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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------
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, 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 October 31, 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
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, 2000 and December 31, 1999 ..................... 2
Consolidated Statements of Operations for the Three Months and Nine Months Ended
September 30, 2000 and 1999.............................................................. 3
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2000 and 1999.............................................................. 4
Notes to Consolidated Financial Statements...................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 9
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 14
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings...................................................................................... 15
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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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PETROGLYPH ENERGY, INC.
Consolidated Balance Sheets
(in thousands)
ASSETS SEPTEMBER 30, DECEMBER 31,
2000 1999
------------ ------------
(Unaudited) (Audited)
Current Assets:
Cash and cash equivalents $ 686 $ 1,742
Accounts receivable:
Oil and natural gas sales 1,161 656
Joint interest billing 19 34
Other 108 87
Inventory 2,281 1,489
Prepaid expenses 119 138
------------ ------------
Total Current Assets 4,374 4,146
------------ ------------
Property and Equipment, successful efforts method at cost:
Proved properties 43,484 38,836
Unproved properties 11,993 11,769
Pipelines, gas gathering and other 10,898 10,424
------------ ------------
66,375 61,029
Less: Accumulated depletion, depreciation and amortization (14,025) (12,516)
------------ ------------
Property and equipment, net 52,350 48,513
Other assets, net of accumulated amortization 292 288
------------ ------------
Total Assets $ 57,016 $ 52,947
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 1,973 $ 635
Oil and natural gas sales 182 116
Current portion of long-term debt 19,041 917
Other 684 509
------------ ------------
Total Current Liabilities 21,880 2,177
------------ ------------
Long-term Debt -- 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 deficit (15,624) (12,443)
------------ ------------
Total Stockholders' Equity 35,136 35,817
------------ ------------
Total Liabilities and Stockholders' Equity $ 57,016 $ 52,947
============ ============
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,
------------------------------ ------------------------------
2000 1999 2000 1999
------------ ------------ ------------ ------------
Operating Revenues:
Oil sales $ 1,743 $ 1,139 $ 4,889 $ 2,359
Natural gas sales 170 310 579 936
Other (1) 62 (23) 202
------------ ------------ ------------ ------------
Total operating revenues 1,912 1,511 5,445 3,497
Operating Expenses:
Lease operating 1,303 831 3,712 1,782
Production taxes 256 120 606 220
Exploration costs -- 21 -- 21
Depletion, depreciation and amortization 523 423 1,509 1,248
General and administrative 472 626 1,821 1,530
------------ ------------ ------------ ------------
Total operating expenses 2,554 2,021 7,648 4,801
------------ ------------ ------------ ------------
Operating loss (642) (510) (2,203) (1,304)
Other Income:
Interest income (expense), net (280) (190) (863) (387)
Gain on sales of property and equipment, net 19 (17) 65 860
------------ ------------ ------------ ------------
Net income (loss) before income taxes (903) (717) (3,001) (831)
Income Tax Expense (Benefit):
Deferred -- (270) -- (299)
Current -- -- -- --
------------ ------------ ------------ ------------
Total income tax expense (benefit) -- (270) -- (299)
============ ============ ============ ============
Net income (loss) before change in accounting principle (903) (447) (3,001) (532)
------------ ------------ ------------ ------------
Change in accounting principle (net of income tax effect) -- -- -- (111)
------------ ------------ ------------ ------------
Net income (loss) $ (903) $ (447) $ (3,001) $ (643)
------------ ------------ ------------ ------------
Dividends earned on preferred stock (53) -- (179) --
Net income (loss) available to common stockholders (956) (447) (3,180) (643)
============ ============ ============ ============
Net income (loss) per common share before
change in accounting principle, basic and diluted $ (0.15) $ (0.08) $ (0.49) $ (0.10)
Net income (loss) per common share from change
in accounting principle $ -- $ -- $ -- $ (0.02)
------------ ------------ ------------ ------------
Net income (loss) per common share, basic and diluted $ (0.15) $ (0.08) $ (0.49) $ (0.12)
============ ============ ============ ============
Weighted average common shares outstanding 6,458,333 5,458,333 6,458,333 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,
--------------------------
2000 1999
---------- ----------
Operating Activities:
Net loss $ (3,180) $ (643)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depletion, depreciation and amortization 1,509 1,263
