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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 June 30, 1999
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _____ to _____
Commission File Number: 000-23185
PETROGLYPH ENERGY, INC.
(Exact name of Registrant as specified in its charter)
DELAWARE 74-2826234
(State or other jurisdiction (I.R.S. Employer
of incorporation or Identification No.)
organization)
1302 NORTH GRAND STREET
HUTCHINSON, KANSAS 67501
(Address of principal executive offices) (Zip Code)
(316) 665-8500
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
As of July 31, 1999, 5,458,333 shares of common stock, par value $.01
per share, of Petroglyph Energy, Inc. were outstanding.
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TABLE OF CONTENTS
<TABLE>
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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 June 30, 1999 and December 31, 1998........................... 2
Consolidated Statements of Operations for the Three Months and Six Months Ended
June 30, 1999 and 1998................................................................... 3
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 1999 and 1998................................................................... 4
Notes to Consolidated Financial Statements...................................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 7
Item 3.Quantitative and Qualitative Disclosures About Market Risk.............................................. 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
recovery programs, the availability, proximity and capacity of refineries,
pipelines and processing facilities, shortages or delays in the delivery of
equipment and services, land issues, federal, state and tribal regulatory
developments and other risks more fully described in the Company's filings with
the Securities and Exchange Commission. All subsequent oral and written forward
looking statements attributable to the Company or persons acting on its behalf
are expressly qualified in their entirety by these factors. The Company assumes
no obligation to update any of these statements.
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ITEM 1. FINANCIAL STATEMENTS
PETROGLYPH ENERGY, INC
Consolidated Balance Sheets
(in thousands)
<TABLE>
<CAPTION>
ASSETS JUNE 30, DECEMBER 31,
1999 1998
----------- ------------
(Unaudited)
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 947 $ 2,008
Accounts receivable:
Oil and natural gas sales 278 265
Joint interest billing -- 835
Other 39 133
Inventory 1,501 1,234
Prepaid expenses 165 247
---------- ----------
Total Current Assets 2,930 4,722
---------- ----------
Property and Equipment, successful efforts method at cost:
Proved properties 31,914 32,191
Unproved properties 10,645 10,072
Pipelines, gas gathering and other 10,361 10,025
---------- ----------
52,920 52,288
Less: Accumulated depletion, depreciation and amortization (11,677) (11,590)
---------- ----------
Property and equipment, net 41,243 40,698
Other assets, net of accumulated amortization 458 615
---------- ----------
Total Assets $ 44,631 $ 46,035
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities:
Trade $ 297 $ 2,088
Oil and natural gas sales 301 280
Current portion of long-term debt -- --
Other 556 403
---------- ----------
Total Current Liabilities 1,154 2,771
---------- ----------
Long-term Debt 8,000 7,500
Deferred Tax Liability 361 452
Stockholders' Equity:
Common Stock, par value $.01 par share; 25,000,000 shares
authorized; 5,458,333 shares issued and outstanding 55 55
Paid-in capital 46,134 46,134
Retained earnings (deficit) (11,073) (10,877)
---------- ----------
Total Stockholders' Equity 35,116 35,312
---------- ----------
Total Liabilities and Stockholders' Equity $ 44,631 $ 46,035
========== ==========
</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)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Operating Revenues:
Oil sales $ 603 $ 700 $ 1,220 $ 1,493
Natural gas sales 305 287 625 600
Other 62 38 141 73
--------- --------- --------- ---------
Total operating revenues 970 1,025 1,986 2,166
Operating Expenses:
Lease operating 450 441 951 1,036
Production taxes 64 40 100 100
Exploration costs -- -- -- --
Depletion, depreciation and amortization 376 441 825 891
General and administrative 429 516 904 1,011
--------- --------- --------- ---------
Total operating expenses 1,319 1,438 2,780 3,038
--------- --------- --------- ---------
Operating loss (349) (413) (794) (872)
Other Income:
Interest income (expense), net (128) 138 (197) 342
