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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, 2000
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
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, 2000, 6,458,333 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, 2000 ............................................... 2
Consolidated Statements of Operations for the Three Months Ended
March 31, 2000........................................................................... 3
Consolidated Statements of Cash Flows for the Three Months Ended
March 31, 2000........................................................................... 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............................................... 12
Item 4. Submission of Matters to a Vote of Security Holders..................................................... 12
PART II -- OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K........................................................................ 13
Signatures....................................................................................... 14
</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 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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ITEM 1. FINANCIAL STATEMENTS
PETROGLYPH ENERGY, INC
Consolidated Balance Sheets
(in thousands)
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ASSETS
MARCH 31, DECEMBER 31,
2000 1999
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(Unaudited) (Audited)
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Current Assets:
Cash and cash equivalents $ 416 $ 1,742
Accounts receivable:
Oil and natural gas sales 1,161 656
Joint interest billing 45 34
Other 108 87
Inventory 1,486 1,489
Prepaid expenses 117 138
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Total Current Assets 3,333 4,146
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Property and Equipment, successful efforts method at cost:
Proved properties 42,033 38,836
Unproved properties 11,914 11,769
Pipelines, gas gathering and other 10,542 10,424
-------- --------
64,489 61,029
Less: Accumulated depletion, depreciation and amortization (13,025) (12,516)
-------- --------
Property and equipment, net 51,464 48,513
Other assets, net of accumulated amortization 289 288
-------- --------
Total Assets $ 55,086 $ 52,947
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 1,161 $ 635
Oil and natural gas sales 69 116
Current portion of long-term debt 1,833 917
Other 384 509
-------- --------
Total Current Liabilities 3,447 2,177
-------- --------
Long-term Debt 14,043 14,953
Stockholders' Equity:
Common Stock, par value $.01 par share; 25,000,000 shares
authorized; 6,458,333 shares issued and outstanding 65 65
Preferred Stock, convertible; 250,000 shares outstanding 2,500 --
Paid-in capital 48,195 48,195
Retained earnings (deficit) (13,164) (12,443)
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Total Stockholders' Equity 37,596 35,817
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Total Liabilities and Stockholders' Equity $ 55,086 $ 52,947
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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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2000 1999
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Operating Revenues:
Oil sales $ 1,667 $ 616
Natural gas sales 211 320
Other -- 79
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Total operating revenues 1,878 1,015
Operating Expenses:
Lease operating 1,262 501
Production taxes 127 36
Exploration costs -- --
Depletion, depreciation and amortization 508 448
General and administrative 441 475
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Total operating expenses 2,338 1,460
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Operating loss (460) (445)
Other Income:
Interest income (expense), net (282) (69)
Gain on sales of property and equipment, net 21 --
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Net loss before income taxes (721) (514)
Income Tax Benefit:
Deferred -- (185)
Current -- --
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Total income tax benefit -- (185)
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Net loss before change in accounting principle (721) (329)
Change in accounting principle (net of income tax effect) -- (111)
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Net loss $ (721) $ (440)
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Net loss per common share before change in accounting
principle, basic and diluted $ (0.11) $ (0.06)
Net loss per common share from change in accounting principle $ -- $ (0.02)
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Net loss per common share, basic and diluted $ (0.11) $ (0.08)
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Weighted average common shares outstanding 6,458,333 5,458,333
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</TABLE>
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC
Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
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THREE MONTHS ENDED
MARCH 31,
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2000 1999
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Operating Activities:
Net loss before income taxes $ (721) $ (440)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization 520 448
Gain on sales of property and equipment, net (21) --
Expense of capitalized organization costs
due to change in accounting principle -- 173
Deferred taxes -- (248)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (543) 472
Increase in inventory (27) (177)
Decrease in prepaid expenses 21 44
Increase (decrease) in accounts payable and
accrued liabilities 354 (1,193)
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Net cash used in operating activities: (417) (921)
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Investing Activities:
Proceeds from sales of property and equipment 52 --
Additions to oil and natural gas properties, including
exploration costs (843) (1,155)
Additions to pipelines, natural gas gathering and other (118) (389)
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Net cash used in investing activities (909) (1,544)
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Financing Activities:
Proceeds from issuance of, and draws on, notes payable -- 1,000
Payments for financing costs -- (11)
------- -------
Net cash provided by financing activities -- 989
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Net decrease in cash and cash equivalents (1,326) (1,476)
Cash and Cash Equivalents, beginning of period 1,742 2,008
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Cash and Cash Equivalents, end of period $ 416 $ 532
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</TABLE>
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. Effective June
30, 1998, PGP, PGP II, and PEI were dissolved and the assets and liabilities and
results of operations were rolled up into the Company with no change in carrying
values.
