10-Q 1 d81988e10-q.txt FORM 10-Q FOR QUARTER ENDED SEPTEMBER 30, 2000 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 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. 2 TABLE OF CONTENTS

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 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. 1 4 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS PETROGLYPH ENERGY, INC. Consolidated Balance Sheets (in thousands)

See accompanying notes to consolidated financial statements. 2 5 PETROGLYPH ENERGY, INC. Consolidated Statements of Operations (in thousands, except per share data) (Unaudited)

See accompanying notes to consolidated financial statements. 3 6 PETROGLYPH ENERGY, INC. Consolidated Statements of Cash Flows (in thousands) (Unaudited)

See accompanying notes to consolidated financial statements. 4 7 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. 5 8 (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 6 9 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. 7 10 (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:

The Company has contracted for the sale of its natural gas production and taken hedge positions to effect the following volumes and prices:

*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. 8 11 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.

(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. 9 12 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. 10 13 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. 11 14 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. 12 15 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. 13 16 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. 14 17 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. 15 18 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 16 19 INDEX TO EXHIBITS

PETROGLYPH ENERGY INC 10-Q