10-K 1 w46879e10-k.txt FORM 10-K COLUMBIA ENERGY GROUP 1 As filed with the United States Securities and Exchange Commission on March 28, 2001. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended DECEMBER 31, 2000 or TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from _____ to _____ C O L U M B I A E N E R G Y G R O U P (Exact name of registrant as specified in its charter) Delaware 13-1594808 ------------------------------ -------------------- (State or other Jurisdiction of (I.R.S. Employer incorporation or organization) (Identification No.) 801 E. 86th Avenue, Merrillville, IN 46410 --------------------------------------------- ------------------ (Address of Principal Executive Office) (Zip Code) Registrant's telephone number, including area code (877) 647-5990 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Which Registered ----------------------------------------- New York Stock Exchange Debentures ---------- 6.61% Series B due November 28, 2002 7.32% Series E due November 28, 2010 6.80% Series C due November 28, 2005 7.42% Series F due November 28, 2015 7.05% Series D due November 28, 2007 7.62% Series G due November 28, 2025 Securities registered pursuant to Section 12(g) of the Act: None 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 proceeding 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/ or No / / Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / / As of November 1, 2000, all shares of the registrant's Common Shares, $.01 par value, were issued and outstanding, all held beneficially and of record by NiSource, Inc. THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I. (1) (A) AND (B) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT. Documents Incorporated by Reference NONE 2 CONTENTS
Page Part I No. ---- Item 1. Business................................................................... 3 Item 2. Properties................................................................. 6 Item 3. Legal Proceedings.......................................................... 8 Item 4. Submission of Matters to a Vote of Security Holders........................ 9 Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.. 9 Item 6. Selected Financial Data.................................................... 10 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................................... 11 Item 8. Financial Statements and Supplementary Data................................ 28 Item 9. Change In and Disagreements with Accountants on Accounting and Financial Disclosure....................................................... 58 Part III Item 10. Directors and Executive Officers of the Registrant......................... 58 Item 11. Executive Compensation..................................................... 58 Item 12. Security Ownership of Certain Beneficial Owners and Management............. 58 Item 13. Certain Relationships and Related Transactions............................. 58 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 58 Signatures.......................................................................... 59 Exhibits............................................................................ 60
2 3 ITEM 1. BUSINESS PART I Columbia Energy Group (Columbia) and its subsidiaries are primarily engaged in natural gas transmission, natural gas distribution, and exploration for and production of natural gas and oil. Columbia, organized under the laws of the State of Delaware on September 30, 1926, is a registered holding company under the Public Utility Holding Company Act of 1935, as amended, (1935 Act) and derives substantially all its revenues and earnings from the operating results of its 19 direct subsidiaries. Merger with NiSource Inc. On November 1, 2000, NiSource Inc. (NiSource) completed the acquisition of Columbia for an aggregate consideration of approximately $6 billion, with 30% of the consideration paid in NiSource common stock and the remaining 70% paid in cash and Stock Appreciation Income Linked Securities(SM) (SAILS(SM)). In addition, NiSource assumed approximately $2 billion in Columbia debt. Presentation of Segment Information Columbia revised its presentation of its primary business segment information beginning with the reporting of second quarter 2000 results. As a result of the discontinuation of most of the businesses within the Energy Marketing Operations, this segment has been deleted. In addition, due to the sale of Cove Point LNG and Columbia Electric Corporation (Columbia Electric) and the pending sale of the propane business, the Power Generation, LNG and Other Operations segment has been renamed Other Products and Services. Transmission and Storage Operations Columbia's two interstate pipeline subsidiaries, Columbia Gas Transmission Corporation (Columbia Transmission) and Columbia Gulf Transmission Company (Columbia Gulf), own a pipeline network of approximately 15,880 miles extending from offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard. In addition, Columbia Transmission operates one of the nation's largest underground natural gas storage systems. Together, Columbia Transmission and Columbia Gulf serve customers in 15 northeastern, mid-Atlantic, mid-western, and southern states and the District of Columbia. Columbia Gulf's pipeline system extends from offshore Louisiana to West Virginia and transports a major portion of the gas delivered by Columbia Transmission. It also transports gas for third parties within the production areas of the Gulf Coast. The transmission and storage subsidiaries are engaged in several projects, the largest of which is the proposed 442-mile Millennium Pipeline Project in which Columbia Transmission is participating. As proposed, the project will transport approximately 700,000 Dekatherm (Dth) of natural gas per day from the Lake Erie region to eastern markets. This project is currently awaiting approval by the Federal Energy Regulatory Commission (FERC). In early November 2000, Columbia Gulf completed the largest expansion of its mainline facility, Mainline '99. At completion, total capacity was increased by approximately 315,000 Dth/day and certificated capacity was increased to approximately 2.2 billion cubic feet (Bcf) per day. Appeals challenging the FERC's authorization of the project are currently pending review by the United States Court of Appeals. Columbia Transmission and Columbia Gulf provide an array of competitively priced natural gas transportation and storage services for local distribution companies (LDCs) and industrial and commercial customers who contract directly with producers or marketers for their gas supplies. See Item 7, page 16 for additional information. Distribution Operations Columbia's five distribution subsidiaries provide natural gas service to nearly 2.1 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. Approximately 32,796 miles of distribution pipelines serve these major markets. The distribution subsidiaries have initiated transportation programs that allow residential and small commercial customers the opportunity to choose their natural gas suppliers