Gain on sales of property and equipment, net (65) (859)
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)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (529) 359
Increase in inventory (835) (183)
Decrease in prepaid expenses 53 104
Increase (decrease) in accounts payable and accrued liabilities 1,579 (1,707)
---------- ----------
Net cash used in operating activities (1,468) (1,657)
---------- ----------
Investing Activities:
Proceeds from sales of property and equipment 108 1,503
Additions to oil and natural gas properties, including
exploration costs (4,872) (9,005)
Additions to pipelines, natural gas gathering and other (474) (561)
---------- ----------
Net cash used in investing activities (5,238) (8,063)
---------- ----------
Financing Activities:
Proceeds from issuance of equity 2,500 8,000
Proceeds from draws on long-term notes 3,150 --
Payments for financing costs -- (14)
---------- ----------
Net cash provided by financing activities 5,650 7,986
---------- ----------
Net decrease in cash and cash equivalents (1,056) (1,734)
Cash and Cash Equivalents, beginning of period 1,742 2,008
---------- ----------
Cash and Cash Equivalents, end of period $ 686 $ 274
========== ==========
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC.
Notes to Consolidated Financial Statements
(Unaudited)
(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 have
been audited by independent public accountants, with the exception of the
September 30, 1999 and 2000 interim financial statements. 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, 2000, and the related results of operations for the periods ended September
30, 2000 and 1999. 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.
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 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 "Special Committee"). The Special Committee was
authorized 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.
At a meeting of the Board of Directors held on June 20, 2000, the
Special Committee reported to the Board of Directors that, after negotiations
between the Special Committee and representatives of Intermountain,
Intermountain had increased its offer to $2.85 per share, and the Special
Committee recommended that the Board of Directors approve the terms of a
proposed merger agreement. The merger agreement was approved by the Board,
subject to stockholder approval, and executed on June 20, 2000.
As previously reported, the funding of the Company's 2000 development
plans was dependent upon its ability to realize proceeds from asset sales,
replace its existing credit facility, raise equity capital and increase its
operating cash flow, whether as a result of successful operations in the Uinta
Basin and Raton Basin or from acquisitions. The Company's inability to obtain
such funds has forced the Company to delay its 2000 development plans. During
the first quarter of 2000, the Company continued its pursuit of finding
additional sources of financing, including selling assets and refinancing its
senior credit facility or replacing its senior lender; however, the Company was
unsuccessful through the second quarter of 2000.
On May 30, 2000, the Company was formally notified that The Chase
Manhattan Bank ("Chase") had redetermined the borrowing base under the Company's
credit agreement (the "Credit Agreement"), resulting in a reduction to $9.0
million. As a result of that redetermination, under the Credit Agreement the
Company had 90 days to reduce the outstanding balance from $11.0 million to $9.0
million. The Company did not have sufficient cash to pay down the $2 million
required by Chase in connection with the redetermination. Since the Company also
had no assurance that Chase would provide the Company with a waiver if it was
unable to reduce the balance by August 28, 2000, the Company asked III
Exploration to provide the Company with financial assistance, which it
subsequently agreed to do. As a result of its discussions with III Exploration,
the Company authorized III Exploration to contact Chase regarding a possible
guarantee of the Company's obligations under the Credit Agreement. Chase refused
to accept III Exploration's guarantee and encouraged III Exploration to purchase
the loan from Chase. As a result, on July 14, 2000, III Exploration's parent
company, Intermountain, purchased at par the outstanding indebtedness and
assumed Chase's rights and obligations under the Credit Agreement. Intermountain
did not change any of the terms and conditions of the Credit Agreement. During
the third quarter of 2000, Intermountain loaned the Company an additional $3.150
million to meet its current obligations. The Company has been advised that this
advance was made in anticipation of the successful completion of the proposed
merger with III Exploration and was specifically intended to preserve the
Company's asset values for the period of time after the merger. The Company was
further advised that any future advances that Intermountain may consider will
only be made if Intermountain believes they are necessary to preserve the
Company's asset values.