On August 18, 1999, III Exploration Company, an Idaho corporation ("III
Exploration"), completed the purchase (the "Purchase") from Robert A.
Christensen, a director and executive officer of the Company, David R. Albin, a
director of the Company, Kenneth A. Hersh, a director of the Company, R. Gamble
Baldwin, John S. Foster, Bruce B. Selkirk, III, Albin Income Trust, Natural Gas
Partners, L.P., Natural Gas Partners II, L.P. and Natural Gas Partners III, L.P.
(collectively, the "Sellers") of 2,753,392 shares of common stock, $.01 par
value of the Company. III Exploration is controlled by Intermountain Industries,
Inc., an Idaho corporation ("Intermountain"). As a result of the Purchase,
Intermountain, through its ownership of III Exploration, acquired approximately
50.4% of the outstanding Common Stock of the Company (the "Change of Control").
On December 28, 1999, the Company sold 1,000,000 shares of Common Stock
to III Exploration in a privately negotiated sale at a purchase price of $2.00
per share (the "Private Placement"). As a result of the Purchase and the Private
Placement, Intermountain, through its ownership of III Exploration, owns
approximately 59.1% of the outstanding Common Stock of the Company (assuming the
exercise of a warrant to purchase 150,000 shares of Common Stock issued in
connection with the sale of subordinated notes).
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 accompanying consolidated financial statements of Petroglyph, with
the exception of the consolidated balance sheet at December 31, 1999, 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,
2000, and the related results of operations for the three month periods ended
March 31, 2000 and 1999. All such adjustments are of a normal recurring nature.
These interim results are not necessarily indicative of results for a full year.
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.
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.
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(2) SIGNIFICANT EVENTS
On February 15, 2000, the stockholders of the Company approved the
issuance of 250,000 shares of Series A Convertible Preferred Stock (the
"Preferred Shares") to III Exploration exchange for certain producing oil and
gas properties primarily located in the Uinta Basin of Utah (the "III
Exploration Purchase"). The stockholders of the Company also approved the
issuance of shares of Common Stock upon the potential conversion of the
Preferred Shares.
The Preferred Shares will be convertible, beginning two years from the
date of issuance, into shares of Common Stock at a conversion price of $3.50 per
share of Common Stock, based on the preference amount of $10.00 per Preferred
Share. The Company has the option to redeem the Preferred Shares at any time
after the third anniversary of the transaction closing date in whole or in part
at a redemption price of $12.00 per Preferred Share. The Preferred Shares are
being issued pursuant to an exemption from the registration requirement under
the Securities Act and will be subject to transfer restrictions imposed by the
Securities Act.
The Company anticipates that the III Exploration Purchase will provide
cash flow of approximately $900,000 during the first year and that proved
developed producing reserves will increase 15%, or 400,000 BOE, from December
31, 1999 levels.
The effective date of the Purchase was November 1, 1999. The
transaction was closed on February 18, 2000.
On May 3, 2000, the Company received a proposal from Intermountain to
purchase the approximately 2.7 million shares of Common Stock of Petroglyph that
it does not already indirectly own through III Exploration for $2.20 per share.
In response to the offer, an independent committee of the Petroglyph board of
directors was formed. The independent committee, was employed by the board of
directors to employ counsel and a financial advisor to evaluate the fairness of
the offer, consider alternatives and handle all negotiations with Intermountain
concerning the proposed purchase of the shares.
(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 redetermination
scheduled for December 31, 1999 resulted in no change to the borrowing base. The
next redetermination was scheduled to occur on or before March 31, 2000.
However, the Company is in the process of replacing the Credit Agreement and the
redetermination has been postponed pending the outcome of the Company's
negotiations with other financial institutions.
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.
At March 31, 2000, the Company was out of compliance with both the
minimum fixed charge coverage ratio and minimum current ratio as defined in the
Credit Agreement. Chase waived the right to enforce default provisions in the
Credit Agreement pertaining to these defaults. The Company anticipates it will
find alternative sources of financing with an initial revolving period in excess
of one year.
In August 1999, the Company sold $5 million of 8% senior subordinated
notes due 2004 (the "Notes") to III Exploration. The Notes required the Company
to deliver to III Exploration a stock purchase warrant to acquire 150,000 shares
of Common Stock of the Company at an exercise price of $3.00 per share and the
ability for III Exploration to obtain additional stock purchase warrants over
the life of the Notes. The number of future stock purchase warrants will
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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.
