================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------- FORM 10-Q/A-3 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended June 30, 1999 ----------- Commission File Number 0-20872 ST. MARY LAND & EXPLORATION COMPANY (Exact name of Registrant as specified in its charter) Delaware 41-0518430 (State or other Jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 1776 Lincoln Street, Suite 1100, Denver, Colorado 80203 (Address of principal executive offices) (Zip Code) (303) 861-8140 (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 [ ] Indicate the number of shares outstanding of each of the Registrant's classes of common stock as of the latest practicable date. As of August 2, 1999 the registrant had 11,094,852 shares of Common Stock, $.01 par value, outstanding. ================================================================================ THIS AMENDMENT ON FORM 10-Q/A-3 TO THE REGISTRANT'S FORM 10-Q/A-2 FOR THE QUARTER ENDED JUNE 30, 1999 IS BEING FILED TO REFLECT CERTAIN ADDITIONAL DISCLOSURES IN RESPONSE TO COMMENTS RECEIVED FROM THE SEC STAFF IN CONNECTION WITH ST. MARY LAND & EXPLORATION COMPANY'S REGISTRATION STATEMENT ON FORM S-4 AMENDMENT NO. 2 FILED ON NOVEMBER 12, 1999. THIS AMENDMENT ALSO REFLECTS THE RECOGNITION OF $386,000 OF INTEREST INCOME AND $49,717 OF OTHER INCOME, BOTH OF WHICH HAD BEEN NETTED AGAINST THE SUMMO NOTE RECEIVABLE IN THE REGISTRANT'S FORM 10-Q/A-2 FOR THE QUARTER ENDED JUNE 30, 1999. ST. MARY LAND & EXPLORATION COMPANY ----------------------------------- INDEX ----- Part I. FINANCIAL INFORMATION PAGE ---- Item 1. Financial Statements (Unaudited) Consolidated Balance Sheets - June 30, 1999 and December 31, 1998 ............................... 3 Consolidated Statements of Operations - Three Months Ended June 30, 1999 and 1998: Six Months Ended June 30, 1999 and 1998 .................... 4 Consolidated Statements of Cash Flows - Six Months Ended June 30, 1999 and 1998........................... 5 Notes to Consolidated Financial Statements - June 30, 1999 ...................... 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................... 9 Part II. OTHER INFORMATION Item 2. Changes in Securities ...........................23 Item 5. Other Information ...............................23 Item 6. Exhibits and Reports on Form 8-K ................23 Exhibits -------- 2.1 Agreement and Plan of Merger 4.1 Shareholder Rights Plan 27.1 Financial Data Schedule -2- PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (In thousands, except share amounts) ASSETS
June 30, December 31, ------------- ------------- 1999 1998 ------------- ------------- Current assets: Cash and cash equivalents $ 5,244 $ 7,821 Accounts receivable 12,775 17,937 Prepaid expenses and other 816 795 Refundable income taxes 211 391 Deferred income taxes 91 125 ------------- ------------- Total current assets 19,137 27,069 ------------- ------------- Property and equipment (successful efforts method), at cost: Proved oil and gas properties 252,803 241,021 Unproved oil and gas properties, net of impairment allowance of $4,229 in 1999 and $5,987 in 1998 31,455 25,588 Other property and equipment 4,654 4,051 ------------- ------------- 288,912 270,660 Less accumulated depletion, depreciation, amortization and impairment (136,714) (126,835) ------------- ------------- 152,198 143,825 ------------- ------------- Other assets: Khanty Mansiysk Oil Corporation receivable and stock 6,839 6,839 Summo Minerals Corporation investment and receivable 1,566 2,869 Restricted cash - 720 Other assets 3,526 3,175 ------------- ------------- 11,931 13,603 ------------- ------------- $ 183,266 $ 184,497 ============= ============= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 10,315 $ 16,926 Current portion of stock appreciation rights 272 358 ------------- ------------- Total current liabilities 10,587 17,284 ------------- ------------- Long-term liabilities: Long-term debt 20,087 19,398 Deferred income taxes 11,918 11,158 Stock appreciation rights 455 422 Other noncurrent liabilities 1,250 1,493 ------------- ------------- 33,710 32,471 ------------- ------------- Commitments and contingencies Stockholders' equity: Common stock, $.01 par value: authorized - 50,000,000 shares: issued and outstanding - 11,269,361 shares in 1999 and 10,992,447 shares in 1998 113 110 Additional paid-in capital 71,083 67,761 Treasury stock - at cost: 182,800 shares in 1999 and 147,800 shares in 1998 (2,995) (2,470) Retained earnings 70,573 69,341 Unrealized gain on marketable equity securities-available for sale 195 - ------------- ------------- Total stockholders' equity 138,969 134,742 ------------- ------------- $ 183,266 $ 184,497 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. -3- ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (In thousands, except per share amounts)
For the Three Months Ended For the Six Months Ended June 30, June 30, ------------------------------- -------------------------------- 1999 1998 1999 1998 ------------- -------------- -------------- -------------- Operating revenues: Oil and gas production $ 15,809 $ 20,233 $ 29,578 $ 39,258 Gain (loss) on sale of proved properties (81) (14) 114 (14) Other revenues 177 88 323 202 ------------- -------------- -------------- -------------- Total operating revenues 15,905 20,307 30,015 39,446 ------------- -------------- -------------- -------------- Operating expenses: Oil and gas production 3,960 4,173 7,954 8,116 Depletion, depreciation and amortization 5,281 6,503 10,683 11,880 Impairment of proved properties 247 1,077 247 1,445 Exploration 1,203 3,052 2,942 6,473 Abandonment and impairment of unproved properties 336 312 800 615 General and administrative 2,030 1,477 3,638 4,424 Loss in equity investees 13 510 58 571 Other 213 57 338 92 ------------- -------------- -------------- -------------- Total operating expenses 13,283 17,161 26,660 33,616 ------------- -------------- -------------- -------------- Income from operations 2,622 3,146 3,355 5,830 Nonoperating income and (expense): Interest income 542 371 638 526 Interest expense (275) (360) (516) (754) ------------- --------------- -------------- -------------- Income before income taxes 2,889 3,157 3,477 5,602 Income tax expense 982 1,121 1,161 1,896 ------------- -------------- -------------- -------------- Income from continuing operations 1,907 2,036 2,316 3,706 Gain on sale of discontinued operations, net of taxes - 34 - 34 ------------- -------------- -------------- -------------- Net income $ 1,907 $ 2,070 $ 2,316 $ 3,740 ============= ============== ============== ============== Basic earnings per common share: Income from continuing operations $ .17 $ .19 $ .21 $ .34 Gain on sale of discontinued operations - - - - ============== ============== ============== ============== Basic net income per common share $ .17 $ .19 $ .21 $ .34 ============== ============== ============== ============== Diluted earnings per common share: Income from continuing operations $ .17 $ .18 $ .21 $ .33 Gain on sale of discontinued operations - - - - ============== ============== ============== ============== Diluted net income per common share $ .17 $ .18 $ .21 $ .33 ============== ============== ============== ============== Basic weighted average common shares outstanding 10,913 10,984 10,879 10,984 ============== ============== ============== ============== Diluted weighted average common shares outstanding 10,934 11,079 10,892 11,102 ============== ============== ============== ============== Cash dividend declared per share $ 0.05 $ 0.05 $ 0.10 $ 0.10 ============== ============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. -4- ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (In thousands)
