-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GKBT9NH3P/+KCUmLiW4gvxDHCVYSF8jG5kjbraNhKfSaUBr1JlR4cFRm55VwqBsa CbsKMyKuShswpfYRUsLGiQ== 0000276327-99-000017.txt : 19990518 0000276327-99-000017.hdr.sgml : 19990518 ACCESSION NUMBER: 0000276327-99-000017 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990517 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MIDCOAST ENERGY RESOURCES INC CENTRAL INDEX KEY: 0000276327 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 760378638 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-11977 FILM NUMBER: 99628850 BUSINESS ADDRESS: STREET 1: 1100 LOUISIANA STREET 2: STE 2950 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136508900 MAIL ADDRESS: STREET 1: 1100 LOUISANA STREET 2: SUITE 3030 CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: NUGGET OIL CORP DATE OF NAME CHANGE: 19920703 10-Q 1 U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] Quarterly Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended March 31, 1999 [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Commission file number 0-8898 Midcoast Energy Resources, Inc. (Exact name of Registrant as Specified in Its Charter) Nevada 76-0378638 (State or Other Jurisdiction of (I.R.S.Employer Incorporation or Organization) Identification No.) 1100 Louisiana, Suite 2950 Houston, Texas 77002 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code: (713) 650-8900 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 _ On March 31,1999, there were outstanding 7,149,513 shares of the Company's common stock, par value $.01 per share. GLOSSARY The following abbreviations, acronyms, or defined terms used in this Form10-Q are defined below: DEFINITIONS Bank One Bank One, Texas N.A. BOD Board of directors of Midcoast Energy Resources, Inc. BTU British thermal unit. Company Midcoast Energy Resources, Inc. DPI Dufour Petroleum, Inc., a wholly owned subsidiary of Midcoast Energy Resources, Inc. EPS Basic earnings per share. FASB Financial Accounting Standards Board. FERC Federal Energy Regulatory Commission. Flare Flare, L.L.C., a wholly owned subsidiary of Midcoast Energy Resources, Inc. Mcf/day Thousand cubic feet of gas (per day). MCOC Midcoast Canada Operating Corporation, a wholly owned subsidiary of Midcoast Energy Resources, Inc. Midcoast Midcoast Energy Resources, Inc. MIDLA The October 1997 acquisition of the MLGC and MLGT Acquisition Systems. MIT The May 1997 acquisition of the MIT and TRIGAS Acquisition Systems. MIT System A 288-mile interstate transmission pipeline. MLGC System A 386-mile interstate transmission pipeline. MLGT A Louisiana intrastate pipeline Mmbtu Million british thermal units. Mmcf/day Million cubic feet of gas (per day). NGL's Natural Gas Liquids. NOL Net operating losses. SeaCrest SeaCrest Company, L.L.C., a 70% owned subsidiary of Mid Louisiana Gas Transmission Company, which is a wholly owned subsidiary of Midcoast Energy Resources, Inc. SFAS Statement of Financial Accounting Standards TRIGAS Two end-user pipelines in Northern Alabama. System MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999
PART I. FINANCIAL INFORMATION Page Number Item 1. Unaudited Financial Statements Consolidated Balance Sheets as of December 31, 1998 and March 31, 1999. 4 Consolidated Statements of Operations for the three months ended March 31, 1998 and March 31, 1999. 5 Consolidated Statement of Shareholders' Equity for the three months ended March 31, 1999. 6 Consolidated Statements of Cash Flows for the three months ended March 31, 1998 and March 31, 1999. 7 Notes to Consolidated Financial Statements. 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. 12 Item 3. Quantitative and Qualitative Disclosures About Market Risk 20 PART II. OTHER INFORMATION 20 SIGNATURE 21
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except share date)
DECEMBER 31, MARCH 31, ASSETS 1998 1999 CURRENT ASSETS: Cash and cash equivalents $ 200 $ 2,021 Accounts receivable, net of allowance of $92 33,020 43,023 Materials and supplies, at average cost 1,363 1,364 Total current assets 34,583 46,408 PROPERTY, PLANT AND EQUIPMENT, at cost: Natural gas transmission facilities 150,041 180,792 Investment in transmission facilities 1,342 1,358 Natural gas processing facilities 4,917 10,090 Oil and gas properties, using the full- 1,383 1,383 cost method of accounting Other property and equipment 2,872 2,976 160,555 196,599 ACCUMULATED DEPRECIATION, DEPLETION AND (6,308) (7,639) AMORTIZATION 154,247 188,960 OTHER ASSETS, net of amortization 2,512 1,799 Total assets $191,342 $237,167 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities $32,540 $36,277 Current portion of long-term debt 176 176 payable to banks Short-term borrowing from bank 754 5,833 Other current liabilities 124 69 Total current liabilities 33,594 42,355 LONG TERM DEBT PAYABLE TO BANKS 78,082 111,567 OTHER LIABILITIES 2,024 2,078 DEFERRED INCOME TAXES 10,808 11,025 MINORITY INTEREST IN CONSOLIDATED 550 593 SUBSIDIARIES COMMITMENTS AND CONTINGENCIES (Note 4) SHAREHOLDERS' EQUITY: Common stock, $.01 par value, 31,250,000 shares authorized, 7,149,513 shares issued and outstanding at December 31, 1998 and 71 71 March 31, 1999, respectively (Note 2) Paid in capital 80,955 80,955 Accumulated deficit (11,947) (9,134) Unearned compensation (4) (4) Less: Cost of 181,125 and 157,301 (2,791) (2,339) treasury shares, respectively Total shareholders' equity 66,284 69,549 Total liabilities and shareholders'equity $191,342 $237,167
The accompanying notes are an integral part of these financial statements. MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (In thousands, except per share data)