On June 28, 2000, III Exploration, in exchange for an assignment of $1
million of the Company's rights from proceeds of oil and natural gas sales,
advanced $1 million to cover past due accounts payable and hedge obligations.
The Company received $800,000 from III Exploration under the terms of an
Agreement and Bill of Sale and Assignment of Proceeds, which assigned to III
Exploration the rights from the proceeds of oil and natural gas sales. The funds
were used to cover past due accounts payable and hedge obligations. The advances
were repaid from the proceeds of oil and natural gas sales.
The Company plans to hold a special meeting of its stockholders to vote
on the merger agreement and the merger as soon as possible after the filing of a
definitive proxy statement with the Securities and Exchange Commission. The
Company has been advised that III Exploration intends to vote all of the shares
of the Company's common stock in favor of the proposed merger with a subsidiary
of III Exploration. As a result, the Company anticipates that the transaction
will be approved. If however the merger is not completed for any reason, the
Company will likely not be
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able to meet its credit obligations originally provided for under the Credit
Agreement, which III Exploration's affiliate purchased, nor carry out its 2000
development plan since there can be no assurance that any additional financing
will be available to the Company on acceptable terms or at all.
The Company sold its Helen Gohlke Field properties in Dewitt and
Victoria Counties, Texas on October 6, 2000 with an effective date of October 1,
2000. Net proceeds, after taking into account the effect of hedging
transactions, were $.8 million and the Company recorded a loss of $.6 million on
the sale.
(3) LONG-TERM DEBT
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 million with a two-year revolving line and a borrowing base
to be redetermined quarterly. The revolving credit facility expired on September
30, 2000, at which time all balances converted 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.
In order to finance the acquisition of the remaining 50% working
interest in the Antelope Creek Field in the Uinta Basin of Utah (the "Antelope
Creek Acquisition") from its non-operated working interest partner, the Company
entered into Amendment No. 1 to the Credit Agreement with Chase, dated as of
August 20, 1999, pursuant to which the Company borrowed an additional $2.5
million.
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.
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 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.
At March 31, 2000, the Company was out of compliance with both the
minimum fixed charge coverage ratio and minimum current ratio covenants as
provided in the Credit Agreement. Chase granted a one-time waiver of default
with respect to such covenants.
On May 30, 2000, the Company was formally notified that Chase had
redetermined the borrowing base, resulting in a reduction in the borrowing base
to $9.0 million. As a result of that redetermination, under the Credit
Agreement, the Company had 90 days to reduce the outstanding balance from $11.0
million to $9.0 million. On July 14, 2000, Intermountain purchased at par the
outstanding indebtedness and assumed Chase's rights and obligations under the
Credit Agreement and did not change any of the terms and conditions of the
Credit Agreement. During the third quarter, the Company borrowed an additional
$3.150 million to meet current obligations.
At September 30, 2000, the Company remained out of compliance with both
the minimum fixed charge coverage ratio (1.25 to 1) and the minimum current
ratio (1 to 1) covenants as provided in the Credit Agreement. The Company had a
fixed charge ratio of (.11) and a current ratio of .20. Accordingly, the debt
outstanding under the Credit Agreement is classified as current in the
consolidated balance sheet. As a result of the Company's non-compliance with
financial covenants in the Credit Agreement, the Company is also in default
under the Notes pursuant to the cross default provisions of the Note Agreement
and has classified the Notes as current in the consolidated balance sheet.
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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
-------- ------ ----- -------
October - December 2000 12,000 Bbl/month $17.00 $20.00
October - December 2000 10,000 Bbl/month $22.00 $27.00
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
-------- ------ -------------
October 2000 - March 2001* 1,000 MMBtu/day $2.2425 MMBtu ($2.39 Mcf)
*The gas hedges were settled on October 9, 2000 in connection with the
sale of the Texas properties.