For the Six Months Ended June 30, -------------------------------- 1999 1998 ------------- ------------- Reconciliation of net income to net cash provided by operating activities: Net income $ 2,316 $ 3,740 Adjustments to reconcile net income to net cash provided by operating activities: (Gain) loss on sale of proved properties (114) 14 Depletion, depreciation and amortization 10,683 11,880 Impairment of proved properties 247 1,445 Exploratory dry hole costs (119) 2,945 Abandonment and impairment of unproved properties 800 615 Loss in equity investees 58 571 Deferred income taxes 760 1,410 Other (567) 239 ------------- ------------- 14,064 22,859 Changes in current assets and liabilities: Accounts receivable 5,947 7,081 Prepaid expenses and other 2,507 (986) Accounts payable and accrued expenses (2,171) (1,600) Stock appreciation rights (86) 7 ------------- ------------- Net cash provided by operating activities 20,261 27,361 ------------- ------------- Cash flows from investing activities: Proceeds from sale of oil and gas properties 713 59 Capital expenditures (20,478) (29,391) Acquisition of oil and gas properties (1,869) (2,026) Investment in and loans to Summo Minerals Corporation (220) (566) Collections on loan to Summo Minerals Corporation 2,096 - Receipts from restricted cash 720 - Investment in Nance Petroleum 684 - Other (352) (922) ------------- ------------- Net cash used in investing activities (18,706) (32,846) ------------- ------------- Cash flows from financing activities: Proceeds from long-term debt 7,550 24,395 Repayment of long-term debt (10,250) (20,387) Proceeds from sale of common stock 177 - Repurchase of common stock (525) - Dividends paid (1,084) (1,098) ------------- ------------- Net cash provided by (used in) financing activities (4,132) 2,910 ------------- ------------- Net decrease in cash and cash equivalents (2,577) (2,575) Cash and cash equivalents at beginning of period 7,821 7,112 ------------- ------------- Cash and cash equivalents at end of period $ 5,244 $ 4,537 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. -5- ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued) Supplemental schedule of additional cash flow information and noncash activities:
For the Six Months Ended June 30, -------------------------------- 1999 1998 ------------- ------------- (In thousands) Cash paid for interest $ 558 $ 771 Cash paid for income taxes 188 444 Cash paid for exploration expenses 2,596 6,425
In June 1999, the Company acquired Nance Petroleum Corporation and Quanterra Alpha Limited Partnership for 259,494 shares of the Company's common stock valued at $3,091,000 together with the assumption of $3,189,000 of Nance Petroleum Corporation debt. The acquisition was accounted for as a purchase. The accompanying notes are an integral part of these consolidated financial statements. -6- ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) --------------------- June 30, 1999 Note 1 - Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. They do not include all information and notes required by generally accepted accounting principles for complete financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in the Annual Report on Form 10-K of St. Mary Land & Exploration Company and Subsidiaries (the "Company") for the year ended December 31, 1998. In the opinion of Management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The accounting policies followed by the Company are set forth in Note 1 to the Company's financial statements in Form 10-K for the year ended December 31, 1998. It is suggested that these financial statements be read in conjunction with the financial statements and notes included in the Form 10-K. Note 2 - Investments In June 1999, the Company participated in a financing package arrangement with Summo Minerals Corporation ("Summo") and Resource Capital Fund L.P. ("RCF"). The Company received $2,096,000 and 17,500,000 Summo warrants in exchange for reducing Summo's note receivable to $1,400,000 and transferring 4,962,047 Summo common shares to RCF. The proceeds received from RCF were applied to the outstanding principle balance of the Summo note receivable and to accrued interest. The loan is secured by Summo's interest in the Lisbon Valley Project and bears interest at LIBOR plus 2.5%. The warrants have an excercise price of CDN$0.12 per share, are fully vested and expire on June 25, 2004. No value has been assigned to the warrants in the financial statements. The remaining 4,962,046 shares of Summo common stock that the Company still owns have a recorded cost basis of zero due to the writedown in the fourth quarter of 1998. The recorded net book value of the Company's investment in Summo, including the note receivable, common stock, warrants, unrealized losses in equity and the unrealized gain on marketable equity securities discussed below is $1,566,000. Management believes that this recorded net book value is realizable. The Company continuously analyzes its net investment in Summo and the effect of persistent depressed copper prices and increased worldwide copper inventory levels on Summo's stock price. The transfer of Summo common shares to RCF reduced the Company's ownership percentage from 37% to 18%. Consequently, the accounting for this investment was changed from the equity method to the cost method in June 1999. The Company recorded $58,000 of equity in Summo's losses in 1999 through May 31, 1999 under the equity method. Under the cost method the Company will record unrealized gains or losses resulting from the fluctuation in the market price of Summo's common stock as a component of comprehensive income within the consolidated statements of shareholders' equity. Losses can only be recorded to the extent of the company's investment, which includes the note receivable from Summo as well as the Summo common shares and warrants owned. As a result of changing to the cost method for the investment in Summo, the Company recorded an unrealized gain of $195,000 in June 1999. This represents the difference in trading value of the Company's ownership in Summo common stock and the recorded basis of the common stock. The June 1999 financing package also resulted in the termination of the May 1997 agreement which was discussed in the Company's Annual Report on Form 10-K/A for the year ended December 31, 1998. In June 1999, the Company completed the purchase of Nance Petroleum Corporation ("Nance") and Quanterra Alpha Limited Partnership for 259,494 shares of the Company's common stock valued at $3,091,000 together with the assumption of $3,189,000 of Nance debt. The acquisition included the 26% of Panterra Petroleum the Company did not previously own as well as certain other properties. The properties acquired are located in the Williston Basin of Montana and North Dakota. The acquisition was accounted for as a purchase. -7- Note 3 - Capital Stock In August 1998, the Company's Board of Directors approved a stock repurchase program whereby the Company may purchase from time to time, in open market purchases or negotiated sales, up to one million shares of its common stock. During the first quarter of 1999 the Company repurchased 35,000 shares of its common stock under the program at a weighted average price of $15.00 per share, bringing the total number of shares repurchased under the program to 182,800 at a weighted-average price of $16.38 per share. Management anticipates that additional purchases of shares by the Company may occur as market conditions warrant. Such purchases would be funded with internal cash flow and borrowings under the Company's credit facility. Note 4 - Income Taxes Federal income tax expense for 1999 and 1998 differ from the amounts that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes primarily due to Section 29 credits, percentage depletion, and the effect of state income taxes. Note 5 - Subsequent Event In July 1999 the Company signed an agreement to acquire King Ranch Energy, Inc. ("KRE") in a merger in which the Company will issue 2,666,252 common shares in exchange for all of the outstanding shares of KRE. The agreement is subject to approval by shareholders of both the Company and KRE. -8- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview St. Mary Land & Exploration Company ("St. Mary" or the "Company") was founded in 1908 and incorporated in Delaware in 1915. The Company is engaged in the exploration, development, acquisition and production of natural gas and crude oil with operations focused in five core operating areas in the United States: the Mid-Continent region; the ArkLaTex region; south Louisiana; the Williston Basin; and the Permian Basin. The Company's objective is to build value per share by focusing its resources within selected basins in the United States where management believes established acreage positions, long-standing industry relationships and specialized geotechnical and engineering expertise provide a significant competitive advantage. The Company's ongoing development and exploration programs are