For the Three Months Ended March 31, March 31, 1998 1999 OPERATING REVENUES: Sale of natural gas and other petroleum products $ 63,176 $ 75,200 Transportation fees 2,976 4,632 Natural gas processing and treating revenue 1,099 1,893 Other 88 339 Total operating revenues 67,339 82,064 OPERATING EXPENSES: Cost of natural gas and other petroleum products 60,465 72,272 Natural gas processing and treating costs 444 982 Depreciation, depletion and amortization 693 1,409 General and administrative 1,603 1,928 Total operating expenses 63,205 76,591 OPERATING INCOME 4,134 5,473 NON-OPERATING ITEMS: Interest expense (599) (1,503) Minority interest in consolidated subsidiaries (2) (40) Other income (expense), net 31 5 INCOME BEFORE INCOME TAXES 3,564 3,935 PROVISION FOR INCOME TAXES Current ( 70) (463) Deferred (733) (217) NET INCOME $ 2,761 $ 3,255 EARNINGS PER COMMON SHARE: BASIC $ 0.39 $ .47 DILUTED $ 0.38 $ .46 WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: BASIC 7,101,663 6,931,098 DILUTED 7,350,138 7,148,391
The accompanying notes are an integral part of these consolidated financial statements. MIDCOAST ENERGY RESOURCES INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (In thousands, except share data) TOTAL COMMON PAID-IN ACCUMULATED UNEARNED TREASURY SHAREHOLDERS' STOCK CAPITAL DEFICIT COMPENSATION STOCK EQUITY Balance, December 31, 1997 $ 71 $ 80,681 $ (19,283) $ (18) $ - $ 61,451 Shares issued or vested - - - 14 - 14 under various stock-based compensation arrangements Warrants exercised - 274 - - - 274 Net income - - 9,113 - - 9,113 Treasury stock purchased - - - - (2,791) (2,791) (181,125 shares) Common stock dividends, - - (1,777) - - (1,777) $.24 per share Balance, December 31, 1998 $ 71 $80,955 $(11,947) $ (4) $(2,791) $66,284 Net income - - 3,255 - - 3,255 Treasury stock purchased - - - - (1,990) (1,990) (116,750 shares) Treasury stock issued in - - - - 2,442 2,442 connection with the DPI acquisition (140,574 shares) (Note 3) Common stock dividends, - - (442) - - (442) $.06 per share Balance, March 31, 1999 $ 71 $80,955 $(9,134) $ (4) $(2,339) $ 69,549
The accompanying notes are an integral part of these consolidated financial statements. MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Three Months Ended March 31, March 31, 1998 1999 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 2,761 $ 3,255 Adjustments to arrive at net cash provided (used) in operating activities - Depreciation, depletion and amortization 693 1,409 Deferred income taxes 733 217 Recognition of deferred income (21) (21) Minority interest in consolidated subsidiaries 2 40 Other 13 - Changes in working capital accounts - (Increase) decrease in accounts receivable 577 (10,003) (Increase) decrease in other current assets 163 (1) Increase (decrease) in accounts payable and (5,378) 4,660 accrued liabilities Net cash used by operating activities (457) (444) CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions - (28,591) Capital expenditures (1,622) (4,949) Other (129) (556) Net cash used by investing activities (1,751) (34,096) CASH FLOWS FROM FINANCING ACTIVITIES: Bank debt borrowings 12,233 90,051 Bank debt repayments (9,773) (51,487) Purchase of treasury stock - (1,990) Advances to affiliates - (610) Receipts from affiliates - 839 Contributions from (distributions to) joint (30) - venture partners Dividends on common stock (413) (442) Net cash provided by financing activities 2,017 36,361 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (191) 1,821 CASH AND CASH EQUIVALENTS,beginning of period 308 200 CASH AND CASH EQUIVALENTS, end of period $ 117 $ 2,021 CASH PAID FOR INTEREST $ 842 $ 2,638 CASH PAID FOR INCOME TAXES $ 101 $ -
The accompanying notes are an integral part of these consolidated financial statements. MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION The accompanying unaudited financial information has been prepared by Midcoast in accordance with the instructions to Form 10-Q. The unaudited information furnished reflects all adjustments, all of which were of a normal recurring nature, which are, in the opinion of the Company, necessary for a fair presentation of the results for the interim periods presented. Although the Company believes that the disclosures are adequate to make the information presented not misleading, certain information and footnote disclosures, including significant accounting policies, normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. Certain reclassification entries were made with regard to the Consolidated Financial Statements for the periods presented in 1998 so that the presentation of the information is consistent with reporting for the Consolidated Financial Statements in 1999. It is suggested that the financial information be read in conjunction with the financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. 2. CAPITAL STOCK In February 1999, the Company's BOD's announced a five-for-four common stock split. The stock split was effective for shareholders of record on February 11, 1999, and was distributed on March 1, 1999. No fractional shares were issued as a result of the stock split and stockholders entitled to a fractional share received a cash payment equal to the market value of the fractional share at the close of the market on the record date. Net income per share, dividends per share and weighted average shares outstanding have been retroactively restated to reflect the five-for-four stock split. 