(4) COMMITMENTS
The Company has hedged a portion of its future production with crude
oil collars based on a floor price and a ceiling price indexed to the NYMEX
light crude future settlement price. Oil hedge contracts currently in place are:
<TABLE>
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DURATION VOLUME FLOOR CEILING
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April 2000 - December 2000 12,000 Bbl/month $17.00 $20.00
July 2000 - September 2000 6,000 Bbl/month $20.00 $23.00
July 2000 - September 2000 4,000 Bbl/month $23.00 $31.70
October 2000 - December 2000 10,000 Bbl/month $22.00 $27.00
AVERAGE PRICE
-------------
April 2000 - June 2000 12,000 Bbl/month $20.05
</TABLE>
The Company has contracted for the sale of its natural gas production
and taken hedge positions to effect the following volumes and prices:
<TABLE>
<CAPTION>
DURATION VOLUME AVERAGE PRICE
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<S> <C> <C> <C>
Utah: April 2000 - September 2000 700 MMBtu/day $2.01 MMBtu ($2.33 MCF)
Texas: April 2000 - March 2001 1,000 MMBtu/day $2.2425 MMBtu ($2.31 MCF)
</TABLE>
The Company uses price hedging arrangements and fixed price natural gas
sales contracts as described above to reduce price risk on a portion of its oil
and natural gas production.
In September 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for fiscal years beginning after June 15, 2000. With its
current hedge contracts, management believes SFAS No. 133 will not have a
material affect on the Company's financial position or results of operations.
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
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rates. Net commitment fees paid to CIG totaling $146,000 for the three-month
period ending March 31, 2000, are reflected as lease operating expense in the
Company's consolidated statements of operations.
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 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.
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Three Months Ended
March 31,
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2000 1999
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Production Data:
Oil (Bbls) ............................... 89,230 50,612
Natural gas (Mcf) ........................ 111,916 171,498
Total (BOE) .............................. 107,883 79,195
Average Daily Production:
Oil (Bbls) ............................... 981 562
Natural gas (Mcf) ........................ 1,230 1,906
Total (BOE) .............................. 1,186 880
Average Sales Price per Unit (1):
Oil (per Bbl) (2) ........................ $ 18.69 $ 12.18
Natural gas (per Mcf) .................... $ 1.88 $ 1.86
Costs Per BOE:
Lease operating expenses ................. $ 11.70 $ 6.33
Production and property taxes ............ $ 1.17 $ 0.45
Depletion, depreciation and
amortization .......................... $ 4.72 $ 5.66
General and administrative ............... $ 4.08 $ 6.00
</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 $25.72 and $9.09 for the three
months ended March 31, 2000 and 1999, 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 plugged and abandoned in South Texas and
three gross and net wells were completed in the Raton Basin during the three
months ended March 31, 2000. This compares with three gross (one net) wells
drilled and completed in Texas and one dry hole in Texas during the three months
ended March 31, 1999.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2000 Compared to Three Months Ended March
31, 1999
OPERATING REVENUES
Operating revenues for the quarter ended March 31, 2000, increased 85%
to $1,878,000 compared to $1,015,000 for the same period in 1999. Oil prices
during the first quarter of 2000 increased $6.51 (53%) to $18.69 per barrel
compared to the first quarter of 1999. This price includes a hedge loss of $7.03
per barrel in 2000 compared to a hedge gain of $3.09 per barrel in 1999. Gas
prices per Mcf after hedge impact were essentially flat between periods. The
2000 gas price included a hedge loss of $0.37 per Mcf for the quarter. There was
no gas hedge effect in the 1999 period.
Oil sales volumes increased 76%, or 38,618 barrels, to 89,230 barrels
for the quarter ended March 31, 2000, compared to the same period in 1999. The
2000 volumes include 35,605 barrels attributable to the purchase of 50% working
interest in Antelope Creek in August 1999 and 13,479 barrels from the III
Exploration acquisition in the fourth quarter of 1999. Gas sales volumes fell
35% to 111,916 Mcf for the first quarter of 2000 compared to 171,498 Mcf for the
first quarter of 1999. Sales of 39,497 Mcf added by the III Exploration
properties were more than offset by declines of 38,674 Mcf (49%) in Texas. Utah
gas sales volumes were reduced 48,981 Mcf (65%) between periods, which was
attributed to normal gas production declines associated with increased reservoir
pressure due to waterflood activity inhibiting free gas from breaking out of the
oil solution.