complemented by less predictable opportunities to acquire producing properties having significant exploitation potential, to monetize assets at a premium and to repurchase shares of its common stock at attractive values. Internal exploration, drilling and production personnel conduct the Company's activities in the Mid-Continent and ArkLaTex regions and in south Louisiana. Prior to June 1, 1999, activities in the Williston Basin were conducted through Panterra Petroleum ("Panterra"), a general partnership managed by Nance Petroleum Corporation ("Nance"). The Company owned a 74% interest in Panterra. On June 1, 1999, the Company closed on the acquisition of Nance which owned the remaining 26% interest in Panterra. All of the Company's activities in the Williston Basin are now conducted through Nance as a wholly owned subsidiary of the Company. Activities in the Permian Basin are primarily contracted through an oil and gas property management company with extensive experience in the basin. The Company's presence in south Louisiana includes active management of its fee lands from which significant royalty income is derived. St. Mary has encouraged development drilling by its lessees, facilitated the origination of new prospects on acreage not held by production and stimulated exploration interest in deeper, untested horizons. The Company's discovery on its fee lands at South Horseshoe Bayou in early 1997 and the successful confirmation well in early 1998 proved that significant accumulations of gas are sourced and trapped at depths below 16,000 feet. In August 1998 one of the wells in the South Horseshoe Bayou project experienced shut-in production due to mechanical problems. These mechanical problems and premature water encroachment caused the Company to reduce the project's proved reserves by 38.8 BCFE. An untested fault block to the north of the existing production is expected to spud at South Horseshoe Bayou in the third quarter of 1999. St. Mary seeks to make selective niche acquisitions of oil and gas properties that complement its existing operations, offer economies of scale and provide further development and exploration opportunities based on proprietary geologic concepts. Management believes that the Company's focus on smaller negotiated transactions where it has specialized geologic knowledge or operating experience has enabled it to acquire attractively-priced and under-exploited properties. -9- The results of operations include several property acquisitions made during recent years and their subsequent further development by the Company. In 1996, 1997 and 1998 the Company purchased a series of interests totaling $15.8 million that formed a new core area of focus in the Permian Basin of New Mexico and west Texas. In late 1998 St. Mary, through Panterra, acquired the interests of Texaco, Inc. in several fields in the Williston Basin for $2.1 million. In 1997 the Company acquired an 85% working interest in certain Louisiana properties of Henry Production Company for $3.9 million, and the remaining 15% working interest in these properties was acquired in the first quarter of 1999. In the first and second quarters of 1999, St. Mary acquired additional interests in the West Cameron Block 39 property located offshore Louisiana and various other properties in Louisiana and Oklahoma totaling $1.9 million. In the second quarter of 1999, the Company acquired Nance and Quanterra Alpha Limited Partnership for 259,494 shares of St. Mary common stock valued at $3.1 million and the assumption of $3.2 million in debt. The acquisition was accounted for as a purchase. This acquisition included Nance's 26% interest in Panterra that the Company did not previously own. In July 1999, the Company entered into an agreement to acquire King Ranch Energy, Inc. ("KRE") in a merger in which the Company will issue 2,666,252 shares of its common stock to shareholders of KRE, and KRE will become a wholly owned subsidiary of St. Mary. KRE's properties are located primarily in the Gulf of Mexico and the onshore Gulf Coast. KRE's 1998 production was 48.8 MMCF equivalent per day. KRE's reported reserves at December 31, 1998, plus an acquisition made early in 1999, were 64.7 BCF equivalent and 82% natural gas. The merger agreement, which has been unanimously approved by the Boards of Directors of both companies, is subject to obtaining a favorable vote of the shareholders of St. Mary and KRE. The Company reviews it producing properties for impairments when events or changes in circumstance indicate that an impairment in value may have occurred. The impairment test compares the expected undisounted future net revenueS on a field-by-field basis with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value", which is determined using future net revenues discounted at 15% for the producing property. Future net revenues are estimated using escalated prices and include the estimated effects of the Company's hedging contracts in place at December 31, 1998. All proved reserve catagories at their full estimated value and probable reserves, risk-adjusted downward to 15% of their estimated value, are used in the impairment test. Probable reserves are risk-adjusted to recognize their lower likelihood of occurrence. The risk-adjustment is subject to periodic review based on current economic conditions.Reserve volumes are based on independent engineering consistent with engineering used in evaluating property acquisitions. The Company pursues opportunities to monetize selected assets at a premium and as part of its continuing strategy to focus and rationalize its operations. In December 1998 St. Mary sold a package of non-strategic properties in Oklahoma to ONEOK Resources Company for $22.2 million and sold its remaining minor interests in Canada for $1.2 million, realizing a pre-tax gain of $7.7 million. St. Mary has one principal equity investment, Summo Minerals Corporation ("Summo"). In the second quarter of 1999, the Company's ownership in Summo was reduced to 17.7%, and the Company now uses the investment method to account for this investment. Prior to this reduction, the Company accounted for its investment in Summo under the equity method and included its share of the income or loss from this entity in its consolidated results of operations. The Company recorded $58,000 of equity in Summo's losses in 1999 through the date of the ownership reduction. -10- In June 1998 the Company's stockholders approved an increase in the number of authorized shares of the Company's common stock from 15,000,000 to 50,000,000 shares. In August 1998 the Company's Board of Directors authorized a stock repurchase program whereby St. Mary may purchase from time-to-time, in open market transactions or negotiated sales, up to 1,000,000 of its own common shares. The Company has repurchased a total of 182,800 shares of common stock under this plan through the second quarter of 1999. The Company seeks to protect its rate of return on acquisitions of producing properties by hedging up to the first 24 months of an acquisition's production at prices approximately equal to those used in the Company's acquisition evaluation and pricing model. The Company also periodically uses hedging contracts to hedge or otherwise reduce the impact of oil and gas price fluctuations on production from each of its core operating areas. The Company's strategy is to ensure certain minimum levels of operating cash flow and to take advantage of windows of favorable commodity prices. The Company generally limits its aggregate hedge position to no more than 50% of its total production. The Company seeks to minimize basis risk and indexes the majority of its oil hedges to NYMEX prices and the majority of its gas hedges to various regional index prices associated with pipelines in proximity to the Company's areas of gas production. The Company has hedged approximately 27% of its remaining estimated 1999 gas production at an average fixed price of $2.10 per MMBtu, and 31% of its remaining estimated 1999 oil production at an average fixed price of $16.49 per Bbl, approximately 8% of its estimated 2000 gas production at an average fixed price of $2.42 per MMBtu and 14% of its estimated 2000 oil production at an average fixed price of $16.96 per Bbl and less than 1% of its estimated 2001 gas and oil production at average fixed prices of $2.46 and $15.73, respectively. The