3. ACQUISITIONS CALMAR ACQUISITION The Company purchased the Calmar system in Alberta, Canada from Probe Exploration, Inc. ("Probe"). The total value of the transaction was approximately $13.2 million (U.S.). The assets purchased include a 30 Mmcf per day amine sweetening plant, 30 miles of gas gathering pipeline and approximately 4,000 horsepower of compression located near Edmonton, Alberta. The Calmar system currently gathers and treats approximately 24 Mmcf per day of sour gas from 27 producing wells operated by Probe and Courage Energy Inc. In conjunction with the purchase, Probe entered into a gas gathering and treating agreement with us, including the long-term dedication of Probe's reserves in the Leduc Field, a right of first refusal agreement on new or existing midstream assets within a defined 390-square mile area of interest, and an assignment to us of an existing third party gathering and treating agreement. DPI AND FLARE ACQUISITIONS The Company purchased two related companies, Flare and DPI. The total value of the transaction was approximately $11.1 million and could include future consideration should certain contingencies be met. The Flare and DPI shareholders received cash consideration of approximately $3.2 million, Midcoast assumed $5.5 million in debt, and the DPI shareholders received 140,574 shares of our common stock. Flare is a natural gas processing and treating company whose principal assets include 27 portable natural gas processing and treating plants from which it earns revenues based on treating and processing fees and/or a percentage of the NGLs produced. DPI is an NGL, crude oil and CO2 transportation and marketing company. DPI operates 43 NGL and crude oil trucks and trailers, a fleet of 40 pressurized railcars and in excess of 400,000 gallons of NGL storage facilities and product treating and handling equipment. The acquisition was funded through the Company's existing credit facility. TINSLEY ACQUISITION The Company purchased the Tinsley crude oil gathering pipeline for $5.2 million. The Tinsley system is located in Mississippi and consists of 60 miles of crude oil gathering pipeline, related truck and Mississippi River barge loading facilities and 170,000 barrels of crude oil storage. The acquisition was funded through the Company's existing credit facility. SEACREST ACQUISITION The Company also completed the purchase of a 70% interest in SeaCrest for $1.5 million, which in turn acquired seven active offshore natural gas gathering pipelines. The gathering pipelines that SeaCrest acquired from Koch Industries include seven active systems located offshore in the Gulf of Mexico, south of Louisiana, and comprise approximately 81 miles of pipeline. These systems gather gas from 23 offshore producing wells with a current total throughput of approximately 49 Mmcf per day. The acquisition was funded through the Company's existing credit facility. 4. COMMITMENTS AND CONTINGENCIES EMPLOYMENT CONTRACTS Certain executive officers of the Company have entered into employment contracts, which through amendments provide for employment terms of varying lengths the longest of which expires in April 2001. These agreements may be terminated by mutual consent or at the option of the Company for cause, death or disability. In the event termination is due to death, disability or defined changes in the ownership of the Company, the full amount of compensation remaining to be paid during the term of the agreement will be paid to the employee or their estate, after discounting at 12% to reflect the current value of unpaid amounts. MIT CONTINGENCY As part of the Company's MIT Acquisition, the Company has agreed to pay additional contingent annual payments, which will be treated as deferred purchase price adjustments, not to exceed $250,000 per year. The amount each year is dependent upon revenues received by the Company from certain gas transportation contracts. The contingency is due over an eight-year period commencing April 1, 1998, and payable at the end of each anniversary date. The Company is obligated to pay the lesser of 50% of the gross revenues received under these contracts or $250,000. At March 31, 1999, the Company has accrued $250,000 as an additional purchase price adjustment. MIDLA CONTINGENCY As a condition of the Midla Acquisition, the Company agreed that if a specific contract with a third party was executed prior to October 2, 1999, which included specific provisions regarding price and throughputs, Midcoast would be obligated to issue 137,500 warrants to acquire Midcoast common stock at an exercise price of $15.82 per share to Republic. In addition, concurrent with initial expenditures on the project, the Company would incur a $1.2 million cash obligation to Republic. At March 31, 1999, none of the provisions of this contingency have been met. 5. EARNINGS PER SHARE In March 1997, the FASB issued SFAS No. 128, entitled "Earnings Per Share", which establishes new guidelines for calculating earnings per share. The pronouncement is effective for reporting periods ending after December 31, 1997. SFAS No. 128 requires companies to present both a basic and diluted earnings per share amount on the face of the statement of operations and to restate prior period earnings per share amounts to comply with this standard. Basic and diluted earnings per share amounts calculated in accordance with SFAS No. 128 are presented below for the three-months ended March 31 (in thousands, except per share amounts):
For the three months ended March 31, 1998 1999 Average Average Net Shares Earnings Net Shares Earnings Income Outstanding Per Share Income Outstanding Per Share Basic $2,761 7,102 $ .39 $3,255 6,931 $.47 Effect of dilutive securities: Stock options 153 207 Warrants 95 10 Diluted $2,761 7,350 $ .38 $3,255 7,148 $.46
6. SEGMENT DATA The Company has three reportable segments that are primarily in the business of transporting; gathering, processing and treating; and marketing of natural gas and other petroleum products. The Company's assets are segregated into reportable segments based on the type of business activity and type of customer served on the Company's assets. The Company evaluates performance based on profit or loss from operations before income taxes and other income and expense items incidental to core operations. Operating income for each segment includes total revenues less operating expenses (including depreciation) and excludes corporate administrative expenses, interest expense, interest income and income taxes. The accounting policies of the segments are the same as those described in the summary of significant accounting policies, included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. The following table presents certain financial information relating to the Company's business segments (in thousands):