and to use the distribution subsidiaries for transportation service only. This ability to choose a supplier was previously limited to larger commercial and industrial customers. See Item 7, page 20 for additional information. Exploration and Production Operations Columbia Energy Resources, Inc. (Columbia Resources) is an exploration and production subsidiary that explores for, develops, gathers and produces natural gas and oil in Appalachia and Canada. As of December 31, 2000, Columbia Resources had net proven oil and gas reserve holdings of 1.1 trillion cubic feet equivalent and owned and operated 6,235 miles of gathering pipelines. See Item 7, page 23 for additional information. Other Products and Services Columbia Transmission Communications Corporation (Transcom), a wholly-owned subsidiary of Columbia, is building a dark-fiber optics telecommunications network primarily along pipeline rights-of-way between New 3 4 ITEM 1. BUSINESS (continued) York and Washington, D.C. The route covers 260 miles and provides access to 16 million people in the busiest telecommunications corridor in the United States. Columbia currently is pursuing strategic alternatives for its telecommunications network in order to focus its resources on its core businesses. Columbia's subsidiary, Columbia Service Partners, is engaged in the business of providing energy-related services to customers of LDCs affiliated with Columbia and to nonaffiliated customers that are served by Columbia's interstate natural gas transmission companies. For additional discussion of Columbia's business segments, including financial information for the last three fiscal years, see Item 7, pages 11 through 26 and Note 17 on pages 50 through 52 of Item 8. Competition The regulatory frameworks applicable to Columbia's rate-regulated operations, at both the state and federal levels, are undergoing fundamental changes. These changes have impacted and will continue to have an impact on Columbia's operations, structure and profitability. At the same time, competition within the gas industry will create opportunities to compete for new customers and revenues. Management continually seeks new ways to be more competitive and profitable in this changing environment, including partnering on energy projects with major industrial customers, providing its gas customers with increased customer choice for new products and services, acquiring companies that will provide improved economies of scale and efficiencies and developing new energy-related products for residential, commercial and industrial customers. Open access to natural gas supplies over interstate pipelines and the deregulation of the commodity price of gas has led to tremendous change in the energy markets, which continue to evolve. During the past few years, LDC customers and marketers began to purchase gas directly from producers and an open competitive market for gas supplies emerged. This separation or "unbundling" of the transportation and other services offered by pipelines and LDCs allows customers to select the service they want independent from the purchase of the commodity. Columbia's gas distribution subsidiaries are involved in programs that provide residential customers the opportunity to purchase their natural gas requirements from third parties and use the distribution subsidiaries for transportation services. It is likely that, over time, distribution companies will have a very limited merchant function. At the same time that natural gas markets are evolving, the markets for competing energy sources are also changing. Forward Looking Statements The foregoing discussion and Item 3 contain "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. Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be achieved. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning Columbia's plans, dispositions, objectives, expected performance, expenditures and recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. From time to time, Columbia may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of Columbia, are also expressly qualified by these cautionary statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially. Realization of Columbia's objectives and expected performance is subject to a wide range of risks and can be adversely affected by, among other things, increased competition in deregulated energy markets, weather, fluctuations in supply and demand for energy commodities, successful consummation of dispositions, growth opportunities for Columbia's businesses, dealings with third parties over whom Columbia has no control, the regulatory process, regulatory and legislative changes as well as changes in general economic, capital and commodity market conditions, counter-party credit risk, many of which are beyond the control of Columbia. In addition, the relative contributions to profitability by each segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time. 4 5 ITEM 1. BUSINESS (continued) Other Relevant Business Information Columbia customer base is broadly diversified, with no single customer accounting for a significant portion of revenues. As of January 31, 2001, Columbia had 8,001 full-time employees of which 1,478 are subject to collective bargaining agreements. Columbia's subsidiaries are subject to extensive federal, state and local laws and regulations relating to environmental matters. These laws and regulations, which are constantly changing, require expenditures for corrective action at various operating facilities, waste disposal sites and former gas manufacturing sites for conditions resulting from past practices that have subsequently become subject to environmental regulation. Information relating to environmental matters is detailed in Item 7, pages 17, 21 and 25, and in Item 8, Note 14I on page 48. 5 6 ITEM 2. PROPERTIES Information relating to properties of subsidiary companies is detailed below and on page 7 and page 36 of Item 8 under Note 1E. Assets under lien and other guarantees are described on page 48 in Note 14D of Item 8. Neither Columbia nor any subsidiary knows of material defects in the title to any real properties of the subsidiaries of Columbia or any material adverse claim of any right, title, or interest therein, pending or contemplated. Substantially all of Columbia Transmission's property has been pledged to Columbia as security for First Mortgage Bonds issued by Columbia Transmission to Columbia. EXPLORATION AND DEVELOPMENT DATA Acreage - At December 31, 2000
Developed Acreage Undeveloped Acreage -------------------------- ------------------------ Gross Net Gross Net --------- --------- --------- --------- United States 2,194,419 2,063,250 1,149,003 1,015,140 Canada............... 3,524 1,626 1,435,544 775,586 --------- --------- --------- --------- Total................ 2,197,943 2,064,876 2,584,547 1,790,726 ========= ========= ========= =========
Net Wells Completed - 12 Months Ended December 31,