Company has also purchased options resulting in price collars on approximately 15% of the Company's remaining estimated 1999 gas production with price ceilings between $2.00 and $3.00 per MMBtu and price floors between $1.50 and $2.30 per MMBtu and price collars on approximately 13% of its remaining estimated 1999 oil production with price floors between $15.00 and $16.70 and price ceilings between $16.85 and $20.90. In 2000 the Company has price collars on approximately 22% of its estimated gas production with price ceilings between $2.50 and $2.94 and price floors between $2.00 and $2.30 and approximately 18% of its estimated oil production with price floors between $15.00 and $18.00 and price ceilings between $16.85 and $21.00. In 2001 the Company has price collars on approximately 9% of its estimated gas production with price ceilings between $2.90 and $2.94 and a price floor of $2.30 and approximately 9% of its estimated oil production with a price floor of $16.44 and price ceilings between $20.64 and $20.65. This Quarterly Report on Form 10-Q includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, expansion and growth of the Company's operations, Year 2000 readiness and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, general economic and business conditions, the business opportunities (or lack thereof) that may be presented to and pursued by the Company, changes in laws or regulations and other factors, many of which are beyond the control of the Company. Readers are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. -11- Results of Operations The following table sets forth selected operating data for the periods indicated:
Three Months Six Months Ended June 30, Ended June 30, ------------------------- ------------------------ 1999 1998 1999 1998 ---------- ---------- ---------- ---------- (In thousands, except BOE data) Oil and gas production Revenues: Working interests $ 14,921 $ 17,862 $ 28,060 $ 34,872 Louisiana royalties 888 2,371 1,518 4,386 ---------- ---------- ---------- ---------- Total $ 15,809 $ 20,233 $ 29,578 $ 39,258 ========== ========== ========== ========== Net production: Oil (MBbls) 313 370 596 692 Gas (MMcf) 5,404 7,255 10,744 13,614 ---------- ---------- ---------- ---------- MBOE 1,214 1,579 2,387 2,961 ========== ========== ========== ========== Average sales price (1): Oil (per Bbl) $ 15.44 $ 13.55 $ 13.57 $ 14.18 Gas (per 2.03 2.10 2.00 2.16 Mcf) Oil and gas production costs: Lease operating expense $ 2,878 $ 3,118 $ 5,975 $ 5,959 Production taxes 1,082 1,055 1,979 2,157 ---------- ---------- ---------- ---------- Total $ 3,960 $ 4,173 $ 7,954 $ 8,116 ========== ========== ========== ========== Additional per BOE data: Sales price $ 13.03 $ 12.81 $ 12.39 $ 13.26 Lease operating expense 2.37 1.97 2.50 2.01 Production taxes .89 .67 .83 .73 --------- ---------- ---------- ---------- Operating margin $ 9.77 $ 10.17 $ 9.06 $ 10.52 Depreciation, depletion and amortization $ 4.35 $ 4.12 $ 4.48 $ 4.01 Impairment of proved properties .20 .68 .10 .49 General and administrative 1.67 .94 1.52 1.49
- ----------------------------- (1) Includes the effects of the Company's hedging activities. Oil and Gas Production Revenues. Oil and gas production revenues decreased $4.4 million, or 22% to $15.8 million for the second quarter of 1999 compared with $20.2 million in 1998. Oil production volumes decreased 16% and gas production volumes decreased 26% for the second quarter of 1999 compared with 1998. Average net daily production declined to 13.3 MBOE for the second quarter of 1999 compared with 17.4 MBOE in 1998. The decline resulted from the significant loss of production at the South Horseshoe Bayou Field in 1998 and 1999 and the sale of certain Oklahoma properties in December 1998. The average realized oil price for the second quarter of 1999 increased 14% to $15.44 per Bbl, while average realized gas prices decreased 3% to $2.03 per Mcf, from their respective 1998 levels. -12- Oil and gas production revenue decreased $9.7 million or 25% to $29.6 million for the six months ended June 30, 1999 compared with $39.3 million in 1998. Oil production volumes decreased 14% and gas production volumes decreased 21% for the six months ended June 30, 1999 compared with 1998. Average net daily production was 13.2 MBOE for the six months ended June 30, 1999 compared with 16.4 in 1998. The production decrease resulted from the significant loss of production at the South Horseshoe Bayou Field in 1998 and 1999 and the sale of certain Oklahoma properties which occurred in late 1998. The average oil price for the six months ended June 30, 1999 decreased 4% to $13.57 per Bbl, and gas prices decreased 7% to $2.00 per Mcf from their respective 1998 levels. The Company hedged approximately 47% of its oil production for the second quarter of 1999 or 148.0 MBbls at an average NYMEX price of $16.41 and realized a $175,000 decrease in oil revenue or $.56 per Bbl on these contracts compared with a $113,000 increase or $.31 per Bbl in 1998. The Company also hedged 62% of its 1999 second quarter gas production or 3.7 million MMBtu at an average indexed price of $2.126 and realized a $67,000 increase in gas revenues or $.01 per Mcf from these hedge contracts compared with a $246,000 increase in gas revenues or $.04 per Mcf in 1998. Oil and Gas Production Costs. Oil and gas production costs consist of lease operating expense and production taxes. Total production costs decreased $213,000 or 5% to $4.0 million for the second quarter of 1999 from $4.2 million in 1998. Total oil and gas production costs per BOE increased 23% to $3.26 for the second quarter of 1999 compared with $2.64 in 1998 due to increased workover costs, reduction in production volumes at South Horseshoe Bayou and the December 1998 sale of producing properties in Oklahoma with lower production costs per BOE. Total production costs decreased $162,000 or 2% to $8.0 million for the six months ended June 30, 1999 from $8.1 million in 1998. Total oil and gas production costs per BOE increased 22% to $3.33 in the first six months of 1999 compared with $2.74 in 1998 due to increased workover costs, reduction in production volumes at South Horseshoe Bayou and the December 1998 sale of producing properties in Oklahoma with lower production costs per BOE. Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion and amortization expense ("DD&A") decreased $1.2 million or 19% to $5.3 million for the second quarter of 1999 from $6.5 million in 1998. DD&A expense per BOE increased 6% to $4.35 in the second quarter of 1999 compared with $4.12 in 1998. This increase is due to the reduction in volumes produced at South Horseshoe Bayou, decreased royalty production from the Fee Lands and the December 1998 sale of producing properties in Oklahoma with lower DD&A expense per BOE. The Company recorded a $247,000 impairment of proved oil and gas properties on the Greensburg prospect in Louisiana for the second quarter of 1999 compared with $1.1 million in 1998. This decrease was due to marginal wells drilled in Oklahoma and Louisiana in 1998 and the adverse effects of low oil prices in the Williston Basin in 1998. DD&A decreased $1.2 million or 10% to $10.7 million for the six months ended June 30, 1999 compared with $11.9 million in 1998. DD&A expense per BOE increased 12% to $4.48 in the six months ended June 30, 1999 compared with $4.01 in 1998. This increase is due to the reduction in volumes produced at South Horseshoe Bayou, decreased royalty production from the Fee Lands, the effect of continued low prices on the Company's oil and gas reserves in the first quarter of 1999, and the December 1998 sale of producing properties in Oklahoma with lower DD&A expense per BOE. The Company recorded $247,000 of impairments of proved oil and gas properties for the six months ended June 30, 1999 due to an unsuccessful recompletion attempt in the Greensburg prospect in Louisiana, compared with $1.4 million in 1998. This decrease was also due to marginal wells drilled in Oklahoma and Louisiana in 1998 and the adverse effects of low oil prices in the Williston Basin in 1998. -13- Abandonment and impairment of unproved properties increased $24,000 or 8% to $336,000 for the second quarter of 1999 compared with $312,000 in 1998 due to additional abandonment of expired leases in 1999. Abandonment and impairment of unproved properties