future asset sales, revenues and future availability under the
Credit Agreement, if any, will be adequate to support its budgeted working
capital and capital expenditure requirements for at least the next 12 months.
The Company anticipates that proceeds from sales of assets will provide
additional capital to fund its debt reduction plans and position the Company to
better take advantage of acquisition opportunities and fund its discretionary
capital budget.
Effective April 1, 1999, the Company completed the sale of its Texas
compression assets as planned for net proceeds of $785,000. This sale will
result in a second quarter gain of approximately $526,000.
CAPITAL EXPENDITURES
During the first quarter 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.
The Company expects Antelope Creek Field waterflood response to continue to
improve as water injection continues. Depending on available cash flow, up to 20
production wells may be converted to injectors during the remainder of 1999 to
increase field-wide water injection response.
In the first quarter of 1999, the Company completed its water disposal
and gas gathering system infrastructure in the Raton Basin. Approximately 30,000
Bbls of water per day are currently produced from the 17 well pilot area. This
pilot project continues to progress according to engineering expectations.
Dewatering of coalbeds through the production of water is a necessary
precondition to economical production of coalbed methane gas. Water levels in
the production wells are dropping and the small volumes of produced gas are
increasing.
During the first quarter of 1999, the Company drilled 3 gross (2 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 accrued as
exploration expense in 1998. This property, which is non-core to the Company's
reserve development strategy, is currently offered for sale.
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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 an original
borrowing base of $15.0 million 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.
Based on crude oil prices in effect at December 31, 1998, the available
borrowing base was redetermined at March 31, 1999 to $9.0 million. In accordance
with the terms of the Credit Agreement, this borrowing base will be reduced to
$8.0 million effective June 15, 1999, with the next redetermination scheduled
for June 30, 1999. Accordingly, the Company has reclassified $500,000 of the
$8.5 million outstanding under the Credit Agreement as current portion of
long-term debt in anticipation of repayment by June 15, 1999.
YEAR 2000 ISSUES
The Company is aware of the date sensitivity issues associated with the
programming code in many existing computer systems and devices with embedded
technology. The "Year 2000" problem concerns the inability of information and
technology-based operating systems to properly recognize and process
date-sensitive information beyond December 31, 1999. The risk is that computer
systems will not properly recognize "00" in date sensitive information when the
year changes to 2000, which could result in system failures or miscalculations,
resulting in the potential disruption of business.
The management of the Company believes it is appropriately addressing
the Company's business and financial risk associated with the Year 2000 issue.
In response to the potential impact of the Year 2000 issue on the Company's
business and operations, the Company has formed a Year 2000 Team (the "Team"),
consisting of members of senior management and the Information Systems Manager.
The Team is developing a program around the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and
governmental entities
The information technology and systems of the Company are believed to
be Year 2000 compliant. Activity in this area included installing and testing
software upgrades and service releases supplied by vendors and testing the
processing ability of hardware and computer equipment with embedded technology.
Most of these upgrades were system replacements conducted in 1996 and 1997 to
improve business efficiencies and functionality and were not undertaken solely
to address 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 in the assessment
phase with approximately 70% in the remediation and verification phases. Field
level processors, meters and equipment utilized by the Company are not expected
to contain embedded technology such as microprocessors. However, the Company
continues to conduct internal evaluations and hold discussions with suppliers to
ensure appropriate measures are taken to minimize the impact to operations
caused by any unidentified company or third party Year 2000 issues. The Company
also relies on non-information technology systems such as telephones, facsimile
machines, security systems and other equipment which may have embedded
technology such as micro processors, which may or may not be Year 2000
compliant. Management believes any such disruption is not likely to have a
significant effect on the Company's financial position or operations. Management
anticipates a complete evaluation of this area to conclude by the end of the
third quarter 1999.
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The third party suppliers, vendors, partners, customers and
governmental entities area is currently in the assessment phase with
approximately 50% in the remediation and verification phase. Formal
communications have been initiated with vendors, suppliers, customers and others
with whom the Company has significant business relationships. The Company
continues to evaluate responses and make additional inquiries as needed. As the
Company is in the process of collecting this information from third parties,
Management cannot currently determine whether third party compliance issues will
materially affect its operations. However, the Company is not currently aware of
any third party issues that would cause a significant business disruption.
Management anticipates a complete evaluation of this area to conclude by the end
of the third quarter 1999.
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 a
total of $20,000 during the remainder of 1999 for Year 2000 related
modifications and testing.
The Company is developing contingency plans in the unlikely event that
portions of its Year 2000 program are inadequate. The Company believes that the
most likely worst-case Year 2000 scenarios are as follows: (i) unanticipated
Year 2000 induced failures in information systems could cause a reliance on
manual contingency procedures and significantly reduce efficiencies in the
performance of certain normal business activities; (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
considered to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company. The Company's contingency plans should be completed by
the end of third quarter 1999.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At March 31, 1999, the Company had 13,250 Bbls per month of 1999 oil
production hedged at a NYMEX floor price of $17.00 per Bbl and a ceiling price
of $22.00 per Bbl. These arrangements could be classified as derivative
commodity instruments subject to commodity price risk. The Company uses hedging
contracts to manage its price risk and limit exposure to short-term fluctuations
in commodity prices. However, should 1999 NYMEX oil prices rise above $22.00 per
Bbl, the Company would not receive the marginal benefit of oil prices in excess
of $22.00 per Bbl.
Additionally, the Company is subject to interest rate risk, as $8.5
million owed at March 23, 1999 under the Company's revolving credit facility
accrues interest a floating rates tied to LIBOR. The Company's current average
rate is approximately 7.25% 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.
-11-
<PAGE> 14
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Financial Data Schedule
(b) Reports Submitted on Form 8-K:
None
-12-
<PAGE> 15
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: May 13, 1999
-13-
<PAGE> 16
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit
Number Description
- ------- -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 532
<SECURITIES> 0
<RECEIVABLES> 761
<ALLOWANCES> 0
<INVENTORY> 1,411
<CURRENT-ASSETS> 2,907
<PP&E> 53,832
<DEPRECIATION> 12,032
<TOTAL-ASSETS> 45,154
<CURRENT-LIABILITIES> 2,078
<BONDS> 8,000
0
0
<COMMON> 55
<OTHER-SE> 34,817
<TOTAL-LIABILITY-AND-EQUITY> 45,154
<SALES> 936
<TOTAL-REVENUES> 1,015
<CGS> 0
<TOTAL-COSTS> 1,460
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 69
<INCOME-PRETAX> (514)
<INCOME-TAX> (185)
<INCOME-CONTINUING> (329)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (111)
<NET-INCOME> (440)
<EPS-PRIMARY> (.08)
<EPS-DILUTED> (.08)
</TABLE>