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, 2011. 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 $97,174 and $398,281 for the three-month and nine-month periods ending
September 30, 2000, 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 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,
------------------------------ -----------------------------
2000 1999 2000 1999
------------ ------------ ----------- -----------
Production Data:
Oil (Bbls) ............................ 82,546 64,838 254,889 158,329
Natural gas (Mcf)...................... 127,713 160,476 354,582 489,480
Total (BOE)............................ 103,832 91,584 313,986 239,909
Average Daily Production:
Oil (Bbls)............................. 897 705 930 580
Natural gas (Mcf)...................... 1,388 1,744 1,294 1,793
Total (BOE)............................ 1,129 995 1,146 879
Average Sales Price per Unit (1):
Oil (per Bbl) (2)...................... $ 21.11 $ 17.56 $ 19.18 $ 14.90
Natural gas (per Mcf).................. $ 1.33 $ 1.94 $ 1.63 $ 1.91
Costs Per BOE:
Lease operating expenses............... $ 12.55 $ 9.08 $ 11.82 $ 7.43
Production and property taxes.......... $ 2.46 $ 1.31 $ 1.93 $ 0.92
Depletion, depreciation and
Amortization........................ $ 5.03 $ 4.62 $ 4.81 $ 5.20
General and administrative............. $ 4.54 $ 6.83 $ 5.80 $ 6.38
(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 $26.34 and $18.45 for the nine
months, and $30.42 and $14.25 for the three months ended September 30,
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.
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One gross (.5 net) well was plugged and abandoned in South Texas during
the nine months ended September 30, 2000. This compares with no wells drilled or
completed during the nine months ended September 30, 1999.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2000 Compared to Three Months Ended
September 30, 1999
OPERATING REVENUES
Operating revenues for the quarter ended September 30, 2000, increased
27% to $1,911,653 compared to $1,511,271 for the same period in 1999. Oil prices
during the third quarter of 2000 increased $3.55 (20%) to $21.11 per barrel
compared to the third quarter of 1999. This price includes a hedge loss of $7.16
per barrel in 2000 compared to a hedge loss of $0.89 per barrel in 1999. Gas
prices per Mcf after hedge impact declined 31% to $1.33 per Mcf. The 2000 gas
price included a hedge loss of $1.34 per Mcf for the quarter, compared to a 1999
third quarter of $0.14 per Mcf hedge loss.
Oil sales volumes increased 27%, from 64,838 barrels, to 82,546 barrels
for the quarter ended September 30, 2000, compared to the same period in 1999.
The 2000 volumes include 11,684 barrels attributable to the purchase of 50%
working interest in Antelope Creek in August 1999 and 11,862 barrels from the
properties acquired from III Exploration ("Property Acquisition") in the fourth
quarter of 1999. Gas sales volumes fell 20% to 127,713 Mcf for the third quarter
of 2000 compared to 160,476 Mcf for the third quarter of 1999. Sales of 43,737
Mcf, from the Property Acquisition, were more than offset by declines of 56,920
Mcf (72%) in Texas. Utah gas sales volumes were reduced 19,583 Mcf (24%) 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 third quarter of 2000 was $471,938
(57%) greater than the comparable period in 1999. Third quarter 2000 lease
operations included significant categories of cost totaling approximately $327
thousand, which were not present in the 1999 period: approximately $194 thousand
representing lease operating expenses for 50% of Antelope Creek Field purchased
in 1999, approximately $98 thousand in lease operating expenses from the
Property Acquisition, and approximately $35 thousand in CIG commitment fees. As
oil and natural gas prices increase, the Company has increased expenditures on
both producing well and injector well remediation. As a result of these
increases, average LOE rose $3.47 to $12.55 per BOE.