increased $185,000 or 30% to $800,000 for the six months ended June 30, 1999 compared with $615,000 in 1998 due to additional abandonment of expired leases in 1999. Exploration. Exploration expense decreased $1.9 million or 61% to $1.2 million for the second quarter of 1999 compared with $3.1 million in 1998. The decrease results from improved exploratory drilling results in 1999. Exploration expense decreased $3.6 million or 55% to $2.9 million for the six months ended June 30, 1999 compared with $6.5 million in 1998. The decrease results from $795,000 of nonrecurring delay rental payments for the Atchafalaya project in 1998 and improved exploratory drilling results in 1999. General and Administrative. General and administrative expenses increased $553,000 or 37% to $2.0 million in the second quarter of 1999 compared with $1.5 million in 1998. This increase was due to an increase in compensation expense related to stock appreciation rights expenses. General and administrative expenses decreased $786,000 or 18% to $3.6 million for the six months ended June 30, 1999 compared with $4.4 million in 1998. Compensation expense decreased $1.3 million due to a decrease in bonus expense in 1999. This decrease in compensation expense was partially offset by a $490,000 reduction in overhead reimbursements from outside interest owners in properties operated by the Company. Other Operating Expenses. Other operating expenses primarily consist of legal expenses in connection with ongoing oil and gas activities. This expense increased $156,000 or 274% to $213,000 for the second quarter of 1999 compared with $57,000 in 1998. This increase was due to increased activity in the pending litigation that seeks to recover damages from the drilling contractor in connection with the St. Mary Land & Exploration No. 1 well at South Horseshoe Bayou. Other operating expenses increased $246,000 or 267% to $338,000 for the six months ended June 30, 1999 compared with $92,000 in 1998. This increase was due to increased activity in the pending litigation that seeks to recover damages from the drilling contractor in connection with the St. Mary Land & Exploration No. 1 well at South Horseshoe Bayou. Equity in Loss of Summo Minerals Corporation. The Company accounted for its investment in Summo under the equity method through May 31, 1999, and included its share of Summo's loss in its results of operations. The Company decreased its investment in Summo during the second quarter of 1999 and consequently now accounts for its investment in Summo under the investment method. The Company recorded equity in the net loss of Summo of $13,000 for the second quarter of 1999 compared with $509,000 in 1998. This decrease was primarily due to Summo's write-off of its investment in its Cashin and Champion properties in the second quarter of 1998. -14- The Company recorded equity in the net loss of Summo of $58,000 for the six months ended June 30, 1999 compared with $571,000 in 1998. This decrease was due to Summo's write-off of its investment in its Cashin and Champion properties in the second quarter of 1998. Non-Operating Income and Expense. Net non-operating income increased $256,000 to $267,000 in the second quarter of 1999 compared with $11,000 in 1998 due to recognition of interest income on the Company's loan to Summo. Net non-operating income increased $350,000 to $122,000 for the six months ended June 30, 1999 compared with $228,000 net non-operating expense in 1998 due to recognition of interest income on the Company's loan to Summo. Income Taxes. Income tax expense totaled $982,000 in the second quarter of 1999 and $1.1 million in 1998, resulting in effective tax rates of 34.0% and 35.5%, respectively. The reduced expense reflects lower net income from operations before income taxes for 1999 due to lower oil and gas production and lower gas prices. The reduced rate reflects a higher impact on lower net income from Section 29 credits and percentage depletion in 1999. Income tax expense was $1.2 million for the six months ended June 30, 1999 and $1.9 million in 1998, resulting in effective tax rates of 33.4% and 33.8%, respectively. The reduced expense reflects lower net income from operations before income taxes for 1999 due to lower oil and gas production and lower gas prices. The reduced rate reflects a higher impact on lower net income from Section 29 credits and percentage depletion in 1999. Net Income. Net income for the second quarter of 1999 decreased $164,000 or 8% to $1.9 million compared with $2.1 million in 1998. The 22% decrease in oil and gas revenues caused by reductions in produced volumes in the second quarter of 1999 was partially offset by decreases in DD&A, impairment of proved properties, exploration expense, and income tax expense. Net income for the six months ended June 30, 1999 decreased $1.4 million or 38% to $2.3 million compared with $3.7 million in 1998. The 25% decrease in oil and gas revenues caused by reductions in both price and produced volumes was partially offset by decreases in DD&A, impairment of proved properties, exploration expense, general and administrative expense and income tax expense, and by an increase in net non-operating income. Liquidity and Capital Resources The Company's primary sources of liquidity are the cash provided by operating activities, debt financing, sales of non-strategic properties and access to the capital markets. The Company's cash needs are for the acquisition, exploration and development of oil and gas properties and for the payment of debt obligations, trade payables and stockholder dividends. The Company generally finances its exploration and development programs from internally generated cash flow, bank debt and cash and cash equivalents on hand. The Company continually reviews its capital expenditure budget based on changes in cash flow and other factors. -15- Cash Flow. The Company's net cash provided by operating activities decreased $7.1 million or 26% to $20.3 million for the six months ended June 30, 1999 compared with $27.4 million in 1998. Revenues decreased by $9.7 million due to decreased production at South Horseshoe Bayou, decreased production in Oklahoma from the sale of producing properties and due to lower oil and gas prices. Additionally, adjustments for non-cash expenses decreased due to lower DD&A of $1.2 million, a decrease in impairment of proved properties of $1.2 million, and a decrease in accounts receivable of $1.1 million along with an increase in prepaid expenses and other of $3.5 million. Exploratory dry hole costs are included in cash flows from investing activities even though these costs are expensed as incurred. If exploratory dry hole costs had been included in operating cash flows, the net cash provided by operating activities would have been $20.4 million and $24.4 million in 1999 and 1998, respectively. Net cash used in investing activities decreased $14.1 million or 43% to $18.7 million for the six months ended June 30, 1999 compared with $32.8 million in 1998. The decrease is due to an $8.9 million decrease in capital expenditures, an $800,000 increase resulting from acquisitions, a $1.4 million increase from property sales and a $2.4 million decrease resulting from the reduction of the Company's investment in Summo in the first half of 1999. Total capital expenditures, including acquisitions of oil and gas properties, in the first half of 1999 decreased $9.1 million or 29% to $22.3 million compared with $31.4 million in the first half of 1998. If exploratory dry hole costs had been included in operating cash flows rather than in investing cash flows, net cash used in investing activities would have been $18.8 million and $29.9 million in 1999 and 1998, respectively. A portion of the proceeds from sales of oil and gas properties in 1998 were applied to acquisitions of oil and gas properties in 1999 under tax-free exchanges. In a tax-free exchange of properties the tax basis of the sold property carries over to the acquired property for tax purposes. Gains or losses for tax purposes are recognized by amortization of the lower tax basis of the property throughout its remaining life or when the acquired property is sold or abandoned. Net cash used in financing activities increased $7.0 million or 242% to $4.1 million for the six months ended June 30, 1999 compared with net cash provided by financing