For the three months ended March 31, 1998 1999 Segment Revenues: Transmission $ 41,311 $ 36,024 End-User 23,669 28,547 Gathering, Processing and Treating 2,271 17,154 Total Segment Revenues $ 67,251 $ 81,725 Segment Operating Income: Transmission $ 3,874 $ 4,543 End-User 1,292 1,520 Gathering, Processing and Treating 555 1,094 Total Segment Operating Income 5,721 7,157 Corporate administrative expenses (1,603) (1,928) Interest expense (599) (1,503) Other income (expense), net 45 209 Income Before Income Taxes $ 3,564 $ 3,935
The identifiable assets of the Company, by segment, are as follows (in thousands):
March 31, 1998 1999 Property, Plant and Equipment Transmission $ 85,774 $104,471 End-User 5,158 8,289 Gathering, Processing and Treating 10,858 82,539 Total Segment Assets 101,790 195,299 Corporate and other 672 1,300 Total Assets $102,462 $196,599
The depreciation expense of the Company, by segment, is as follows (in thousands):
For the three months ended March 31, 1998 1999 Depreciation Expense: Transmission $ 390 $ 372 End-User 136 205 Gathering, Processing and Treating 105 737 Total Segment Depreciation Expense 631 1,314 Corporate and other 62 95 Total Depreciation Expense $ 693 $ 1,409
7. NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED The FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". This Statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. This Statement is effective for all fiscal quarters of fiscal years beginning after June 15, 1999. Initial application of this Statement should be as of the beginning of an entity's fiscal quarter; on that date, SFAS No. 133 will require the Company to record all derivatives on the balance sheet at fair value. Changes in derivative fair values will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other shareholders' equity until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative's change in fair value will be immediately recognized in earnings. The impact of SFAS 133 on the Company's financial statements will depend on a variety of factors, including future interpretative guidance from the FASB, the extent of the Company's hedging activities, the types of hedging instruments used and the effectiveness of such instruments. However, the Company does not believe the effect of adopting SFAS 133 will be material to its financial position. 8. SUBSEQUENT EVENTS In May 1999, the Company announced that it intends to make a public offering of 3,370,000 shares of its common stock under its shelf registration statement declared effective on February 5, 1999. Also it is anticipated that three selling shareholders will offer an additional 130,000 shares. The offering is expected to close in late May 1999. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Company has grown significantly as a result of the construction and acquisition of new pipeline facilities. Since January of 1996, the Company acquired 49 pipelines for an aggregate acquisition cost of over $161 million. The Company believes the historical results of operations do not fully reflect the operating efficiencies and improvements that are expected to be achieved by integrating the acquired pipeline systems. As the Company pursues its growth strategy in the future, its financial position and results of operations may fluctuate significantly from period to period. The Company's results of operations are determined primarily by the volumes of gas transported, purchased and sold through its pipeline systems or processed at its processing facilities. Most of the Company's operating costs do not vary directly with volume on existing systems, thus, increases or decreases in transportation volumes on existing systems generally have a direct effect on net income. Also, the addition of new pipeline systems typically results in a larger percentage of revenues being added to operating income as fixed overhead components are allocated over more systems. The Company derives its revenues from three primary sources: (i) transportation fees from pipeline systems owned by the Company, (ii) the processing and treating of natural gas and NGL trucking fees and (iii) the marketing of natural gas and other petroleum products. Transportation fees are received by the Company for transporting gas owned by other parties through the Company's pipeline systems. Typically, the Company incurs very little incremental operating or administrative overhead cost to transport gas through its pipeline systems, thereby recognizing a substantial portion of incremental transportation revenues as operating income. The Company's natural gas processing revenues are realized from the extraction and sale of NGL's as well as the sale of the residual natural gas. These revenues occur under processing contracts with producers of natural gas utilizing both a "percentage of proceeds" and "keep-whole" basis. The contracts based on percentage of proceeds provide that the Company receives a percentage of the NGL and residual gas revenues as a fee for processing the producers gas. The contracts based on keep-whole provide that the Company is required to reimburse the producers for the BTU energy equivalent of the NGLs and fuel removed from the natural gas as a result of processing and the Company retains all revenues from the sale of the NGL's. Once extracted, the NGL's are further fractionated in the Company's facilities into products such as ethane, propane, butanes, natural gasoline and condensate, then sold to various wholesalers along with raw sulfur from the Company's sulfur recovery