Severance taxes increased 114% to $255,682 for the third quarter of
2000 compared to $119,575 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 third quarter
of 2000 decreased $99,488 (24%) to $522,680, compared to the third quarter of
1999. These charges are calculated on oil and gas sales volumes, which were
greater in the 2000 period. Depreciation, depletion, and amortization expense
per barrel increased $.41 (9%) between periods.
Third quarter 2000 general and administrative expense decreased 25% to
$471,860 compared to the same period in 1999.
OTHER INCOME (EXPENSE)
Other revenue and expense, primarily net gas transportation costs,
declined to a $660 loss for the third quarter of 2000 from $61,888 income for
the same period of 1999. Third party gas for transport declined significantly in
both Texas and the Uinta Basin in the third quarter of 2000 and transportation
revenues in Texas were significantly less than transportation costs.
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Net interest expense for the third quarter of 2000 was $279,786,
compared to net interest expense of $198,038 for third quarter 1999. This
reflects the increase in corporate debt between periods.
The Company recorded no tax benefit in the third quarter, compared to
tax benefit in the third quarter of 1999 of $269,551.
RESULTS OF OPERATIONS
Nine Months Ended September 30, 2000 Compared to Nine Months Ended
September 30, 1999
OPERATING REVENUES
Oil revenues of $4,888,636 for the first nine months of 2000 were 107%
above oil revenues for the first nine months of 1999. The volume of oil sold
increased 95,560 barrels (61%) compared to the same period in 1999, due to the
acquisition of the remaining 50% working interest in Antelope Creek and oil
sales from the Property Acquisition. The Company's average realized oil price
increased 29% to $19.18 per barrel for the first nine months of 2000 from $14.90
for the same period in 1999.
Gas volumes for the first nine months of 2000 decreased 27% to 354,582
Mcf compared to 489,480 Mcf for the same period in 1999. Gas volumes in the
Antelope Creek Field decreased in tandem with oil volumes. Gas sales from wells
drilled in the Helen Gohlke Field in 1999 also declined compared to the same
period in 1999. The average sales price for the first nine months of 2000
declined $0.28 to $1.63 (hedge adjusted) compared to $1.91 for the same period
in 1999. The overall result was a 38% decrease in gas revenues to $578,703 for
the first nine months of 2000 compared to $935,625 in 1999.
OPERATING EXPENSES
Lease operating expenses through September 30, 2000 were $3,712,077, or
108% greater than for the first nine months of 1999, due primarily to the
acquisition of the remaining 50% working interest in Antelope Creek, the
Property Acquisition and the CIG commitment fees. During the first three
quarters of 1999, oil prices were at extremely low levels. As a result,
expenditures from maintenance, workovers and remediations were delayed. As
prices improved during the first three quarters of 2000, the Company has
increased the amount of workover and remediation activity to recover from the
reduced activity in 1999. The Company has also converted 16 wells from producing
wells to water injection wells. The conversion of producing wells to water
injection wells results in reduced production. As the reservoir is repressured,
less natural gas is being produced. Decreasing natural gas production and fewer
producing oil wells, combined with the increased lease operating expenditures
has resulted in lease operating cost increases of 60% to $11.82 per BOE for the
first nine months of 2000 compared to $7.43 for the same period in 1999.
Depreciation, depletion and amortization expense for the first nine
months of 2000 was $1,509,318 compared to $1,247,825 through September 30, 1999.
Depreciation, depletion and amortization expense increased 21% due to higher
sales volumes. There was an 8% decline in cost to $4.81 net BOE, for the first
nine months of 2000, compared to $5.20 per BOE for the same period in 1999.
General and administrative expense increased $290,058 (19%) to
$1,820,323 for the first nine months of 2000 compared to the same period in 1999
due primarily to merger related costs.
OTHER INCOME (EXPENSE)
Net interest expense for the first nine months of 2000 was $863,486
compared to $387,045 net interest expense for the same period in 1999.
Gain on sales of equipment decreased from $859,605 in the first nine
months of 1999 to $64,744 for the first nine months of 2000. During the first
nine months of 2000, the Company realized cash of $108,424 from the sale of
surplus inventory, while in the first nine months of 1999 compressors were sold
for $1,393,000.