activities of $2.9 million in 1998. The increase was due to a reduction of long-term debt in 1999 compared with an increase in long-term debt in 1998. The Company had $5.2 million in cash and cash equivalents and had working capital of $8.6 million as of June 30, 1999 compared with $7.8 million in cash and cash equivalents and working capital of $9.8 million as of December 31, 1998. The reduction in cash and cash equivalents is the result of payments to reduce debt levels. Credit Facility. On June 30, 1998, the Company entered into a long-term revolving credit agreement with a maximum loan amount of $200.0 million. The lender may periodically re-determine the aggregate borrowing base depending upon the value of the Company's oil and gas properties and other assets. In May 1999 the borrowing base was reduced $25.0 million by the lender to $80.0 million as a result of reduced reserve pricing and the write down of South Horseshoe Bayou reserves. The accepted borrowing base was $40.0 million at June 30, 1999. The credit agreement has a maturity date of December 31, 2005, and includes a revolving period that matures on December 31, 2000. The Company can elect to allocate up to 50% of available borrowings to a short-term tranche due in 364 days. The Company must comply with certain covenants including maintenance of stockholders' equity at a specified level and limitations on additional indebtedness. As of June 30, 1999, and December 31, 1998, $8.0 million and $10.5 million, respectively, was outstanding under this credit agreement. These outstanding balances accrue interest at rates determined by the Company's debt to total capitalization ratio. During the revolving period of the loan, loan balances accrue interest at the Company's option of either (a) the higher of the Federal Funds Rate plus 1/2% or the prime rate, or (b) LIBOR plus 1/2% when the Company's debt to total capitalization is less than 30%, up to a maximum of either (a) the higher of the Federal Funds Rate plus 5/8% or the prime rate plus 1/8%, or (b) LIBOR plus 1-1/4% when the Company's debt to total capitalization is equal to or greater than 50%. -16- Panterra, in which the Company had a 74% general partnership interest, maintained a separate credit facility with a $21.0 million borrowing base as of December 31, 1998. Upon being acquired by the Company, Nance assumed the responsibility for this credit facility in the second quarter of 1999. Outstanding borrowings under this separate credit facility were $12.1 million as of June 30, 1999 and $12.0 million as of December 31, 1998. St. Mary's portion of the December 31, 1998 outstanding balance was $8.9 million. The credit agreement includes a revolving period converting to a five-year amortizing loan on June 30, 2000. During the revolving period of the loan, loan balances accrue interest at Nance's option of either (a) the bank's prime rate or (b) LIBOR plus 3/4% when Nance's debt to capital ratio is less than 30%, up to a maximum of either (a) the bank's prime rate or (b) LIBOR plus 1-1/4% when Nance's debt to partners' capital ratio is greater than 100%. The Company anticipates using its primary credit facility to retire the balance due on the Nance credit facility. Common Stock. In June 1998 the Company's stockholders approved an increase in the number of authorized shares of the Company's common stock from 15,000,000 to 50,000,000 shares. In August 1998 the Company's Board of Directors authorized a stock repurchase program whereby St. Mary may purchase from time-to-time, in open market transactions or negotiated sales, up to 1,000,000 of its common shares. During 1998 the Company repurchased a total of 147,800 shares of its common stock under the program for $2.5 million at a weighted-average price of $16.71 per share. The Company repurchased 35,000 additional shares for $15.00 per share during the first half of 1999. Management anticipates that additional purchases of shares by the Company may occur as market conditions warrant. Such purchases will be funded with internal cash flow and borrowings under the Company's credit facility. In June 1999 the Company completed the purchase of Nance and Quanterra Alpha Limited Partnership for 259,494 shares of the Company's common stock valued at $3.1 million and the assumption of $3.2 million of Nance debt. Capital and Exploration Expenditures. The Company's expenditures for exploration and development of oil and gas properties and acquisitions are the primary use of its capital resources. Outlook. The Company believes that its existing capital resources, cash flows from operations and available borrowings are sufficient to meet its anticipated capital and operating requirements for 1999. The Company generally allocates approximately 85% of its capital budget to low to moderate-risk exploration, development and niche acquisition programs in its core operating areas. The remaining portion of the Company's capital budget is directed to higher-risk, large exploration ideas that have the potential to increase the Company's reserves by 25% or more in any single year. The Company anticipates incurring approximately $101.0 million for capital and exploration expenditures in 1999 with $37.0 million allocated for ongoing exploration and development in its core operating areas, $9.0 million for large-target, higher-risk exploration and development projects, and $55.0 million for acquisitions of producing properties. These anticipated expenditures include the acquisition of Nance through the issuance of St. Mary common stock and the assumption of Nance debt. These numbers also assume that the KRE acquisition closes through the issuance of St. Mary common stock. Anticipated ongoing exploration and development expenditures for each of the Company's core areas include $22.0 million in the Mid-Continent region, $6.5 million in the ArkLaTex region, $2.0 million in the Williston Basin and $6.5 million allocated within the Permian Basin and south Louisiana regions. -17- The results of operations also include the results of the Company's large-target exploration ideas. During the first half of 1999 two confirmed wells were drilled at the West Cameron Block 39 project. The Company has several prospects in its pipeline of large-target exploration ideas. Drilling was completed at the Stallion project in July 1999, and production tests have recorded rates of 9.4 MMcf per day. The well is currently shut in awaiting pipeline connection. The Company expects to commence the drilling of three additional significant tests in 1999 at its South Horseshoe Bayou, North Parcperdue and Patterson projects in south Louisiana. The amount and allocation of future capital and exploration expenditures will depend upon a number of factors including the number of available acquisition opportunities, the Company's ability to assimilate such acquisitions, the impact of oil and gas prices on investment opportunities, the availability of capital and borrowing capability and the success of its development and exploratory activity which could lead to funding requirements for further development. The Company continuously evaluates opportunities in the marketplace for oil and gas properties and, accordingly, may be a buyer or a seller of properties at various times. St. Mary will continue to emphasize smaller niche acquisitions utilizing the Company's technical expertise, financial flexibility and structuring experience. In addition, the Company is also actively seeking larger acquisitions of assets or companies that would afford opportunities to expand the Company's existing core areas, to acquire additional geoscientists or to gain a significant acreage and production foothold in a new basin within the United States. The persistence of depressed commodity prices and increased worldwide inventory levels of copper have caused Summo's stock price to decline. Management believed that this stock price decline was not temporary and that its value was impaired. Consequently, the Company wrote down its net investment in Summo to net realizable value in the fourth quarter of 1998. Management believes the recorded net investment is recoverable. The Company, through a subsidiary, now owns 4.96 million shares or 17.7% of Summo. In June 1999, the Company participated in a financing package arrangement with Summo Minerals Corporation ("Summo") and Resource Capital Fund L.P. ("RCF"). This