OPERATING EXPENSES
Lease operating expense for the first quarter of 2000 was $761,000
(152%) greater than the comparable period in 1999. First quarter 2000 lease
operations included significant categories of cost totaling $838,000 which were
not present in the 1999 period: $158,000 in compressor rentals attributable to
the sale of compression facilities in Antelope Creek and Texas in 1999, $508,000
representing lease operating expenses for 50% of Antelope Creek Field purchased
in 1999, $45,000 in lease operating expenses on properties acquired from III
Exploration, and $127,000 in CIG commitment fees. As a result of these
increases, average LOE rose $5.37 to $11.70 per barrel.
Severance taxes increased 253% to $127,000 for the first three months
of 2000 compared to $36,000 for the same period of 1999. This increase is in
step with the increase in the value of oil and gas sales between periods before
the effect of hedge losses and gains.
Depreciation, depletion, and amortization charges for the first quarter
of 2000 increased $60,000 (13%) to $508,000 compared to the first quarter of
1999. These charges are calculated on oil and gas sales volumes, which were
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greater in the 2000 period. Depreciation, depletion, and amortization expense
per barrel declined $0.94 (17%) between periods.
First quarter 2000 general and administrative expense decreased 7% to
$441,000 compared to the same period in 1999, as a result of cost reduction
measures initiated in the previous year.
OTHER INCOME (EXPENSE)
Other revenue, primarily net gas transportation fee income, declined to
zero for the first three months of 2000 from $79,000 income for the same period
of 1999. Third party gas for transport declined significantly in both Texas and
the Uinta Basin in the first quarter of 2000 and transportation revenues did not
exceed costs for obligations to down-stream pipelines during the three-month
period ending March 31, 2000.
Net interest expense for the first quarter of 2000 was $282,000,
compared to net interest expense of $69,000 for first quarter 1999. This
reflects the increase in corporate debt between periods.
The Company is in a net deferred tax asset position at March 31, 2000.
As a result, the Company does not intend to record any tax benefits in 2000
relating to net operating losses for financial statement purposes. The statement
of operations for the quarter ending March 31, 1999 showed an income tax benefit
of $185,000 based on the loss for the period. No income tax benefit was booked
relative to the net loss incurred in first quarter 2000.
CHANGE IN ACCOUNTING PRINCIPLE
During 1999, the Company adopted Statement of Position ("SOP") 98-5,
Reporting on the Costs of Start-Up Activities. 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, for the three-month period ending March 31, 1999, the Company
showed as a change in accounting principle an $111,000 expense, which
represented net capitalized organizational costs of $173,000 and the associated
income tax benefit of $62,000.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities was $417,000 during the quarter ended
March 31, 2000. Accounts receivable, principally oil and gas receivables
realized in April 2000, increased $543,000. Current payables increased $353,000.
In addition, $917,000, representing a loan payment due in the first quarter of
2001, was moved from long-term liabilities to Current Portion of Long-Term Debt.
In the first quarter of 2000, the Company realized $52,000 and booked
$21,000 gain from the sale of surplus lease and well equipment.
The Company currently has no borrowing capacity on its existing credit
agreement, which converts in December 2000 to a term loan requiring quarterly
principal payments of approximately $916,000. The Company intends to refinance
its existing credit facility and replace it with a new credit agreement with an
initial revolving period of at least two years. The anticipated facility,
together with a planned sale of certain Texas oil and gas properties, is
expected to provide a portion of the capital resources required to fund the
Company's 2000 development program and support its ongoing operations. If the
Company is successful in replacing its existing credit facility, additional
capital resources will still be required to completely fund the Company's 2000
development plan. The Company does not currently have any other committed
sources of debt or equity capital, but anticipates these sources will become
available. However, if the Company is unable to replace its existing credit
facility, additional capital resources may be required to fund maturities of
debt as they become due. There can be no assurance that any additional financing
will be available to the Company on acceptable terms or at all. In the event
sufficient capital is not available, the Company may be unable to develop its
Uinta Basin and Raton Basin properties in accordance with its planned schedule,
pay its maturities of debt as they
-10-
<PAGE> 13
become due or maintain compliance with existing debt covenants and may be
required to take further measures to reduce the size and scope of its business.
CAPITAL EXPENDITURES
During the first three months of 2000, the Company converted one gross
and net producing well in the Antelope Creek Field to water injection status.
Additional capital expenditures for well remediation and production enhancement
projects have resulted in production increases of approximately 20% over
year-end 1999 rates. Depending on available capital the Company intends to spend
up to $5.0 million converting as many as 26 wells to water injection status and
drilling up to eight new wells during the remainder of 2000 to increase the
field-wide water injection pattern and enhance production.