Gain on sales of property and equipment, net 877 28 877 56
--------- --------- --------- ---------
Net income (loss) before income taxes 400 (247) (114) (474)
Income Tax Expense (Benefit):
Deferred 156 (97) (29) (185)
Current -- -- -- --
--------- --------- --------- ---------
Total income tax expense (benefit) 156 (97) (29) (185)
--------- --------- --------- ---------
Net income (loss) before change in accounting principle 244 (150) (85) (289)
Change in accounting principle (net of tax) -- -- (111) --
--------- --------- --------- ---------
Net income (loss) $ 244 $ (150) $ (196) $ (289)
========= ========= ========= =========
Net income (loss) per common share before change in accounting
principle, basic and diluted $ 0.04 $ (0.03) $ (0.02) $ (0.05)
Net loss per common share from change in accounting principle $ -- $ -- $ (0.02) $ --
--------- --------- --------- ---------
Net income (loss) per common share, basic and diluted $ 0.04 $ (0.03) $ (0.04) $ (0.05)
========= ========= ========= =========
Weighted average common shares outstanding 5,458,333 5,458,333 5,458,333 5,458,333
========= ========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
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PETROGLYPH ENERGY, INC
Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
--------------------------
1999 1998
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Operating Activities:
Net loss before income taxes $ (196) $ (289)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization 825 893
Gain on sales of property and equipment, net (877) (56)
Expense of capitalized organization costs
due to change in accounting principle 173 --
Deferred taxes (91) (185)
Changes in assets and liabilities:
Decrease in accounts receivable 897 378
Increase in inventory (293) (210)
(Increase) decrease in prepaid expenses 82 (153)
Decrease in accounts payable and
accrued liabilities (1,617) (733)
---------- ----------
Net cash used in operating activities: (1,097) (355)
---------- ----------
Investing Activities:
Proceeds from sales of property and equipment 1,475 82
Additions to oil and natural gas properties, including
exploration costs (1,398) (5,830)
Additions to pipelines, natural gas gathering and other (526) (3,612)
---------- ----------
Net cash used in investing activities (449) (9,360)
---------- ----------
Financing Activities:
Proceeds from issuance of, and draws on, notes payable 500 --
Payments on notes payable -- (37)
Payments for financing costs (15) (26)
---------- ----------
Net cash provided by (used in) financing activities 485 (63)
---------- ----------
Net decrease in cash and cash equivalents (1,061) (9,778)
Cash and Cash Equivalents, beginning of period 2,008 16,679
---------- ----------
Cash and Cash Equivalents, end of period $ 947 $ 6,901
========== ==========
</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.
On June 30, 1998, all properties owned by PGP, PGP II, and PEI were
transferred into the Company and the three entities (PGP, PGP II, and PEI) were
dissolved.
The accompanying consolidated financial statements of Petroglyph
include the assets, liabilities and results of operations of its wholly owned
subsidiary, Petroglyph Operating Company, Inc. ("POCI"). POCI is a subchapter C
corporation. POCI is the designated operator of all wells for which the Company
has acquired operating rights. Accordingly, all producing overhead and
supervision fees were charged to the joint accounts by POCI. All material
intercompany transactions and balances have been eliminated in the preparation
of the accompanying consolidated financial statements.
The Company's operations are primarily focused in the Uinta Basin of
Utah and the Raton Basin of Colorado with additional operations in DeWitt and
Victoria Counties in South Texas.
The accompanying consolidated financial statements of Petroglyph, with
the exception of the consolidated balance sheet at December 31, 1998, have not
been audited by independent public accountants. In the opinion of the Company's
management, the accompanying consolidated financial statements reflect all
adjustments necessary to present fairly the financial position at June 30, 1999
and the related results of operations for the three-month and six-month periods
ended June 30, 1999 and 1998. All such adjustments are of a normal recurring
nature. These interim results are not necessarily indicative of results for a
full year.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted in this Form 10-Q pursuant to the
rules and regulations of the Securities and Exchange Commission.