Exploratory Development Total ------------------- ------------------ ------------------ Productive Dry Productive Dry Productive Dry ---------- --- ---------- --- ---------- --- United States........ 2000............ 3 1 206 11 209 12 1999............ 3 1 193 37 196 38 1998............ 5 1 136 32 141 33 Canada............... 2000............ 2 3 2 4 4 7 1999............ - 1 1 2 1 3 1998............ - 1 - 1 - 2
Productive and Drilling Wells - At December 31, 2000
Production Wells --------------------------------- Gross Net Wells Drilling -------------- ------------- ----------------- Gas Oil Gas Oil Gross Net --- --- ------ ----- ----- --- United States........ 7,962(a) 105 7,483 66 37 33 Canada............... 26 6 13 4 6 4 ------ ----- ----- ------ ------ ---- Total................ 7,988 111 7,496 70 43 37 ===== ===== ===== ====== ====== ====
(a) Includes 604 multiple completion gas wells, all of which are included as single wells in the table. Also includes 1 gross productive horizontal well. 6 7 ITEM 2. PROPERTIES (Continued) GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 2000
Underground Storage Miles of Pipeline ------------------------------- ------------------------------------------- Gathering Subsidiaries State Acreage Wells and Storage Transmission Distribution Columbia Gas of Kentucky, Inc. KY - - - - 2,463 Columbia Gas of Maryland, Inc. MD - - - - 606 Columbia Gas of Ohio, Inc. OH - - - - 18,622 Columbia Gas of Pennsylvania, Inc. PA 3,300 8 4 - 7,010 Columbia Gas of Virginia, Inc. VA - - - - 4,095 Columbia Gas Transmission Corporation DE - - - 3 - KY - - - 713 - MD 945 - - 179 - NJ - - - 69 - NY 26,286 144 30 321 - NC - - - 1 - OH 486,954 2,477 815 3,921 - PA 64,532 221 72 1,856 - VA - - - 1,117 - WV 285,277 793 272 2,397 - Columbia Gulf Transmission Company KY - - - 716 - LA - - - 2,016 - MS - - - 659 - TN - - - 556 - TX - - - 159 - WY - - - 10 - Columbia Energy Resources, Inc. KY - - 2,332 - - MI - - 6 - - NY - - 136 - - OH - - 128 - - PA - - 38 - - TN - - 45 - - VA - - 439 - - WV - - 3,111 - - Columbia Pipeline Company LA - - 3 - - ------- ----- ----- ------ ------ Total 867,294 3,643 7,431 14,693 32,796 ======= ===== ===== ====== ======
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 2000
Compressor Stations Installed --------------------------- Subsidiaries Number Capacity (hp) Columbia Gas of Kentucky, Inc. - - Columbia Gas of Maryland, Inc. - - Columbia Gas of Ohio, Inc. - - Columbia Gas of Pennsylvania, Inc. 1 800 Columbia Gas of Virginia, Inc. - - Columbia Gas Transmission Corporation - - 5 9,270 1 12,000 - - 3 3,880 1 1,200 25 103,187 23 66,194 10 79,330 39 313,564 Columbia Gulf Transmission Company 2 70,000 6 195,500 3 131,500 2 86,200 - - - - Columbia Energy Resources, Inc. 21 40,788 - - 3 860 3 400 - - 3 925 1 1,000 22 1,999 Columbia Pipeline Company - - --- --------- Total 174 1,118,597 === =========
NOTE: This table excludes minor gas properties and all construction work in progress. The titles to the real properties of the subsidiaries of Columbia have not been examined for the purpose of this document. Neither Columbia nor any subsidiary know of material defects in the title to any of the real properties of the subsidiaries of Columbia or of any material adverse claim of any right, title, or interest therein, pending or contemplated. Substantially all of Columbia Transmission's property has been pledged to Columbia as security for First Mortgage Bonds issued by Columbia Transmission to Columbia. 7 8 ITEM 3. LEGAL PROCEEDINGS A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of Canada Ltd. C.A. No. 9001-03466, Court of Queen's Bench, Alberta, Canada, filed March 7, 1990. The plaintiffs assert, among other things, that the defendant working interest owners, including Columbia Gas Development of Canada Ltd. (Columbia Canada) and various Amoco affiliates, breached an alleged fiduciary duty to ensure the earliest feasible marketing of gas from the Kotaneelee field (Yukon Territory, Canada). The plaintiffs seek, among other remedies, the return of the defendants' interests in the Kotaneelee field to the plaintiffs, a declaration that such interests are held in trust for the plaintiffs and an order requiring the defendants to promptly market Kotaneelee gas or assessing damages. In November 1993, the plaintiffs amended their Amended Statement of Claim to include allegations that the balance in the Carried Interest Account (an account for operating costs, which are recoverable, by working interest owners) which is in excess of the balance as of November 1988 should be reduced to zero. Columbia, on behalf of Columbia Canada, consented to the amendment in consideration of the plaintiffs' acknowledgment that approximately $63 million was properly charged to the account. However, Columbia and Columbia Canada continue to dispute the claim to the extent that the claim challenges expenditures incurred since November 1988, including expenditures made after Columbia Canada was sold to Anderson Exploration Ltd. (Anderson) effective December 31, 1991. A trial commenced in the third quarter of 1996 in the Court of Queen's Bench. Following multiple lengthy adjournments, the parties have concluded presenting their witnesses and evidence and have made their post-trial arguments. The parties are awaiting the courts ruling. Management continues to believe that its defenses are meritorious, and that the risk of any material liability to Columbia is de minimis. Pursuant to an Indemnification Agreement regarding the Kotaneelee Litigation entered into when Columbia Canada was sold to Anderson, Columbia agreed to indemnify and hold Anderson harmless for losses due to this litigation arising out of actions occurring prior to December 31, 1991. An escrow account provides security for the indemnification obligation and is funded by a letter of credit with a face amount of approximately $35,835,000 (Cdn). B. Columbia Gas Transmission Corp. v. Consolidation Coal Co., et al., C.A. No. 99-2071 W.D. Pa. On December 21, 1999, Columbia Transmission filed a complaint against Consolidation Coal Co. and McElroy Coal Co. (collectively, Consol), seeking declaratory and permanent injunctive relief enjoining Consol from pursuing its current plan to conduct longwall mining through Columbia Transmission's Victory Storage Field (Victory) in northern West Virginia. The complaint was served on April 10, 2000. Consol's current plans to longwall mine through the Victory would destroy certain infrastructure of Victory, including all of Columbia Transmission's storage wells in the path of the mining. The parties are holding discussions concerning resolution of this matter. On December 8, 2000, the court denied Consol's Motion to Dismiss for protective order, and discovery by the parties has been initiated. D. Transcom. On March 17, April 11 and April 21, 2000, one of Columbia's subsidiaries, Transcom received directives from the Philadelphia District of the U.S. Army Corps of Engineers (Philadelphia District) and an administrative order from The Pennsylvania Department of Environmental Protection (PA DEP) addressing alleged violations of federal and state laws resulting from construction activities associated with Transcom's laying fiber optic cable along portions