In the first three months of 2000, the Company completed three gross
and net wells previously drilled in the Bear Creek area of the Raton Prospect.
The 2000 development plan calls for drilling 11 additional wells in the Pilot
Project/Little Creek area and two wells in the Bear Creek area for total costs
of $3.0 million.
During the first three months of 2000, the Company plugged and
abandoned one gross (.5 net) well in the Helen Gohlke Field in Victoria and
Dewitt Counties, Texas. This property, which is non-core to the Company's
reserve development strategy, is currently offered for sale.
On February 18, 2000, the Company exchanged 2,500,000 shares of Series
A Convertible Preferred Stock for non-operated working interests in oil and gas
properties owned by III Exploration and primarily located in the Uinta Basin of
Utah. The Company anticipates that the III Exploration Purchase will provide
cash flow of approximately $900,000 during the first year and that proved
developed producing reserves will increase 15%, or 400,000 BOE, from December
31, 1999 levels.
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. The Credit Agreement contains certain financial covenants
including a minimum fixed charge coverage ratio, a minimum current ratio and
others.
At March 31, 2000, the Company was out of compliance with both the
minimum fixed charge coverage ratio and minimum current ratio as defined in the
Credit Agreement. Chase waived the right to enforce default provisions in the
Credit Agreement pertaining to these defaults. The Company anticipates it will
find alternative sources of financing with an initial revolving period in excess
of one year.
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 redetermination
scheduled for December 31, 1999 resulted in no change to the borrowing base. The
next redetermination was scheduled to occur on or before March 31, 2000.
However, the Company is in the process of replacing the Credit Agreement and the
redetermination has been postponed pending the outcome of the Company's
negotiations with other financial institutions.
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.
In August 1999, the Company sold $5 million of 8% senior subordinated
notes due 2004 (the "Notes") to III Exploration. The Notes required the Company
to deliver to III Exploration a stock purchase warrant to acquire 150,000 shares
of Common Stock of the Company at an exercise price of $3.00 per share and the
ability for III Exploration to obtain additional stock purchase warrants over
the life of the Notes.
-11-
<PAGE> 14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At March 31, 2000, the Company currently has oil and gas hedge
contracts in place as 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 $11.0
million owed at March 31, 2000, under the Company's revolving credit facility
accrues interest at floating rates tied to LIBOR. The Company's current average
rate is approximately 8.79%, locked in for 90-day terms.
The Company performed a sensitivity analysis to assess the potential
effect of commodity price risk and interest rate risk and determined that the
effect, if any, of reasonably possible near-term changes in NYMEX oil prices or
interest rates on the Company's financial position, results of operations and
cash flow should not be material.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
A special meeting of stockholders was held on February 15, 2000 to vote
on one proposition: to approve the issuance of (a) 250,000 shares of Series A
Convertible Preferred Stock, par value $.01 per share (the "Preferred Shares"),
to III Exploration, in exchange for certain oil and gas producing properties
primarily located in the Uinta Basin of Utah; and (b) shares of Common Stock,
par value $.01 per share (the "Common Stock"), upon the potential conversion of
the Preferred Shares. The table below depicts the votes cast for, against and
abstained.
<TABLE>
<CAPTION>
Votes For Votes Against Votes Abstained
--------- ------------- ---------------
<S> <C> <C>
5,202,076 18,720 9,900
</TABLE>
-12-
<PAGE> 15
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Financial Data Schedule
-13-
<PAGE> 16
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 15, 2000
-14-
<PAGE> 17
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-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 416
<SECURITIES> 0
<RECEIVABLES> 1,314
<ALLOWANCES> 0
<INVENTORY> 1,486
<CURRENT-ASSETS> 3,333
<PP&E> 64,489
<DEPRECIATION> 13,025
<TOTAL-ASSETS> 55,086
<CURRENT-LIABILITIES> 3,447
<BONDS> 14,043
0
2,500
<COMMON> 65
<OTHER-SE> 35,031
<TOTAL-LIABILITY-AND-EQUITY> 55,086
<SALES> 1,878
<TOTAL-REVENUES> 1,878
<CGS> 0
<TOTAL-COSTS> 2,338
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 282
<INCOME-PRETAX> (721)
<INCOME-TAX> 0
<INCOME-CONTINUING> (721)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (721)
<EPS-BASIC> (0.11)
<EPS-DILUTED> (0.11)
</TABLE>