plant. The Company's processing operations can be adversely affected by declines in NGL prices, declines in gas throughput or increases in shrinkage or fuel costs. The Company's NGL trucking revenues occur in the transportation of crude oil, and NGL's using pressurized tractor- trailers and railcars. The Company's marketing revenues are realized through the purchase and resale of natural gas and other petroleum products to the Company's customers. Generally, marketing activities will generate higher revenues and correspondingly higher expenses than revenues and expenses associated with transportation activities, given the same volumes of gas. This relationship exists because, unlike revenues derived from transportation activities, marketing revenues and associated expenses includes the full commodity price of the natural gas and other petroleum product acquired. The operating income the Company recognizes from its marketing efforts is the difference between the price at which the gas and other petroleum products was purchased and the price at which it was resold to the Company's customers. The Company's strategy is to focus its marketing activities on Company owned pipelines. The Company's marketing activities have historically varied greatly in response to market fluctuations. The Company has had quarter-to-quarter fluctuations in its financial results in the past due to the fact that the Company's marketing sales and pipeline throughputs can be affected by changes in demand for natural gas primarily because of the weather. Although, historically, quarter-to-quarter fluctuations resulting from weather variations have not been significant, the acquisitions of the Magnolia System, the MIT System and the MLGC System have increased the impact that weather conditions have on the Company's financial results. In particular, demand on the Magnolia System, MIT System and MLGC System fluctuate due to weather variations because of the large municipal and other seasonal customers which are served by the respective systems. As a result, historically the winter months have generated more income than summer months on these systems. There can be no assurances that the Company's efforts to minimize such effects will have any impact on future quarter-to-quarter fluctuations due to changes in demand resulting from variations in weather conditions. Furthermore, future results could differ materially from historical results due to a number of factors including but not limited to interruption or cancellation of existing contracts, the impact of competitive products and services, pricing of and demand for such products and services and the presence of competitors with greater financial resources. The Company has also from time to time derived significant income by capitalizing on opportunities in the industry to sell its pipeline systems on favorable terms as the Company receives offers for such systems which are suited to another company's pipeline network. Although no substantial divestitures are currently under consideration, the Company will from time to time solicit bids for selected properties which are no longer suited to its business strategy. RESULTS OF OPERATIONS The following tables present certain data for major operating segments of Midcoast for the three-month periods ended March 31, 1998 and March 31, 1999. A discussion follows which explains significant factors that have affected Midcoast's operating results during these periods. Gross margin for each of the segments is defined as the revenues of the segment less related direct costs and expenses of the segment and does not include depreciation, interest or allocated corporate overhead. As previously discussed, the Company provides marketing services to its customers. For analysis purposes, the Company accounts for the marketing services by recording the marketing activity on the operating segment where it occurs. Therefore, the gross margin for each of the major operating segments include transportation and marketing components.
TRANSMISSION PIPELINES (In thousands, except gross margin per Mmbtu) For the Three Months Ended March 31,1998 March 31,1999 Operating Revenues: Marketing $ 39,314 $ 34,107 Transportation Fees 1,997 1,917 Total Operating Revenues 41,311 36,024 Operating Expenses: Marketing Costs 35,875 30,024 Operating Expenses 1,172 1,085 Total Operating Expenses 37,047 31,109 Gross Margin $ 4,264 $ 4,915 Volume (in Mmbtu) Marketing 16,348 16,313 Transportation 15,152 14,668 Total Volume 31,500 30,981 Gross Margin per Mmbtu $ .14 $ .16
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998 The Company's Transmission segment experienced a 15% increase in gross margin for the three-months ended March 31, 1999 when compared to the equivalent three-month period ended March 31, 1998. This increase was achieved despite a mild winter due to improved marketing margins on a per Mmbtu basis, as well as a reduction in operating expense.
END-USER PIPELINES (In thousands, except gross margin per Mmbtu) For the Three Months Ended March 31, March 31, 1998 1999 Operating Revenues: Marketing $22,905 $ 27,808 End-User Transportation 764 739 Fees Total Operating Revenues 23,669 28,547 Operating Expenses: Marketing Costs 22,196 26,722 Operating Expenses 45 100 Total Operating Expenses 22,241 26,822 Gross Margin $ 1,428 $ 1,725 Volume (in Mmbtu) Marketing 10,236 10,046 Transportation 4,883 6,012 Total Volume 15,119 16,058 Gross Margin per Mmbtu $ .09 $ .11
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998 For the quarter ended March 31, 1999, the End-User segment gross margin increased 21% over the same period in 1998. The increase is primarily attributable to incremental gross margin created by the June 1998 Creole pipeline acquisition, in addition to new natural gas marketing services to a new cogeneration facility near Baton Rouge, Louisiana.