(2) LONG-TERM DEBT
Effective September 30, 1998, the Company entered into a credit
agreement with the Chase Manhattan Bank ("Chase") (the "Credit Agreement"). The
Credit Agreement established a credit facility for the Company of up to $50.0
million with a two-year revolving line and an original borrowing base of $15.0
million to be redetermined quarterly. The revolving credit facility expires on
September 30, 2000, at which time all outstanding balances will convert to a
term loan expiring on September 30, 2003. Interest on outstanding borrowings is
calculated, at the Company's option, at either Chase's prime rate or the London
Interbank Offer Rate plus a margin determined by the amount outstanding under
the facility.
Based on crude oil prices in effect at December 31, 1998, the available
borrowing base was redetermined at March 31, 1999 to $9.0 million. In accordance
with the terms of the Credit Agreement, this borrowing base was reduced
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to $8.0 million effective June 15, 1999. Because of the change in the borrowing
base at June 15, the redetermination scheduled for June 30, 1999 was rescheduled
for September 30, 1999.
(3) 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>
<CAPTION>
DURATION VOLUME FLOOR CEILING
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<S> <C> <C> <C>
July 1999 - December 1999 13,250 Bbl/month $17.00 $22.00
January 2000 - December 2000 12,000 Bbl/month $17.00 $20.00
</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
----------------------------- --------------- -----------------------
<S> <C> <C> <C>
Utah: October 1998 - September 1999 3,000 MMBtu/day $1.93 MMBtu ($2.24 MCF)
October 1999 - September 2000 1,500 MMBtu/day $2.10 MMBtu ($2.33 MCF)
Texas: April 1999 - March 2000 1,000 MMBtu/day $2.23 MMBtu ($2.30 MCF)
April 2000 - March 2001 1,000 MMBtu/day $2.24 MMBtu ($2.32 MCF)
</TABLE>
The Company uses price hedging arrangements and fixed price natural gas
sales contracts as described above to reduce price risk on a portion of its oil
and natural gas production.
In September 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities. The Statement establishes
accounting and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair market value. The Statement requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
Statement 133 is effective for fiscal years beginning after June 15, 2000. With
its current hedge contracts, management believes Statement 133 will have no
impact on the financial statements of the Company.
During July 1998, the Company entered into an agreement with Colorado
Interstate Gas Company ("CIG") whereby CIG agreed to install approximately 37
miles of 10-inch steel pipeline from near Trinidad, Colorado to the Company's
Raton Basin coalbed methane development area approximately 6 miles southwest of
Walsenburg, Colorado. The pipeline was placed in service in January 1999 with a
delivery capacity of approximately 50 MMcf per day and will provide the Company
primary access to mid-continent markets for its future coalbed methane
production. The Company has committed to pay CIG a minimum transportation charge
equivalent to $0.325 per Mcf for the daily agreed volumes described below less
$0.02 per Mcf for any unused transportation capacity beginning February 1, 1999,
and ending January 31, 2009. The commitment begins at a minimum volume of 2,000
Mcf per day and increases after each three-month period by 1,000 Mcf per day,
with a maximum commitment of 10,000 Mcf per day. At the end of the first
two-year period the Company has the option to: 1) continue the agreement with a
minimum volume to 16,000 Mcf per day, 2) increase the minimum volume to 32,000
Mcf per day, or 3) eliminate the commitment. The cost of eliminating the
commitment is the cost of the pipeline ($6.4 million) less a credit applied for
the Company's Raton Basin commercial gas production up to 16,000 Mcf per day.
This cost could be applied as a credit to transportation elsewhere on CIG's
system. The Company can reduce the minimum monthly commitment by selling its
available pipeline capacity at market rates.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Petroglyph is an independent energy company engaged in the exploration,
development and acquisition of crude oil and natural gas properties. The
Company's strategy is to increase its reserves, production and cash flow through
(i) the development of its drillsite inventory, (ii) the exploitation of its
existing reserve base, (iii) the control of operations of its core properties,
(iv) the acquisition of additional property interests, and (v) the development
of a strong financial position that affords the Company the financial
flexibility to execute its business strategy.
OPERATING DATA
The following table sets forth certain operating data of the Company
for the periods presented.