package resulted in the Company receiving $2.1 million in exchange for reducing Summo's note receivable to $1.4 million and transferring 4.96 million Summo shares to RCF. Also as part of the arrangement, the Company was granted 17.5 million warrants with an exercise price of CDN$0.12 per share that are fully vested and expire on June 25, 2004. No value has been assigned to the warrants in the financial statements. The proceeds received from RCF were applied to the outstanding principle balance of the Summo note receivable and to accrued interest resulting in a remaining net book value of the Company's entire investment in Summo of $1,566,000. The loan is secured by Summo's interest in the Lisbon Valley Project and bears interest at LIBOR plus 2.5%.The Company continuously analyzes its net investment in Summo and the effect of persistent depressed copper prices and increased worldwide copper inventory levels on Summo's stock price. Future development and financial success of the Lisbon Valley Project are largely dependent on the market price of copper, which is determined in world markets and is subject to significant fluctuations. -18- Impact of the Year 2000 Issue. The following Year 2000 statements constitute a Year 2000 Readiness Disclosure within the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998. The Year 2000 Issue is the result of computer programs and embedded computer chips being written or manufactured using two digits rather than four, or other methods, to define the applicable year. Computer programs and embedded chips that are date-sensitive may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, operate equipment or engage in normal business activities. Failure to correct a material Year 2000 compliance problem could result in an interruption in, or inability to conduct normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, cash flow and financial condition. The Company's approach to determining and mitigating the impact on the Company of Year 2000 compliance issues is comprised of five phases: i) Review and assessment of all internal information technology (IT) systems and significant non-IT systems for Year 2000 compliance; ii) Identify and prioritize systems with Year 2000 compliance issues; iii) Repair or replace and test non-Year 2000 compliant systems; iv) Survey and assess the Year 2000 readiness of the Company's significant vendors, suppliers, purchasers and transporters of oil and natural gas; and, v) Design and implement contingency plans for those systems, if any, that cannot be made Year 2000 compliant before December 31, 1999. The Company completed phases i) and ii) of its plan by August 1998, and has identified the systems requiring repair or replacement in order to be Year 2000 compliant. This review and assessment was completed using outside consultants as well as Company personnel. The Company determined that of its major systems, the software it uses for reservoir engineering, its telephone system, a significant number of the personal computers used by Company personnel and the computer system used by Panterra should be updated or replaced. Phase iii) of the Company's plan of repair and replacement of non-Year 2000 compliant systems is approximately 95% complete. The telephone system and personal computers have been replaced with Year 2000 compliant hardware and software as part of the Company's ongoing upgrade program. The Company purchased a Year 2000 compliant release of the reservoir engineering system and anticipates conversion to and testing of the new system in the third quarter of 1999. In the fourth quarter of 1998 Panterra licensed a Year 2000 compliant system and converted to the new system in January 1999. Nance is now using that system. The systems that have been either upgraded or replaced will be further tested to confirm their Year 2000 compliance. Testing of the Company's primary accounting, lease records and production accounting system was performed during the second quarter of 1999 as planned and confirmed the system to be Year 2000 compliant. The Company presently believes that other less significant IT and non-IT systems can be upgraded to mitigate any Year 2000 issues with modifications to existing software or conversions to new systems. Modifications or conversions to new systems for the less significant systems, if not completed timely, would have neither a material impact on the operations of the Company nor on its results of operations. -19- Under phase iv) of the plan, the Company initiated formal communications with its significant vendors, suppliers and purchasers and transporters of oil and natural gas to determine the extent to which the Company is vulnerable to those third parties' failures to remediate their own Year 2000 issues. The process of collecting information from these third parties is over 50% complete. All of the responses received to date confirm that the respondents will be Year 2000 compliant on a timely basis. Completion of phase iv) of the plan is anticipated in the third quarter of 1999. Until this phase of the plan is complete, management cannot currently predict if third party compliance issues will materially affect the Company's operations. There can be no assurance that the systems of these third parties will be converted timely, or that a failure to remediate Year 2000 compliance issues by another company would not have a material adverse effect on the Company. Phase v) of the Company's Year 2000 plan, the design and implementation of contingency plans for those systems, if any, that cannot be made Year 2000 compliant before December 31, 1999, will be addressed in the last half of 1999. Through June 30, 1999, the Company has spent approximately $450,000 on its Year 2000 efforts. This includes the costs of consultants as well as the cost of repair or replacement of non-compliant hardware and software systems. Additional costs to complete the Company's plan are estimated at approximately $25,000. The Company has not specifically tracked its internal costs of addressing the Year 2000 issue. However, management does not believe these costs to be material. The Company has not completed a comprehensive analysis of the operational problems and costs that would be reasonably likely to result from the Company or its significant third parties' failure to timely complete efforts to remediate Year 2000 issues. Potential "worst case" impacts could include the inability of the Company to deliver its production to, or receive payment from, third parties purchasing or transporting the Company's production; the inability of third party vendors to provide needed materials or services to the Company for ongoing or future exploration, development or producing operations; and the inability of the Company to execute financial transactions with its banks or third parties whose systems fail or malfunction. The Company currently has no reason to believe that any of these contingencies will occur or that its principal vendors, customers and business partners will not be Year 2000 compliant. However, there can be no assurance that the Company will be able to identify and correct all Year 2000 problems or implement a satisfactory contingency plan. Therefore, there can be no assurance that the Year 2000 issue will not materially impact the Company's results of operations or adversely affect its relationships with vendors, customers and other business partners. Accounting Matters In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective for all fiscal quarters of fiscal years beginning after June 15, 1999. The Statement requires companies to report all derivatives at fair value as either assets or liabilities and bases the accounting treatment of the derivatives on the reasons an entity holds the instrument. The Company is currently reviewing the effects this Statement will have on the financial statements in relation to the Company's hedging activities. In June 1999 the FASB issued SFAS No.137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133--An Amendment of FASB Statement No. 133." SFAS No. 137 delayed the effective date of the requirements of SFAS No. 133 to all fiscal quarters of fiscal years beginning after June 15, 2000. -20- Effects of Inflation and Changing Prices Within the United States inflation has had a minimal effect on the Company. The Company cannot predict the future