GATHERING PIPELINES AND NATURAL GAS PROCESSING AND TREATING (In thousands, except gross margin per Mmbtu) For the Three Months Ended March 31, March 31, 1998 1999 Operating Revenues: Marketing $ 957 $ 13,285 Gathering Transportation Fees 215 1,976 Processing and Treating Revenues 1,099 1,893 Total Operating Revenues 2,271 17,154 Operating Expenses: Marketing Costs 777 13,332 Operating Expenses 390 1,009 Processing and Treating Costs 444 982 Total Operating Expenses 1,611 15,323 Gross Margin $ 660 $ 1,831 Volume (in Mmbtu) Marketing 461 5,125 Gathering 5,866 19,557 Processing and Treating 511 1,961 Total Volume 6,838 26,643 Gross Margin per Mmbtu $ .10 $ .07
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998 Significant increases in revenues, gross margin and volumes were realized for the quarter ended March 31, 1999 compared to the quarter ended March 31, 1998. The significant increases are a result of the Company's successful acquisition strategy which has recently been focused on assets in this segment. As discussed in Note 3 to the Consolidated Financial Statements, five acquisitions in this segment were consummated in the first quarter of 1999, in addition to the Anadarko and Mendota acquisitions in September and December 1998, respectively. OTHER INCOME, COSTS AND EXPENSES In the three months period ended March 31, 1999, the Company received revenues of $339,000 in other revenues as compared to $88,000 over the same period in 1998. The increase is primarily attributable to a sale of renovated equipment by its Flare subsidiary. In the three month period ended March 31, 1999, the Company's depreciation, depletion and amortization increased to $1,409,000 from $693,000 when compared to 1998. Of the $716,000 increase, 69% is attributable to depreciation on the Anadarko, Flare, SeaCrest, Tinsley, and Dufour acquisitions, which had no equivalent depreciation in 1998. In addition, 20% of the increase is attributable to a one-time impairment on the Company's H&W assets recognized in the quarter. In the three months period ended March 31, 1999, the Company's general and administrative expenses increased to $1,928,000 from $1,603,000 in 1998. The increase is due to incremental overhead on newly acquired assets in late 1998 and 1999 as well as increased staffing levels in 1999. Interest expense for the three months period ended March 31, 1999 increased to $1,503,000 from $599,000 in 1998. The increased debt load in 1999 is primarily associated with the Company's September 1998 acquisition of Anadarko and March 1999 acquisition of MCOC. The additional expense related to increased debt levels was mitigated by a reduction in the Company's weighted average interest rate. The Company's weighted average interest rate was 6.13% for the three-month period ended March 31, 1999 as compared to 7.72% for the three-month period ended March 31, 1998. The Company recognized net income for the three-month period ended March 31, 1999 of $3.26 million as compared to $2.76 million for the equivalent period in 1998. EPS for the three month period ended March 31, 1999 increased 21% from $.39 to $.47 in 1999. The significant improvement in EPS is attributable full quarter operations of acquisitions completed in 1998, and partial quarter operations of new acquisitions in 1999. INCOME TAXES As of December 31, 1998, the Company had NOL carryforwards of approximately $16.6 million, expiring in various amounts from 1999 through 2011. The Company's predecessor and Republic generated these NOLs. The ability of the Company to utilize the carryforwards is dependent upon the Company generating sufficient taxable income and will be affected by annual limitations (currently estimated at approximately $4.9 million) on the use of such carryforwards due to a change in shareholder control under the Internal Revenue Code triggered by the Company's July 1997 common stock offering and the change of ownership created by the Midla Acquisition. CAPITAL RESOURCES AND LIQUIDITY The Company had historically funded its capital requirements through cash flow from operations and borrowings from affiliates and various commercial lenders. However, our capital resources were significantly improved with the equity infusion derived from our initial and secondary common stock offerings in August 1996 and July 1997, respectively. The net proceeds of our combined stock offerings contributed approximately $42.1 million and significantly improved our financial flexibility. This increased flexibility has allowed us to pursue acquisition and construction opportunities utilizing lower cost conventional bank debt financing. During 1998 and to date in 1999, the Company has acquired or constructed $83.1 million of pipeline systems. These acquisition and construction projects increased our long-term debt to total capitalization ratio to 62% at March 31, 1999. As a result of significantly increased cash flows generated from our numerous acquisitions, in September 1998, the Company has amended and restated our bank financing agreement with Bank One. These amendments increased our borrowing availability, modified our letter of credit facility, established a credit sharing, extended the maturity two years to August 2002, modified financial covenants, established waiver and amendment approvals and changed the fee structure to include a decrease in the interest rate on borrowings. The amendments to the credit agreement increased our borrowing availability from $80 million to $150 million (with an initial committed amount of $100 million, which, as noted below, has subsequently been increased to $125 million). The amended credit agreement provides borrowing availability as follows: (i) up to a $15 million sublimit for the issuance of standby and commercial letters of credit and (ii) the difference between the $100 million and the used sublimit available as a revolving credit facility. Effective September 8, 1998, at our option, borrowings under the amended credit agreement accrue interest at LIBOR plus 1.25% or the Bank One base rate. Under the amended credit agreement, a credit sharing was established among Bank One, CIBC Inc., and Bank of America, N.A. The Company is subject to an initial facility fee of $.5 million, which represents all fees due on borrowings up to $100 million. As the Company borrows funds in excess of $100 million, a .15% fee will be imposed. The commitment fee remained at .375%. Additionally, the Company is subject to an annual administrative agency fee of $35,000. In addition, the credit agreement is secured by all accounts receivable, contracts, the pledge of all of our subsidiaries' stock and a first lien security interest in our pipeline systems. The credit agreement also contains a number of customary covenants that require us to