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Production Data:
Oil (Bbls) 42,879 67,050 93,491 134,513
Natural gas (Mcf) 157,506 139,182 329,005 292,668
Total (BOE) 69,130 90,247 148,325 183,291
Average Daily Production:
Oil (Bbls) 471 737 517 743
Natural gas (Mcf) 1,731 1,529 1,818 1,617
Total (BOE) 760 992 819 1,013
Average Sales Price per Unit (1):
Oil (per Bbl) (2) $ 14.07 $ 10.44 $ 13.05 $ 11.10
Natural gas (per Mcf) $ 1.94 $ 2.06 $ 1.90 $ 2.05
Costs Per BOE:
Lease operating expenses $ 6.50 $ 4.89 $ 6.41 $ 5.65
Production and property taxes $ 0.93 $ 0.45 $ 0.67 $ 0.55
Depletion, depreciation and
amortization $ 5.44 $ 4.88 $ 5.56 $ 4.86
General and administrative $ 6.21 $ 5.72 $ 6.10 $ 5.51
</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 $11.38 and $10.16 for the six
months, and $14.07 and $9.14 for the three months ended June 30, 1999
and 1998, respectively.
Bbl - Barrel
Mcf - Thousand cubic feet
BOE - Barrels of oil equivalent (six Mcf equal one Bbl)
The Company uses the successful efforts method of accounting for its
oil and natural gas activities. Costs to acquire mineral interests in oil and
natural gas properties, to drill and equip exploratory wells that result in
proved reserves, and to drill and equip development wells are capitalized. Costs
to drill exploratory wells that do not result in proved reserves, costs of
geological, geophysical and seismic testing, and costs of carrying and retaining
properties that do not contain proved reserves are expensed. Costs of
significant nonproducing properties, wells in the process of being drilled and
development projects are excluded from depletion until such time as the related
project is developed and proved reserves are established or impairment is
determined.
No wells were drilled or completed during the three months ended June
30, 1999. This compares with 18 gross (9 net) wells drilled and 16 gross (8 net)
wells completed during the three months ended June 30, 1998.
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 Compared to Three Months Ended June
30, 1998
OPERATING REVENUES
Oil revenues decreased 14% to $603,000 for the quarter ended June 30,
1999, as compared to $700,000 for the same period in 1998, due to a reduction in
the average number of producing wells in the Antelope Creek Field between
periods and a normal production decline in per well volumes from wells outside
the waterflood influence. Oil production declined 36% between periods to 42,879
Bbls. Declining production was mitigated by a $3.63 per Bbl (35%) rise in the
average sales price to $14.07 in the second quarter of 1999 compared to the
second quarter of 1998.
Natural gas revenues increased by 6% to $305,000 for the quarter ended
June 30, 1999, as compared to $287,000 for the same period in 1998. Gas
production volumes rose 13% to 157,506 Mcf. The volume gains offset a 6% decline
in average gas price to $1.94 per Mcf (including hedge) compared to the second
quarter of 1998.
OPERATING EXPENSES
Lease operating expense of $450,000 increased 2% for the quarter ended
June 30, 1999 compared to the same 1998 period. Expense in the current quarter
included $51,000 in commitment fees for Raton Prospect pipeline capacity
compared to zero during the 1998 period. As a result of the commitment fees and
lower volumes noted above, average lease operating expense rose $1.61 (33%) to
$6.50 per BOE compared to the second quarter of 1998.
Depreciation, depletion and amortization expense decreased by 15% to
$376,000 for the quarter ended June 30, 1999, as compared to $441,000 for the
same period in 1998. Since depletion and depreciation on oil and gas leaseholds
and equipment is calculated based on production, the lower volumes in the second
quarter of 1999 translate into reduced expense on oil and gas properties.
However, the depreciation expense for non-oil and gas equipment was spread over
lower sales volume than in the second quarter of 1998. Thus, total depreciation,
depletion and amortization expense rose $0.56 (11%) to $5.44 per BOE in the
second quarter of 1999 compared to the same period in 1998.
General and administrative expenses decreased 17% to $429,000 for the
quarter ended June 30, 1999, as compared to $516,000 for the quarter ended June
30, 1998. The Company's cost reduction plan, initiated in the fourth quarter of
1998 due to low oil prices and decreased drilling activity, was completed in
April 1999.