of a route between Washington, D.C. and New York City. The order and directives required Transcom to largely cease construction activities. On September 18, 2000, Transcom entered into a voluntary settlement agreement with the Philadelphia District under which Transcom contributed $1.2 million to the Pennsylvania chapter of the Nature Conservancy and the Philadelphia District lifted its directives. As a result of the voluntary agreement with the Philadelphia District and communications with the PA DEP, the Maryland Department of the Environment and the Baltimore District of the U.S. Army Corps of Engineers, work in Pennsylvania and Maryland is now ongoing. Transcom cannot predict the nature or amount of total remedies that may be sought in connection with the foregoing construction activities. E. United States of America ex rel. Jack J. Grynberg v Columbia Gas Transmission Corp. et. al., CA No. 97-2091-K, E.D. La. The plaintiff filed a complaint under the False Claims Act, on behalf of the United States of America, against approximately seventy pipelines including Columbia Gulf. The plaintiff claimed that the defendants had submitted false royalty reports to the government (or caused others to do so) by mismeasuring the volume and heating content of natural gas produced on Federal land and Indian lands. Plaintiff's original complaint was dismissed without prejudice for misjoinder of parties and for failing to plead fraud with specificity. The plaintiff then filed over sixty-five new False Claims Act complaints against over 330 defendants in numerous Federal courts. One of those complaints was filed in the Federal District Court for the Eastern District of 8 9 Louisiana against Columbia and thirteen affiliated entities. Plaintiff's second complaint repeats the mismeasurement claims previously made and adds valuation claims alleging that the defendants have undervalued natural gas for royalty purposes in various ways, including sales to affiliated entities at artificially low prices. Most of the Grynberg cases were transferred to Federal court in Wyoming, in 1999. In December, 1999, the Columbia defendants filed a motion to dismiss plaintiff's second complaint primarily based on a failure to plead fraud with specificity. A hearing was held on the motion in March, 2000 but the court has not yet ruled on. F. Quinque Operating Co. et al v. Gas Pipelines et al., Case No. 99 C 30, Stevens County, Kansas Plaintiff filed an amended complaint in Stevens County, Kansas state court against over 200 natural gas measurers, mostly natural gas pipelines, including Columbia and fourteen affiliated entities. The allegations in Quinque are similar to those made in Grynbeg; however, Quinque broadens the claims to cover all oil and gas leases (other than the Federal and Indian leases that are the subject of Grynberg). Qunique asserts a breach of contract claim, negligent or intentional misrepresentation, civil conspiracy, common carrier liability, conversion, violation of a variety of Kansas statutes and other common law causes of action. Quinque purports to be a nationwide class action filed on behalf of all similarly situated gas producers, royalty owners, overriding royalty owners, working interest owners and certain state taxing authorities. The defendant had previously remanded the case to Federal court. On January 12, 2001, the Federal court remanded the case to state court. G. Vivian K. Kershaw et al. v. Columbia Natural Resources, Inc., et al., CA No. 00-CV-246C(H), W.D.N.Y. In February, 2000, plaintiff filed a complaint in New York state court against Columbia Natural Resources (CNR) and Columbia Transmission. The complaint alleges that Kershaw owns an interest in an oil and gas lease in New York and that the defendants have underpaid royalties on those leases by, among other things, failing to base royalties on the price at which natural gas is sold to the end user and by improperly deducting post-production costs. The complaint also seeks class action status on behalf of all royalty owners in oil and gas leases operated by CNR. Plaintiff seeks the alleged royalty underpayments and punitive damages. Columbia removed the case to Federal court in March, 2000. The Federal court has now remanded Kershaw back to New York State court. H. Anthony Gonzalez, et al. v. National Propane Corporation, et al. Case No. 97 L 15857 Circuit Court of Cook County, Illinois On December 11, 1997, Plaintiffs Anthony Gonzalez, Helen Pieczynski, as Special Administrator of the Estate of Edmund Pieczynski, deceased, Michael Brown and Stephen Pieczynski filed a multiple-count complaint for personal injuries in the Circuit Court of Cook County, Illinois against National Propane Corporation and the Estate of Edmund Pieczynski sounding in strict tort liability and negligence. Plaintiff's complaint arises from an explosion and fire which occurred in a Wisconsin vacation cottage in 1997. National Propane, L.P. filed a third-party complaint for contribution against Natural Gas Odorizing and Phillips Petroleum Company. Written discovery has been completed and the parties are conducting oral discovery of the fact witnesses. There has been no trial date set in the matter, and the next court date is June 27, 2001, at which time further scheduling of discovery will occur. C. McElroy Coal Company v. Columbia Gas Transmission Corporation, No. 5-01 CV 18 U.S. Dist. Ct. N.D. WV, On February 12, 2001, McElroy Coal Company (McElroy), an affiliate of Consolidation Coal Co., filed a complaint against Columbia Transmission in federal court in Wheeling, West Virginia. The West Virginia complaint seeks declaratory and injunctive relief as to McElroy's alleged right to mine coal within Victory and Columbia Transmission's obligation to take all necessary measures to permit McElroy to longwall mine. The complaint also seeks compensation for the inverse condemnation of any coal that cannot be mined due to Columbia Transmission's Victory operations. Except for the claim of inverse condemnation, McElroy's West Virginia complaint appears to be virtually identical to Consolidation Coal Co.'s counterclaim to Columbia Transmission's federal court action in Pennsylvania. We are currently evaluating McElroy's West Virginia complaint and Columbia Transmission's potential responses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS NiSource is the holder of record of all the outstanding common equity securities of Columbia. 