maintain certain financial ratios and limit our ability to incur additional indebtedness, transfer or sell assets, create liens, or enter into a merger or consolidation. The Company is in compliance with such financial covenants at March 31, 1999. In March 1999, we further amended the credit agreement to increase the committed amount of borrowing availability and to allow for Canadian dollar denominated loans. In anticipation of a new acquisition in Canada, the Company increased the committed amount of borrowing availability under the credit agreement from $100 million to $125 million. In addition, because the functional currency of a newly formed Canadian subsidiary will be Canadian dollars, the Company revised the credit agreement to allow flexibility to borrow funds in Canadian dollars in order to eliminate foreign currency exchange risk. For the quarter ended March 31, 1999, the Company generated cash flow from operating activities before changes in working capital accounts of approximately $4.9 million and had approximately $7.6 million available under the credit agreement. At March 31, 1999, the Company had committed to making approximately $2.2 million in construction related expenditures for 1999. The Company believes that its credit agreement and funds provided by operations will be sufficient to meet its operating cash needs for the foreseeable future and its projected capital expenditures of approximately $2.2 million. If funds under the credit agreement are not available to fund acquisition and construction projects, the Company would seek to obtain such financing from the sale of equity securities or other debt financing. There can be no assurances that any such financing will be available on terms acceptable to the Company. Should sufficient capital not be available, the Company will not be able to implement its growth strategy as aggressively. In May 1999, the Company announced that it intends to make a public offering of 3,370,000 shares of its common stock under its shelf registration statement declared effective on Feb. 5, 1999. Also it is anticipated that three selling shareholders will offer an additional 130,000 shares. The offering is expected to close in late May 1999. RISK MANAGEMENT The Company utilizes derivative financial instruments to manage market risks associated with certain energy commodities and interest rates. According to guidelines provided by the BOD, the Company enters into exchange-traded commodity futures, options and swap contracts to reduce the exposure to market fluctuations in price and transportation costs of energy commodities and fluctuations in interest rates. The Company does not engage in speculative trading. Approvals are required from senior management prior to the execution of any financial derivative. COMMODITY PRICE RISK The Company's commodity price risk exposure arises from inventory balances and fixed price purchase and sale commitments. The Company uses exchange-traded commodity futures contracts, options and swap contracts to manage and hedge price risk related to these market exposures. The futures and options contracts have pricing terms indexed to both the New York Mercantile Exchange and Kansas City Board of Trade. Gas futures involve the buying and selling of natural gas at a fixed price. Over-the-counter swap agreements require the Company to receive or make payments based on the difference between a fixed price and the actual price of natural gas. The Company uses futures and swaps to manage margins on offsetting fixed-price purchase or sales commitments for physical quantities of natural gas. Options held to hedge risk provide the right, but not the obligation, to buy or sell energy commodities at a fixed price. The Company utilizes options to manage margins and to limit overall price risk exposure. The gains, losses and related costs of the financial instruments that qualify as a hedge are not recognized until the underlying physical transaction occurs. At March 31, 1999, the Company had no unrealized losses from such hedging contracts Interest Rate Risk: The Company's Credit Facility provides an option for the Company to borrow funds at a variable interest rate of LIBOR plus 1.25%. In an effort to mitigate interest rate fluctuation exposure, the Company has entered into $65 million dollars of interest rate swaps under two separate swap agreements. The interest rate swap agreements entered into by the Company effectively convert $65 million of floating-rate debt to fixed-rate debt. The first interest rate swap agreement was entered into with Bank One in December 1997. The swap agreement effectively established a fixed three-month LIBOR interest rate setting of 6.02% for a two-year period on a notional amount of $25 million. This swap agreement was subsequently transferred to Nations Bank in November 1998 and replaced with a new swap agreement. The new swap agreement provides a fixed 5.09% three month LIBOR interest rate to Midcoast with a new two year termination date of December 2000 which may, however, be extended through December 2003 at NationsBank's option on the last day of the initial term. The variable three-month LIBOR rate is reset quarterly based on the prevailing market rate, and Midcoast is obligated to reimburse NationsBank when the three-month LIBOR rate is reset below 5.09%. Conversely, NationsBank is obligated to reimburse Midcoast when the three-month LIBOR rate is reset above 5.09%. At March 31, 1999, the fair value of this interest rate swap through the transferred termination date was a net liability of $75,000. The second interest rate swap agreement was entered into with CIBC in October 1998. The swap agreement effectively established a fixed three-month LIBOR interest rate setting of 4.475% for a three-year period on a notional amount of $40 million. The agreement, however, may be extended an additional two years through November 2003 at CIBC's option on the last day of the initial term. The variable three-month LIBOR rate is reset quarterly based on the prevailing market rate, and Midcoast is obligated to reimburse CIBC when the three-month LIBOR rate is reset below 4.475%. Conversely, CIBC is obligated to reimburse Midcoast when the three-month LIBOR rate is reset above 4.475%. At March 31, 1999, the fair value of this interest rate swap through the initial termination date was a net asset of $1,078,000. The effect of these swap agreements was to lower interest expense by $49,000 in the three-months ended March 31, 1999 and increase interest expense by $12,000 in the three-months ended March 31, 1998. YEAR 2000 COMPLIANCE The Year 2000 ("Y2K") issue is the result of computer programs being written using two digits rather than four to define the applicable year. Any programs that have