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OTHER INCOME (EXPENSES)
Interest expense, net of interest income, for the quarter ended June
30, 1999 was $128,000, as compared to $138,000 net interest income in the second
quarter of 1998. This represents the decline in invested funds from the Offering
to a net debt position during the second quarter of 1999.
In the second quarter of 1999 the Company realized a gain of $877,000
and cash of $1,475,000 from the sale of compression equipment in Utah and Texas
and miscellaneous surplus equipment in inventory. Gain on sales of property and
equipment in the second quarter of 1998 was $28,000.
RESULTS OF OPERATIONS
Six Months Ended June 30, 1999 Compared to Six Months Ended June 30,
1998
OPERATING REVENUE
Oil revenues of $1,220,000 for the first six months of 1999 were 18%
below oil revenues for the first half of 1998. The volume of oil sold declined
41,022 barrels (30%) compared to the same period in 1998, as approximately 30
wells were taken out of production in the last half of 1998 due to low oil
prices and conversions to water injection status. The Company's average realized
oil price increased 18% to $13.05 per barrel in the first half of 1999 from
$11.10 for the same period in 1998, which offset the production decline.
Gas volumes in the first half of 1999 increased 12% to 329,005 Mcf
compared to 292,668 Mcf for the same period in 1998. Gas volumes in the Antelope
Creek Field decreased in tandem with oil volumes. However, first half 1999 gas
sales from wells drilled in the Helen Gohlke Field in 1998 more than offset
production declines from the Antelope Creek Field properties. The average sales
price for the first half of 1999 declined $.15 to $1.90 (hedge adjusted)
compared to $2.05 for the same period in 1998. The overall result was a 4%
increase in gas revenues to $625,000 in the first half of 1999 compared to
$600,000 in 1998.
OPERATING EXPENSES
Lease operating expenses through June 30, 1999 were $951,000, or 8%
less than for the first six months of 1998, due primarily to the reduced number
of producing wells mentioned above. However, because of lower sales volumes,
lease operating costs rose 13% to $6.41 per BOE for the first half of 1999
compared to $5.65 for the same period in 1998.
Depreciation, depletion and amortization expense for the first half of
1999 was $825,000 compared to $891,000 through June 30, 1998. Decline in sales
volume during the period caused depreciation, depletion and amortization expense
to rise 14% to $5.56 per BOE for the first six months of 1999 compared with
$4.86 per BOE for the first half of 1998.
General and administrative expenses fell $107,000 (11%) to $904,000 for
the first half of 1999 compared to the same period in 1998. The Company
completed its cost reduction plan in April of 1999 and included $82,000 in
severance costs in the general and administrative expenses for the first half of
1999. Excluding severance charges, general and administrative costs declined 19%
between periods.
OTHER INCOME (EXPENSES)
Net interest expense for the first half of 1999 was $197,000 compared
to $342,000 net interest income for the same period in 1998. Proceeds from the
Offering and borrowed funds were invested in drilling and development activities
throughout 1998, resulting in a net debt position during the first six months of
1999.
Gain on sales of properties increased from $56,000 in the first half of
1998 to $877,000 for the first half of 1999. During the first half of 1999, the
Company realized cash of $1,475,000 from the sale of compression equipment in
Utah and Texas and surplus equipment in inventory.
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CHANGE IN ACCOUNTING PRINCIPLE
The Company is required to comply with Statement of Position ("SOP")
98-5, Reporting on the Costs of Start-Up Activities, for fiscal years beginning
after December 15, 1998. This SOP requires start-up and organizational costs be
expensed as incurred. It also requires start-up and organizational costs
previously capitalized be expensed and that the resulting one-time expense be
accounted for as a change in accounting principle. Accordingly, the Company has
shown as a change in accounting principle $111,200, which represents net
capitalized organizational costs of $173,700 and the associated income tax
benefit of $62,500.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL
Cash used in operating activities was $1,097,000 for the six months
ended June 30, 1999. Accounts receivable decreased $897,000 as credits were
posted to joint interest owners for a share of equipment sales. The Company used
cash on hand, $1,475,000 proceeds from sales of property and equipment, and a $1
million draw under the Credit Agreement to reduce accounts payable and accrued
liabilities by $1,617,000, repay $500,000 of bank debt, and to finance
$1,924,000 of capital spending. During the first quarter of 1999 a total of 3
gross (2 net) wells were drilled and 2 gross (1 net) wells were completed and
put to production. In addition, pipeline infrastructure was completed in the
Raton Basin. No wells were drilled or completed in the second quarter of 1999.