9 10 ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA Columbia Energy Group and Subsidiaries ($ in millions) 2000 1999 1998 1997 1996 ----------------------------------------------------------------------------------------------------------------------------- INCOME STATEMENT DATA($) Net revenues 1,936.5 1,908.0 1,823.9 1,863.4 1,826.4 Earnings (Loss) before discontinued operations, extraordinary item and accounting changes 294.6 387.8 308.9 276.3 214.5 Earnings (Loss) before extraordinary item and accounting changes 133.7 249.2 269.2 273.3 221.6 Earnings (Loss) on common stock 133.7 249.2 269.2 273.3 221.6 ----------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET DATA($) Capitalization Common stock equity 2,035.9 2,064.0 2,005.3 1,790.7 1,553.6 Preferred stock -- -- -- -- -- Long-term debt 1,639.1 1,639.3 2,002.8 2,003.0 2,003.8 Short-term debt 521.0 465.5 N/A N/A N/A Current maturities of long-term debt 0.2 311.1 0.2 0.4 0.4 Total 4,196.2 4,479.9 4,008.3 3,794.1 3,557.8 Total assets 7,626.2 7,037.3 6,495.2 6,236.3 5,875.8 ----------------------------------------------------------------------------------------------------------------------------- OTHER FINANCIAL DATA Capitalization ratio(%)(including current maturities *): Common stock equity 48.5 46.1 50.0 47.2 43.7 Preferred stock -- -- -- -- -- Debt 51.5 53.9 50.0 52.8 56.3 Capital expenditures($) 498.3 558.1 460.7 553.3 308.7 Net cash from operations($) 558.0 536.7 686.1 486.8 452.3 Return on average common equity before discontinued operations, extraordinary item and accounting changes(%) 14.4 19.1 16.3 16.5 16.1 -----------------------------------------------------------------------------------------------------------------------------
N/A - Not applicable * Short-term borrowings were used in 1999 and 2000 to finance acquisitions and to fund Columbia's stock repurchase program. Inclusion of the short-term debt in 1999 and 2000 makes those historical ratios more meaningful. 10 11 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Index Page Consolidated Review.................................................... 11 Liquidity and Capital Resources........................................ 13 Transmission and Storage Operations.................................... 16 Distribution Operations................................................ 20 Exploration and Production Operations.................................. 23 Other Products and Services............................................ 25 The Management's Discussion and Analysis of Financial Condition and Results of Operations, including statements regarding market risk sensitive instruments, contains "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. Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be achieved. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning Columbia's plans, dispositions, objectives, expected performance, expenditures and recovery of expenditures through rates, stated on either a consolidated or segment basis, underlying assumptions and statements that are other than historical fact. From time to time, Columbia may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of Columbia, are also expressly qualified by these cautionary statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially. Realization of Columbia's objective and expected performance is subject to a wide range of risks and can be adversely affected by, among other things, increased competition in deregulated energy markets, weather conditions, fluctuations in energy-related commodity prices, service territories, successful consummation of dispositions, growth opportunities for Columbia's regulated and non-regulated businesses, dealings with third parties over whom Columbia has no control, the regulatory process, regulatory and legislative changes, changes in general economic, capital and commodity market conditions and counter-party credit risk, many of which are beyond the control of Columbia. In addition, the relative contributions to profitability by each segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time. Merger Agreement On February 28, 2000, Columbia and NiSource entered into an Agreement and Plan of Merger, dated as of February 27, 2000, and subsequently amended and restated on March 31, 2000 (Merger Agreement). In early June 2000, shareholders of both companies approved the merger between NiSource and Columbia. On November 1, 2000, NiSource completed the acquisition of Columbia for an aggregate consideration of approximately $6 billion, with 30% of the consideration paid in common stock and 70% of the consideration paid in cash and Stock Appreciation Income Linked Securities(SM), referred to as SAILS(SM), which are units consisting of zero coupon debt security coupled with a forward equity contract in NiSource shares. NiSource also assumed approximately $2 billion in Columbia debt. As provided for in the Merger Agreement, NiSource organized a new company that serves as the holding company for Columbia and its other subsidiaries. CONSOLIDATED REVIEW Columbia's income from continuing operations for 2000 was $294.6 million, a decrease of $93.2 million from 1999. The decrease primarily reflected approximately $160 million after-tax in merger-related expenditures in 2000, partially offset by the sale of Columbia Electric and the Cove Point LNG facilities, which sales improved after-tax income by $86.4 million and $58.9 million, respectively. Also improving 2000 results was 9% colder weather compared to 1999. In 1999, a settlement of a co-generation power purchase contract increased after-tax income by $49 million and a producer contract settlement improved income $20.6 million after-tax. Discontinued operations, which include the propane, petroleum and mass marketing businesses of Columbia Energy Services, Inc. (Columbia Energy Services), reflected an after-tax loss of $160.9 million in 2000. Taking into account income from continuing operations and the loss from discontinued operations, Columbia reported net income of $133.7 million in 2000, versus $249.2 million in the prior year. Income from continuing operations for 1999 of $387.8 million increased $78.9 million over 1998, essentially due to a $49 million after-tax gain recorded in connection with the termination of a co-generation power purchase contract, 11 12 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) a $20.6 million after-tax gain related to the final producer contract, an after-tax gain of $7.8 million on the sale of Columbia's interests in the Trailblazer pipeline system and a reduction in tax expense for the realization of certain tax benefits that increased net income by $6.9 million. Tempering these increases was a $16.5 million improvement recorded in 1998 for a settlement gain related to post-retirement benefit costs. The after-tax loss on discontinued operations was $138.6 million in 1999 compared to $39.7 million in 1998. Income from continuing operations together with the loss from discontinued operations resulted in reported net income in 1999 of $249.2 million, a decrease of $20 million from 1998. Net Revenues Total net revenues (revenues less associated product purchased costs) of $1,936.5 million for 2000 reflected an increase of $28.5 million over 1999 primarily due to colder weather during the fourth quarter, an improvement in transportation revenue and increased natural gas prices and production for Columbia Resources' operations. Tempering these improvements was the 1999 gain recorded on the termination of a co-generation power purchase contract and a decline in off-system sales. For 1999, total net revenues of $1,908 million reflected an increase of $84.1 million over 1998, primarily due to the effect of colder weather in 1999 on gas sales