-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SKrj7/s9s8cyXPLAl77IEtOvkrQIskpah5AMRpaDZHtLh+nyNmbp7zLQYOYGF8Kz Qd/+pvABcpB+XUHHHK7DCQ== 0000950134-99-007469.txt : 19990817 0000950134-99-007469.hdr.sgml : 19990817 ACCESSION NUMBER: 0000950134-99-007469 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990816 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PETROGLYPH ENERGY INC CENTRAL INDEX KEY: 0001038052 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 742826234 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 000-23185 FILM NUMBER: 99690310 BUSINESS ADDRESS: STREET 1: P O BOX 1839 STREET 2: 1302 N GRAND CITY: HUTCHINSON STATE: KS ZIP: 67501 BUSINESS PHONE: 3166658500 MAIL ADDRESS: STREET 1: PETROGLYPH ENERGY INC STREET 2: P O BOX 1839 1302 N GRAND CITY: HUTCHINSON STATE: KS ZIP: 67501 10-Q 1 FORM 10-Q FOR QUARTER ENDED JUNE 30, 1999 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------- FORM 10-Q --------------------- [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. ================================================================================ 2 TABLE OF CONTENTS
Page ---- 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
-i- 3 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. -1- 4 ITEM 1. FINANCIAL STATEMENTS PETROGLYPH ENERGY, INC Consolidated Balance Sheets (in thousands)
ASSETS JUNE 30, DECEMBER 31, 1999 1998 ----------- ------------ (Unaudited) 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 ========== ==========
See accompanying notes to consolidated financial statements. -2- 5 PETROGLYPH ENERGY, INC Consolidated Statements of Operations (in thousands, except per share data) (Unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------ 1999 1998 1999 1998 --------- --------- --------- --------- 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 ========= ========= ========= =========
See accompanying notes to consolidated financial statements. -3- 6 PETROGLYPH ENERGY, INC Consolidated Statements of Cash Flows (in thousands) (Unaudited)
SIX MONTHS ENDED JUNE 30, -------------------------- 1999 1998 ---------- ---------- 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 ========== ==========
See accompanying notes to consolidated financial statements. -4- 7 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 -5- 8 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:
DURATION VOLUME FLOOR CEILING ---------------------------- ---------------- ------ ------- July 1999 - December 1999 13,250 Bbl/month $17.00 $22.00 January 2000 - December 2000 12,000 Bbl/month $17.00 $20.00
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 ----------------------------- --------------- ----------------------- 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)
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. -6- 9 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL Petroglyph is an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas properties. The Company's strategy is to increase its reserves, production and cash flow through (i) the development of its drillsite inventory, (ii) the exploitation of its existing reserve base, (iii) the control of operations of its core properties, (iv) the acquisition of additional property interests, and (v) the development of a strong financial position that affords the Company the financial flexibility to execute its business strategy. OPERATING DATA The following table sets forth certain operating data of the Company for the periods presented.
Three Months Ended Six Months Ended June 30, June 30, ----------------------- ----------------------- 1999 1998 1999 1998 --------- --------- --------- --------- 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
-7- 10 (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. -8- 11 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. -9- 12 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- 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- 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- 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- 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- 17 INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION - ------- ----------- 27 Financial Data Schedule, filed herewith
EX-27 2 FINANCIAL DATA SCHEDULE
5 1,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 947 0 317 0 1,501 2,930 52,920 11,677 44,631 1,154 8,000 0 0 55 35,061 44,631 1,845 1,986 0 2,780 0 0 197 (114) (29) (85) 0 0 (111) (196) (.04) (.04)
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