In the second quarter of 1999 the Company realized a gain of $877,000
and cash of $1,475,000 from the sale of Utah and Texas compression facilities
and miscellaneous surplus equipment in inventory.
The Company expects to realize future cash from operations, asset sales,
increased availability under its Credit Agreement, if any, and the development
of other capital resources. The Company believes that a combination of these
sources and current cash on hand will be adequate to support its budgeted
working capital and discretionary capital expenditure programs for at least the
next 12 months. The Company is actively pursuing capital to fund its drilling,
development, and acquisition plans and, if successful, intends to proceed with
the further development of its properties.
CAPITAL EXPENDITURES
During the first half of 1999, the Company converted 2 gross (1 net)
producing wells in the Antelope Creek Field to water injectors and began
returning shut-in wells to producing status as a result of oil price increases.
The Company expects Antelope Creek Field waterflood response to continue to
improve as water injection continues. Depending on available cash flow, up to 12
production wells may be converted to injectors during the remainder of 1999 to
increase field-wide water injection response.
In the first half of 1999, the Company completed its water disposal and
gas gathering system infrastructure in the Raton Basin. Approximately 30,000
Bbls of water per day are currently produced from the 17 well pilot area. This
pilot project continues to progress according to engineering expectations.
Dewatering of coalbeds through the production of water is a necessary
precondition to economical production of coalbed methane gas. The water level in
several production wells is dropping and the volume of produced gas and the
number of wells producing measurable gas quantities are increasing. Pending
testing of current gas production levels, the Company may begin replacing gas
purchased for field usage with produced gas.
During the first half of 1999, the Company drilled 3 gross (2 net)
wells and completed 2 gross (1 net) wells in the Helen Gohlke Field in Victoria
and Dewitt Counties, Texas. One gross and net well was a dry hole and accrued as
exploration expense in 1998. The Company expects to drill 1 gross (0.5 net) well
in the Helen Gohlke Field in the third quarter of 1999 in accordance with a
seismic option agreement. This property, which is non-core to the Company's
reserve development strategy, is currently offered for sale.
-10-
<PAGE> 13
FINANCING
Effective September 30, 1998, the Company entered into the Credit
Agreement with Chase. The Credit Agreement established a credit facility for the
Company of up to $50.0 million with a two-year revolving line and an original
borrowing base of $15.0 million to be redetermined quarterly. The revolving
credit facility expires on September 30, 2000, at which time all outstanding
balances will convert to a term loan expiring on September 30, 2003. Interest on
outstanding borrowings is calculated, at the Company's option, at either Chase's
prime rate or the London Interbank Offer Rate plus a margin determined by the
amount outstanding under the facility.
Based on crude oil prices in effect at December 31, 1998, the available
borrowing base was redetermined at March 31, 1999 to $9.0 million. In accordance
with the terms of the Credit Agreement, this borrowing base was reduced to $8.0
million effective June 15, 1999. Because of the change in the borrowing base at
June 15, the redetermination scheduled for June 30, 1999 was rescheduled for
September 30, 1999.
YEAR 2000 ISSUES
The Company is aware of the potential for disruption of its business as
a result of the failure of computer systems which will not properly recognize
"00" in date sensitive information when the year changes to 2000. Such failures
are collectively characterized as the "Year 2000 issue".