for the distribution segment and higher revenues from transportation services in the exploration and production. Also improving revenues in 1999 was the gain recorded for the termination of a co-generation power purchase contract. Tempering this increase were reduced net revenues associated with the net effect of several Columbia Gas of Ohio, Inc. (Columbia of Ohio) regulatory settlements. Expenses Total operating expenses for 2000 were $1,518.2 million, an increase of $305.4 million over 1999, reflecting higher expenses in 2000 attributable to merger-related activities and employee-related costs for Columbia Electric's projects. Tempering this increase were reduced labor and benefits costs as a result of implementing the Voluntary Incentive Retirement Program (VIRP) and the positive impact of the 1997 Columbia of Ohio regulatory settlement. Total operating expenses of $1,212.8 million for 1999 decreased $20.5 million compared to 1998. The decrease was primarily due to the settlement of producer-related litigation in 1999, which reduced operating expenses in that year by $31.7 million and a decrease in depreciation and depletion expense due to the impact of Columbia of Ohio's 1999 regulatory settlement. These decreases were partially offset by higher operation and maintenance expense in 1999 due to start-up costs related to new businesses. Other Income (Deductions)
Twelve Months Ended December 31, (in millions) 2000 1999 1998 ------------------------------------------------------------------------------------------- Interest income and other, net $ 236.3 $ 34.9 $ 14.7 Interest expense and related charges (169.6) (164.2) (144.2) ------------------------------------------------------------------------------------------- TOTAL OTHER INCOME (DEDUCTIONS) $ 66.7 $ (129.3) $ (129.5) -------------------------------------------------------------------------------------------
Other income (deductions) improved income by $66.7 million in 2000 compared to a reduction of $129.3 million in 1999. Interest income and other, net, of $236.3 million was $201.4 million greater than in the year earlier, due largely to the gain from the sale of Columbia Electric and Cove Point facilities in 2000. Tempering this increase was the improvement in 1999 from the sale of Columbia's interests in a pipeline partnership for $12.1 million and from the sale of coal properties for $2.9 million. Interest expense and related charges of $169.6 million increased $5.4 million due largely to higher short-term borrowings to finance acquisitions and fund Columbia's stock repurchase program, as discussed below, tempered by lower interest on contingent taxes. For 1999, other income (deductions) reduced income by $129.3 million, relatively unchanged from 1998. Interest income and other, net of $34.9 million increased $20.2 million when compared to 1998, due largely to the gain on a pipeline partnership sale and the sale of coal properties. Interest expense and related charges of $164.2 million in 1999 increased $20 million over 1998, primarily reflecting an increase in interest expense related to a 1991-1994 settlement of contingent taxes and higher interest costs due to additional borrowing. 12 13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Income Taxes Income tax expense in 2000 totaled $190.4 million, an increase of $12.3 million over 1999, primarily due to the utilization of certain tax benefits and state tax planning initiatives during 1999. Tempering this increase was the impact of lower pre-tax income. Income tax expense of $178.1 million for 1999 increased $25.9 million over the year earlier, primarily reflecting higher pre-tax income. Income benefited as a result of utilizing state tax planning initiatives during 1999 and 1998. Discontinued Operations Discontinued operations reflected an after-tax loss of $160.9 million in 2000 compared to an after-tax loss of $138.6 million in 1999. The increased loss was primarily related to an additional loss recorded for the proposed sale of the propane operations. During 2000, Columbia undertook an evaluation of the appropriateness of remaining in certain businesses given the rapidly changing energy industry and the pending merger with NiSource. During the course of this assessment, it was determined to essentially exit the energy marketing operations, which includes the propane, petroleum and Columbia Energy Services' mass marketing business, as discussed below. In accordance with generally accepted accounting principles, the results from these businesses are now reported as discontinued operations. In the fourth quarter of 1999, Columbia Energy Services, a wholly-owned subsidiary of Columbia, sold its wholesale and trading operations to Enron North America Corporation. In late 1999, Columbia Energy Services also decided to exit its major accounts business. In May 2000, Columbia Energy Services sold its internet-based energy marketing operation, Energy.com. Also in May 2000, Columbia announced that it was in the process of preparing its propane and petroleum businesses for sale. In early 2001, NiSource announced that Columbia Propane Corporation had signed a definitive agreement for approximately $208 million, including $53 million of partnership common units. The closing is expected to occur in the second quarter of 2001. In the third quarter of 2000, Columbia sold its retail energy mass marketing business to The New Power Company, a national residential and small business energy provider. Late in 2000, Columbia sold its interest in Columbia Electric's four power generation plants to a partnership between Delta Power Company and John Hancock Life Insurance Company and the remainder of Columbia Electric to Orion Power. The gain on the sale of these assets resulted in an improvement to consolidated net income of approximately $86 million. LIQUIDITY AND CAPITAL RESOURCES A significant portion of Columbia's operations is subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from sales and transportation services typically exceed cash requirements. Conversely, during the remainder of the year, cash on hand together with external short-term and long-term financing, as needed, is used to purchase gas to place in storage for heating season deliveries, perform necessary maintenance of facilities, make capital improvements in plant and expand service. With the significant increase in gas prices experienced over the last few months of 2000 and early 2001, gas purchased for resale by Columbia's distribution subsidiaries has resulted in an under recovery of these costs given the current rates in effect. However, the recovery of these higher costs are provided for under the current regulatory process. Management believes that this recovery mechanism will continue to provide full recovery of gas costs. Net cash from continuing operations for the year ended December 31, 2000 was $545.2 million, a $237.8 million decrease from the same period in 1999. The decrease was primarily due to the impact of higher gas prices on gas purchased for resale and merger-related and restructuring activities, tempered by