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LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities primarily remediation and workover
and conversions of producing wells to water injection wells was $1,467,758
during the first nine months of 2000. Accounts receivable, principally oil and
gas receivables, increased $528,750. Current increases of payables of $1,578,579
partially offset the $3,180,249 loss.
The Company reclassified $19,040,725, representing the total amount of
the Company's outstanding debt, was reclassified from long-term liabilities to
Current Portion of Long-Term Debt. On July 14, 2000, Intermountain purchased at
par the Chase loan. As of September 30, 2000, the Company was out of compliance
with both the current ratio and the fixed charge coverage ratio covenants
provided in the Credit Agreement. Because the Company is in default under the
Credit Agreement, and because it converts in December 2000 to a term loan
requiring quarterly principal payments of approximately $916,666 and no
alternative financing is imminent, the total amount of the debt is classified as
current. In the third quarter of 2000, Intermountain advanced under the Credit
Agreement an additional $3.150 million to cover current working capital
requirements. The Company has been advised that this advance was made in
anticipation of the successful completion of the merger and was specifically
intended to preserve the Company's asset values for the period of time after the
merger. The Company has also been advised that any future advances that
Intermountain may consider will only be made if Intermountain believes they are
necessary to preserve the Company's asset values for the period of time after
the merger.
CAPITAL EXPENDITURES
During the first nine months of 2000, the Company converted 16 gross
(16 net) producing wells in the Antelope Creek Field to water injection status.
Depending on available capital the Company intends to spend up to $6.0 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 nine months of 2000, the Company completed six gross (six
net) wells previously drilled in the Bear Creek area of the Raton Prospect. The
2000 development plan calls for drilling two additional wells in the Pilot
Project/Little Creek area.
During the first nine 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, was sold on October 6, 2000 with an effective date of
October 1, 2000.
On February 18, 2000, the Company exchanged 250,000 shares of Series A
Convertible Preferred Stock for non-operated working interests in oil and gas
properties owned by III Exploration ("Property Acquisition") and primarily
located in the Uinta Basin of Utah. The Company anticipates that the Property
Acquisition will provide cash flow of approximately $1.1 million during the
first year and that proved developed producing reserves will increase 15%, or
400,000 BOE, from December 31, 1999 levels. The Company received $402,910 in the
third quarter of 2000 from III Exploration as consideration for an amendment to
a purchase and sale agreement, the effect of which eliminated certain properties
from the Property Acquisition.
FINANCING
As previously reported, the funding of the Company's 2000 development
plans was dependent upon its ability to realize proceeds from asset sales,
replace its existing credit facility, raise equity capital and increase its
operating cash flow, whether as a result of successful operations in the Uinta
Basin and Raton Basin or from acquisitions. The Company's inability to obtain
such funds has forced the Company to delay its 2000 development plans. During
the first quarter of 2000, the Company continued its pursuit of finding
additional courses of financing, including selling assets and refinancing its
senior credit facility or replacing its senior lender; however, the Company was
unsuccessful through the second quarter of 2000.
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On May 30, 2000, the Company was formally notified that Chase had
redetermined the borrowing base under the Credit Agreement, resulting in a
reduction to $9.0 million. As a result of that redetermination, under the Credit
Agreement the Company had 90 days to reduce the outstanding balance from $11.0
million to $9.0 million. The Company did not have sufficient cash to pay down
the $2 million required by Chase in connection with the redetermination. Since
the Company also had no assurance that Chase would provide the Company with a
waiver if it was unable to reduce the balance by August 28, 2000, the Company
asked III Exploration to provide the Company with financial assistance, which it
subsequently agreed to do. As a result of its discussions with III Exploration,
the Company authorized III Exploration to contact Chase regarding a possible
guarantee of the Company's obligations under the Credit Agreement. Chase refused
to accept III Exploration's guarantee and encouraged III Exploration to purchase
the loan from Chase. As a result, on July 14, 2000, III Exploration's parent
company, Intermountain, purchased at par the outstanding indebtedness and
assumed Chase's rights and obligations under the Credit Agreement. Intermountain
did not change any of the terms and conditions of the Credit Agreement. During
the third quarter of 2000, Intermountain loaned the Company an additional $3.150
million to meet its current obligations. The Company has been advised that this
advance was made in anticipation of the successful completion of the proposed
merger with III Exploration and was specifically intended to preserve the
Company's asset values for the period of time after the merger. The Company was
further advised that any future advances that Intermountain may consider will
only be made if Intermountain believes they are necessary to preserve the
Company's asset values.