Management of the Company has formed a Year 2000 Team (the "Team"),
consisting of managers and knowledgeable employees, to assess and identify the
potential risks of the Year 2000 issue on the Company and to take the necessary
actions to nullify, as much as possible, the impact of the Year 2000 issue. The
Team has developed a program around the following major areas:
o Information technology and systems
o Process controls and embedded technology
o Third party service and supply providers, customers and
governmental entities
The information technology and systems of the Company are believed to
be Year 2000 compliant. Software upgrades and service releases supplied by
vendors have been installed. The processing ability of hardware and computer
equipment with embedded technology has been successfully tested. Most of these
upgrades were system replacements conducted in 1996 and 1997 to improve business
efficiencies and functionality and were not undertaken solely to address the
Year 2000 issues. As such, Management believes the Year 2000 issues with respect
to the Company's information technology and systems will not have a significant
effect on the Company's financial position or operations.
The process controls and embedded technology area is essentially
complete, but ongoing. Field level processors, meters and equipment utilized by
the Company are not expected to contain embedded technology such as
microprocessors. However, the Company continues to conduct internal evaluations
and hold discussions with suppliers to ensure appropriate measures are taken to
minimize the impact to operations caused by any unidentified company or third
party Year 2000 issues. The Company also relies on non-information technology
systems such as telephones, facsimile machines, security systems and other
equipment which may have embedded technology such as microprocessors, which may
or may not be Year 2000 compliant. Management believes any such disruption is
not likely to have a significant effect on the Company's financial position or
operations. Management anticipates a complete evaluation of this area to
conclude by the end of the third quarter 1999.
Formal communications have been initiated with vendors, suppliers,
customers and others with whom the Company has significant business
relationships. Approximately 85% of correspondents have responded. The Team
continues to evaluate responses and make additional inquiries as needed. The
Company is not currently aware of any third party issues that would cause a
significant business disruption. Management anticipates a complete evaluation of
this area to conclude by the end of the third quarter 1999.
-11-
<PAGE> 14
The total cost of the Company's Year 2000 program is not expected to be
material to the Company's financial position. The Company anticipates spending
less than $10,000 during the remainder of 1999 for Year 2000 related
modifications and testing.
The Company continues to develop its contingency plans in the unlikely
event that portions of its Year 2000 program are inadequate. The Company
believes that the most likely worst-case Year 2000 scenarios are as follows: (i)
unanticipated Year 2000 induced failures in information systems could cause a
reliance on manual contingency procedures and significantly reduce efficiencies
in the performance of certain normal business activities; and (ii) slow downs or
disruptions in the third party supply chain due to Year 2000 causes could result
in operational delays and reduced efficiencies in the performance of certain
normal business activities. Manual systems and other procedures are being
developed to accommodate significant disruptions that could be caused by system
failures. When possible, alternative providers are being identified in the event
certain critical suppliers become unable to provide an acceptable level of
service to the Company. The Company's contingency plans should be completed by
the end of third quarter 1999.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company currently has oil and gas hedge contracts in place further
described in Note 3 (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 $8
million owed at June 30, 1999 under the Company's revolving credit facility
accrues interest a floating rates tied to LIBOR. The Company's current average
rate is approximately 7.8% 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.
-12-
<PAGE> 15
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27 Financial Data Schedule
(b) Reports Submitted on Form 8-K:
None
-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: August 13, 1999
-14-
<PAGE> 17
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
- ------- -----------
<S> <C>
27 Financial Data Schedule, filed herewith
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<CASH> 947
<SECURITIES> 0
<RECEIVABLES> 317
<ALLOWANCES> 0
<INVENTORY> 1,501
<CURRENT-ASSETS> 2,930
<PP&E> 52,920
<DEPRECIATION> 11,677
<TOTAL-ASSETS> 44,631
<CURRENT-LIABILITIES> 1,154
<BONDS> 8,000
0
0
<COMMON> 55
<OTHER-SE> 35,061
<TOTAL-LIABILITY-AND-EQUITY> 44,631
<SALES> 1,845
<TOTAL-REVENUES> 1,986
<CGS> 0
<TOTAL-COSTS> 2,780
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 197
<INCOME-PRETAX> (114)
<INCOME-TAX> (29)
<INCOME-CONTINUING> (85)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (111)
<NET-INCOME> (196)
<EPS-BASIC> (.04)
<EPS-DILUTED> (.04)
</TABLE>