increase cash receipts due to the impact of colder weather. Columbia satisfies its liquidity requirements primarily through internally generated funds and from the sale of commercial paper, which is supported by two unsecured bank revolving credit facilities (Credit Facilities). On October 11, 2000, the Credit Facilities were amended and restated, and reduced from the previous level of $1.35 billion to $900 million. The previous $450 million 364-day facility was increased to $850 million, and is scheduled 13 14 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) to expire in October 2001. The prior $900 million five-year facility was decreased to $50 million, shortened to a two-year facility expiring in October 2002, and will be solely used to support the issuance of letters of credit. Interest rates on borrowings under the Credit Facilities are based upon the London Interbank Offered Rate, Certificate of Deposit rates or other short-term interest rates. In addition, the Credit Facilities have a utilization fee if borrowings exceed a certain level. As of December 31, 2000, Columbia had approximately $124.2 million of letters of credit issued, of which approximately $14.6 million were issued under the Credit Facilities, and $521 million of commercial paper was outstanding. NiSource is in the process of arranging a new $2.5 billion revolving credit facility with a syndicate of banks for future working capital requirements. The new facility will refinance and consolidate essentially all of NiSource's existing short-term credit facilities, including Columbia's as discussed above, into one credit facility, through NiSource's financing subsidiary. Management expects to have this new facility in place by the end of the first quarter of 2001. In 1998, Columbia entered into several fixed-to-floating interest-rate swap agreements to modify the interest characteristics of $300 million of its outstanding long-term debt. As a result of these transactions, that portion of Columbia's long-term debt is now subject to fluctuations in interest rates. This allows Columbia to benefit from a lower interest rate environment. In order to maintain a balance between fixed and floating interest rates, Columbia is targeting average annual floating rate debt exposure for 10 to 20% of its outstanding long-term debt. Columbia has an effective shelf registration statement on file with the Securities and Exchange Commission (SEC) for the issuance of up to $1 billion in aggregate of debentures, common stock or preferred stock in one or more series. Currently, Columbia has $750 million available under the shelf registration. Management believes that its sources of funding are sufficient to meet the short-term and long-term liquidity needs of Columbia. Common Stock Repurchase Program During 1999, Columbia's Board of Directors (Columbia's Board) authorized the repurchase of up to $500 million of Columbia's common stock through July 14, 2000, in the open market. During that period, a total of 4,368,300 common shares has been repurchased under this program at a cost of $249.1 million. Purchased shares were held in treasury and have since been retired as a result of the acquisition of Columbia by NiSource. Capital Expenditures The table below reflects actual capital expenditures by segment for 2000 and 1999 and an estimate for year 2001:
(in millions) 2001 2000 1999 -------------------------------------------------------------------------------- Transmission and Storage $132.0 $128.9 $183.4 Distribution 113.0 139.6 145.5 Exploration and Production 132.0 128.9 166.5 Other Products and Services 2.0 96.0 57.3 Corporate -- 4.9 5.4 -------------------------------------------------------------------------------- Total $379.0 $498.3 $558.1 --------------------------------------------------------------------------------
For 2000, capital expenditures were $498.3 million, a decrease of $59.8 million from 1999. The 2000 program included approximately $56 million for extending service to new areas and $60 million for replacement and betterment projects for the distribution segment. The largest portion of the 2000 program for the transmission and storage segment was to ensure the safety and reliability of the pipelines and for market expansion activities as well as new business initiatives. The distribution subsidiaries' program includes investments to extend service to new areas and develop future markets, as well as expenditures ensuring safe, reliable and improved service. The exploration and production segment's 2000 program included amounts for its expanded drilling program and acquisitions. For 2001, Columbia's estimated capital expenditure program of $379 million is $119.3 million lower than the 2000 program which reflects Columbia's effort to divest assets and maintain operations that are in line with its core strategy. Market Risk Exposure Subsidiaries in Columbia's exploration and production segment are exposed to market risk due primarily to fluctuations in commodity prices. NiSource's risk management policy permits the use of certain financial instruments to manage its market risk including futures, swaps and options. Risk management is defined as the process by which the organization ensures that the risks to which it desires to be exposed to achieve its primary 14 15 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) business objectives. Columbia Resources utilizes financial instruments to fix prices for a portion of its future production volumes, which are hedged in the marketplace through a third party. NiSource's senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. In recognition of the increasingly varied and complex nature of the energy business, NiSource's risk management policies and procedures continue to evolve and are subject to ongoing review and modification. As noted, Columbia also utilizes fixed-to-floating interest rate swap agreements to modify the interest characteristics of a portion of its outstanding long-term debt. As a result of these transactions, $300 million of Columbia's long-term debt is now subject to fluctuations in interest rates. Voluntary Workforce Reduction Programs As a result of Columbia's ongoing review of its various business units, the utilization of improved technologies and process improvement initiatives, management has identified a number of ways of working more efficiently. As discussed below, Columbia implemented the VIRP at various times during 1999 and 2000 for active employees who were age fifty and above with at least five years of service. In September 1999, Columbia Transmission announced a VIRP that provided a retirement incentive for eligible employees as of March 1, 2000. Approximately 486 of its 600 eligible employees elected early retirement under this program with the majority of the retirements occurring in the first quarter of 2000. In February 2000, the five distribution subsidiaries and Columbia Energy Group Service Corporation (Service Corp.) announced the introduction of a VIRP for 879 eligible employees as of June 1, 2000. The acceptance period ended on April 30, 