On June 28, 2000, III Exploration, in exchange for an assignment of $1
million of the Company's rights from proceeds of oil and natural gas sales,
advanced $1 million to cover past due accounts payable and hedge obligations.
The Company had previously received $800,000 from III Exploration under the
terms of an Agreement and Bill of Sale and Assignment of Proceeds dated June 8,
2000, which assigned to III Exploration the rights from the proceeds of oil and
natural gas sales. The funds were used to cover past due accounts payable and
hedge obligations. Both advances were repaid from the proceeds of oil and
natural gas sales.
The Company plans to hold a special meeting of its stockholders to vote
on the merger agreement and the merger as soon as possible after the filing of a
definitive proxy statement with the Securities and Exchange Commission. The
Company has been advised that III Exploration intends to vote all of the shares
of the Company's common stock in favor of the proposed merger with a subsidiary
of III Exploration. As a result, the Company anticipates that the transaction
will be approved. If however the merger is not completed for any reason, the
Company will likely not be able to meet its credit obligations originally
provided for under the Credit Agreement, which III Exploration's affiliate
purchased, nor carry out its 2000 development plan since there can be no
assurance that any additional financing will be available to the Company on
acceptable terms or at all.
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 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.
At September 30, 2000, the Company was out of compliance with both the
minimum fixed charge coverage ratio (1.25 to 1) and the minimum current ratio (1
to 1) covenants as provided in the Credit Agreement. The Company had a fixed
charge ratio of (.07) and a current ratio of .18. Accordingly, the debt
outstanding under the Credit Agreement is classified as current in the
consolidated balance sheet. As a result of the Company's non-compliance with
financial covenants in the Credit Agreement, the Company is also in default
under the Notes pursuant to the cross default provisions of the Note Agreement
and has classified the Notes as current in the consolidated balance sheet.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
At September 30, 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 $14.150
million owed at September 30, 2000, under the Company's revolving credit
facility accrues interest at floating rates tied to LIBOR. The Company's current
average rate is approximately 9.234%, 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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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Mark Lively v. Petroglyph Operating Company, Inc.
Petroglyph is a defendant in a lawsuit filed on or about December 22,
1999 in the District Court of Huerfano County, Colorado, by Mark Lively, wherein
Lively, among other things, seeks an order from the court evicting Petroglyph
from a portion of Lively's property that contains four of Petroglyph's Raton
Basin coalbed methane gas wells. Lively also seeks to recover attorney fees and
costs incurred in connection with the lawsuit. The District Court has entered a
judgment the effect of which is to give Lively a minority working interest in
the minerals underlying the four wells, which judgment Petroglyph plans to
appeal. Petroglyph continues to vigorously defend itself in this matter.
Petroglyph does not believe a negative outcome in this matter would have a
material adverse effect on Petroglyph's financial position or results of
operations.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
10.1 Amendment No. 1 to Purchase and Sale Agreement by and
between III Exploration Company and the Company dated
September 25, 2000.
27.1 Financial Data Schedule
(b) Reports Submitted on Form 8-K:
None.
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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/ S. Kennard Smith
-----------------------------------
S. Kennard Smith
Chief Financial Officer
Date: November 14, 2000
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INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------ -----------
10.1 Amendment No. 1 to Purchase and Sale Agreement by and
between III Exploration Company and the Company dated
September 25, 2000.
27.1 Financial Data Schedule