time-sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in major system failure or miscalculations. As a result, many companies may be forced to upgrade or completely replace existing hardware and software in order to be Y2K compliant. The Company has completed the assessment of its computer software, hardware and other systems, including embedded technology, relative to Y2K compliance. Some of the Company's older computer programs were written using two digits rather than four to define the applicable year. As a result, the Y2K problem identified above does impact some of the Company's computer software and hardware systems. If the problems are not remedied timely, this could cause disruptions of operations, including, among other things, a temporary inability to process transactions, send invoices, or engage in similar normal business activities. Such disruption could materially and adversely affect the Company's results of operation, liquidity and financial condition The Company is currently updating some of its software and hardware in order to improve the timeliness and quality of its business information systems. A byproduct of these improvements includes the purchase of Y2K compliant software and hardware that otherwise are not Y2K compliant today. Software and hardware selection has been completed and implementation has begun with anticipated completion dates ranging from December 1998 to June 1999. A budget for updating computer software and hardware of approximately $1.0 million dollars has been established of which $.8 million has been spent through March 31, 1999. Based on a successful implementation of our Y2K plan, we do not expect the Y2K issue to pose significant operational problems for the Company's computer systems. The Company plans to complete its assessment of its key vendors, customers and other third parties by June 30, 1999 in order to assess the impact such third party Y2K issues will have, if any, on the Company's business operations. The Company does not anticipate that any third parties' Y2K issues will materially impact the Company's operations or financial results. With respect to suppliers, the Company does not utilize any individual supplier in its operations with whom interruptions for Y2K problems could have a material impact on the Company's operations and financial results. In addition, there are alternative suppliers with whom the Company anticipates that it would be able to obtain sufficient quantities of products to continue to conduct its business. Because the Company anticipates that it will complete its Y2K remediation efforts in advance of December 31, 1999, it has not made any contingency plans with respect to its operations and systems. However, a contingency plan will be established by the third quarter of 1999 to address any unforeseen issues, or if the planned improvements are not completed on schedule. The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the intention to comply fully with the Year 2000 Information and Readiness Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law October 19, 1998. All Statements made herein shall be construed within the confines of that Act. To the extent that any reader of the above Year 2000 Readiness Disclosure is other than an investor or potential investor in the Company's Common Stock, this disclosure is made for the SOLE PURPOSE of communicating or disclosing information aimed at correcting, helping to correct and/or avoid Year 2000 failures. DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act of 1934. All statements other than statements of historical fact included in this report are forward looking statements. Such forward looking statements include, without limitation, statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity" regarding Midcoast's estimate of the sufficiency of existing capital resources, whether funds provided by operations will be sufficient to meet its operational needs in the foreseeable future, and its ability to utilize NOL carryforwards prior to their expiration. Although Midcoast believes that the expectations reflected in such forward looking statements are reasonable, it can give no assurance that such expectations reflected in such forward looking statements will prove to be correct. The ability to achieve Midcoast's expectations is contingent upon a number of factors which include (i) timely approval of Midcoast's acquisition candidates by appropriate governmental and regulatory agencies, (ii) the effect of any current or future competition, (iii) retention of key personnel and (iv) obtaining and timing of sufficient financing to fund operations and/or construction or acquisition opportunities. Important factors that could cause actual results to differ materially from the Company's expectations ("Cautionary Statements") are disclosed in this report, including without limitation those statements made in conjunction with the forward looking statements included in this report. All subsequent written and oral forward looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 1998, in addition to the interim consolidated financial statements and accompanying notes presented in Items 1 and 2 of this Form 10-Q. There are no material changes in market risks faced by the Company from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS - None. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS - None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS - None. ITEM 5. OTHER INFORMATION - None. ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: EXHIBITS DESCRIPTION OF EXHIBITS ______ b. Reports on Form 8-K: A report on Form 8-K was filed during the first quarter of 1999. Such report was filed on February 26, 1999 as an Other Event, to amend Registration Statements to include the effects of a five for four stock split. Signature In accordance with the requirements of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MIDCOAST ENERGY RESOURCES, INC. (Registrant) BY: /s/ Richard A. Robert Richard A. Robert Principal Financial Officer Treasurer Principal Accounting Officer Date: May 17, 1999 _______________________________ 1Includes 339 other revenue, less 94 corporate depreciation expense, 40 minority interest and 5 other 2Need to call (Nationsbank) 877-669-7369 for market value of SWAP at 3/31/99 3Need to call Thomas Lee (CIBC) 212-885-4373 for market value of SWAP at 3/31/99. EX-27 2 ARTICLE 5 FIN. DATA SCHEDULE FOR 1ST QUARTER 1999
5 3-MOS DEC-31-1999 MAR-31-1999 2,021,000 0 43,023,000 0 1,364,000 46,408,000 196,559,000 7,639,000 237,167,000 42,355,000 0 71,000 0 0 69,478,000 237,167,000 82,064,000 82,064,000 73,254,000 76,591,000 (35,000) 0 1,503,000 3,935,000 680,000 3,255,000 0 0 0 3,255,000 .47 .46
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