extent of any such effect. The Company's results of operations and cash flows are affected by material changes in oil and gas prices. Oil and gas prices are strongly impacted by North American influences on gas and global influences on oil in relation to supply and demand for petroleum products. Oil and gas prices are further impacted by the quality of the oil and gas to be sold and the location of the Company's producing properties in relation to markets for the products. Oil and gas price increases or decreases have a corresponding effect on the Company's revenues from oil and gas sales. Oil and gas prices also affect the prices charged for drilling and related services. If oil and gas prices increase, there could be a corresponding increase in the cost to the Company for drilling and related services, although offset by an increase in revenues. Also, as oil and gas prices increase, the cost of acquisitions of producing properties increases, which could limit the number and accessibility of quality properties on the market. Material changes in oil and gas prices affect the current and future value of the Company's estimated proved reserves and the borrowing capability of the Company, which is largely based on the value of such proved reserves. Oil and gas price changes have a corresponding effect on the value of the Company's estimated proved reserves and the available borrowings under the Company's credit facility. The last half of 1998 and most of the first quarter of 1999 were characterized by historically low oil prices and weakening gas markets. Capital left the oil and gas industry and caused a significant decrease in the number of working drilling rigs. Consequently, in early 1999 there was an abundance of available drilling rigs, personnel, supplies and services with a corresponding reduction of costs. Oil and gas prices have increased from December 31, 1998 levels during the second quarter of 1999. If prices continue to increase, there could be a return to shortages and a corresponding increase in the costs to the Company of exploration, drilling and production of oil and gas. Financial Instrument Market Risk The Company holds derivative contracts and financial instruments that have cash flow and net income exposure to changes in commodity prices or interest rates. Financial and commodity-based derivative contracts are used to limit the risks inherent in some crude oil and natural gas price changes that have an effect on the Company. In prior years the Company has occasionally hedged interest rates, and may do so in the future should circumstances warrant. The Company's Board of Directors has adopted a policy regarding the use of derivative instruments. This policy requires every derivative used by the Company to relate to underlying offsetting positions, anticipated transactions or firm commitments. It prohibits the use of speculative, highly complex or leveraged derivatives. Under the policy, the Chief Executive Officer and Vice President of Finance must review and approve all risk management programs that use derivatives. The Company's Board of Directors periodically reviews these programs. -21- Commodity Price Risk. The Company uses various hedging arrangements to manage the Company's exposure to price risk from its natural gas and crude oil production. These hedging arrangements have the effect of locking in for specified periods, at predetermined prices or ranges of prices, the prices the Company will receive for the volumes to which the hedge relates. Consequently, while these hedging arrangements are structured to reduce the Company's exposure to decreases in prices associated with the hedged commodity, they also limit the benefit the Company might otherwise receive from price increases associated with the hedged commodity. A hypothetical 10% change in the quarter-end market prices of commodity-based swaps and futures contracts on a notional amount of 9.5 million MMBtu would have caused a potential $141,000 change in net income before income taxes for the Company for gas contracts in place on June 30, 1999. A 10% change in the quarter-end market prices of commodity-based swaps and future contracts on a notional amount of 675 MBbls would have caused a potential $457,000 change in net income before income taxes for the Company for oil contracts in place on June 30, 1999. These hypothetical changes were discounted to present value using a 7.5% discount rate since the latest expected maturity date of some of the swaps and futures contracts is greater than one year from the reporting date. The derivative gain or loss effectively offsets the loss or gain on the underlying commodity exposures that have been hedged. The fair values of the swaps are estimated based on quoted market prices of comparable contracts and approximate the net gains or losses that would have been realized if the contracts had been closed out at quarter end. The fair values of the futures are based on quoted market prices obtained from the New York Mercantile Exchange. Interest Rate Risk. Market risk is estimated as the potential change in fair value resulting from an immediate hypothetical one percentage point parallel shift in the yield curve. A sensitivity analysis presents the hypothetical change in fair value of those financial instruments held by the Company at June 30, 1999, which are sensitive to changes in interest rates. For fixed-rate debt, interest rate changes affect the fair market value but do not impact results of operations or cash flows. Conversely for floating rate debt, interest rate changes generally do not affect the fair market value but do impact future results of operations and cash flows, assuming other factors are held constant. The carrying amount of the Company's floating rate debt approximates its fair value. At June 30, 1999, the Company had floating rate debt of $20.1 million and had no fixed rate debt. Assuming constant debt levels, the results of operations and cash flows impact for the remainder of the year resulting from a one percentage point change in interest rates would be approximately $101,000 before taxes. -22- PART II. OTHER INFORMATION Item 2. Changes in Securities --------------------- As discussed in Item 5 of this Part II, the Board of Directors of St. Mary Land & Exploration Company adopted a Shareholder Rights Plan on July 15, 1999. Pursuant to the Plan each share of common stock of the Company also represents a right to Purchase one additional share of common stock of the Company at the price of $100 per share. Item 5. Other Information ----------------- On July 15, 1999 the Board of Directors of St. Mary Land & Exploration Company adopted a Shareholder Rights Plan. Pursuant to the Plan each share of common stock of the Company also represents a right to purchase one additional share of common stock of the Company at a price of $100 per share. In the event of an acquisition of twenty percent or more of the Company in a transaction not approved by the Board of Directors, each Right will entitle the holder to purchase one share of common stock of the Company or of the acquiror at a price equal to one-half of the trading market price of such stock. The Company may at any time elect to redeem the rights by the payment of $.001 per Right. Rights will not be represented by separate certificates and will not have any public trading market. The Board of Directors of the Company reserves the right at any time to amend the Shareholder Rights Plan. Adoption of the Plan was not in response to any prospective acquisition effort known to the Company. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Description ------- ----------- 2.1 Agreement and Plan of Merger 4.1 Shareholder Rights Plan 27.1 Financial Data Schedule (b) There were no reports on Form 8-K filed during the quarter ended June 30, 1999. -23- SIGNATURES ---------- Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. ST. MARY LAND & EXPLORATION COMPANY November 12, 1999 By /s/ MARK A. HELLERSTEIN ------------------------------------- Mark A. Hellerstein President and Chief Executive Officer November 12, 1999 By /s/ RICHARD C. NORRIS ------------------------------------- Richard C. Norris Vice President - Finance, Secretary and Treasurer November 12, 1999 By /s/ GARRY A. WILKENING ------------------------------------- Garry A. Wilkening Vice President - Administration and Controller