2000, with 679 employees accepting the VIRP. The majority of the retirements occurred on June 1, 2000. In September 2000, Columbia announced that employees of the five distribution subsidiaries and Service Corp., whom were not eligible for the February 2000 program, as well as the employees of Columbia Resources, would be offered a VIRP as of January 1, 2001. Approximately 172 of its 400 eligible employees elected early retirement. The actual retirement date for those employees electing the VIRP will be based on the specific business needs of the business units. Following the announcement of the merger with NiSource, another VIRP was offered to certain employees not eligible for the earlier VIRPs. The acceptance period ended on December 22, 2000, with 64 employees accepting the VIRP. The majority of the retirements occurred on January 1, 2001. Presentation of Segment Information Columbia revised its presentation of its primary business segment information beginning with the reporting of second quarter 2000 results. As a result of the discontinuation of most of the businesses within the Energy Marketing Operations, this segment has been deleted. In addition, due to the sale of Cove Point LNG, the Power Generation, LNG and Other Operations segment has been renamed Other Products and Services. The results for Columbia Service Partners Inc., which provides energy-related services to primarily residential customers, were previously in Energy Marketing Operations. These operations were reclassified to Other Products and Services. 15 16 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) TRANSMISSION AND STORAGE OPERATIONS Columbia's transmission and storage segment consists of the operations of Columbia Transmission, Columbia Gulf and Columbia Pipeline Corporation. Together they own a pipeline network of approximately 15,880 miles extending from offshore in the Gulf of Mexico to Lake Erie, New York and the eastern seaboard serving 15 northeastern, mid-Atlantic, mid-western and southern states, as well as the District of Columbia. In addition, Columbia Transmission operates one of the nation's largest underground natural gas storage systems. Proposed Millennium Pipeline Project The proposed Millennium Pipeline Project (Millennium Project), in which Columbia Transmission is participating and will serve as developer and operator, will transport western gas supplies to northeast and mid-Atlantic markets. The 442-mile pipeline will connect to TransCanada Pipe Lines Ltd. at a new Lake Erie export point and transport approximately 700,000 Dth per day to eastern markets. There are currently eight shippers who have signed agreements for a significant portion, in aggregate, of the available capacity. Based on delays attributed to the regulatory approval process at the FERC, the Millennium Project sponsors have advised the FERC of a revised in-service date of November 1, 2002. The sponsors of the proposed Millennium Project are Columbia Transmission, Westcoast Energy, Inc., TransCanada Pipe Lines Ltd. and MCN Energy Group, Inc. Volunteer Pipeline On April 14, 1999, Columbia Gulf, MCN Energy Group, Inc. and AGL Resources, Inc. announced the start of an open season on the proposed Volunteer Pipeline (Volunteer). They were offering approximately 250,000 Dth per day of capacity in a natural gas pipeline extending approximately 160 miles from an interconnection near Portland, Tennessee to an interconnection near Chattanooga, Tennessee. Subsequent to the open season, AGL Resources, Inc. withdrew its participation in the project. Volunteer anticipates additional interconnections with several pipeline companies including Columbia Gulf who will also serve as operator of the new pipeline facilities. At the end of the open season in May 1999, nearly a dozen companies requested more than 440,000 Dth per day of capacity on Volunteer. Volunteer expects to provide firm natural gas transportation from the mid-continent into the Atlanta, Georgia, and other southeastern markets. Volunteer is currently in the process of negotiating with potential shippers, and the timing of a FERC construction application is contingent upon a final determination of market demand based upon these negotiations. Volunteer is exploring several construction options and timelines that would have the pipeline in place to meet market demand as it evolves. Competition and the Effect of LDC Unbundling Services Columbia's transmission and storage subsidiaries compete with other interstate pipelines for the transportation and storage of natural gas. Since the issuance of FERC Order No. 636, various states throughout Columbia Transmission's service area have initiated proceedings dealing with open access and unbundling of LDC services. Among other things, unbundling involves providing all LDCs with the choice of what entity will serve as transporter as well as merchant supplier. While the scope and timing of these various unbundling initiatives varies from state to state, retail choice programs are being extended to increasing numbers of LDC customers throughout Columbia Transmission's market area. Among the issues being addressed in the state unbundling proceedings is the treatment of the pipeline transmission and storage agreements that have underpinned the traditional LDC merchant function. In the case of Columbia Transmission and Columbia Gulf, contracts covering the majority of their firm transportation and storage quantities with LDCs have primary terms that extend to October 31, 2004. Management fully expects that the LDCs, or those entities to which pipeline capacity may be assigned as a result of the LDC unbundling process, will continue to fulfill their obligations under these contracts. However, in view of the changing market and regulatory environment, Columbia's transmission companies have commenced the process of discussing long-term transportation and storage service needs with their firm customers. Those discussions could result in the restructuring of some of these contracts on mutually agreeable terms prior to 2004. Regulatory Matters Mainline `99 Columbia Gulf filed an application with the FERC in June 1998 for authority to increase the maximum certificated capacity of its mainline facilities. Columbia Gulf's largest expansion of its mainline facilities, referred to as 16 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Mainline `99, was authorized by the FERC in February 1999. The Mainline `99 project has increased Columbia Gulf's certificated capacity to nearly 2.2 Bcf/day by replacing certain compressor units and increasing the horsepower capacity of other compressor stations. On December 1, 1999, approximately 270,000 Dth/day of additional capacity was made available on Columbia Gulf's mainline and approximately 45,000 Dth/day of additional capacity was made available on the mainline on November 1, 2000, following the construction of all of the facilities authorized by the FERC as part of the Mainline `99 project. Appeals challenging the FERC's authorization of the Mainline `99 facilities have been filed and are pending before the United States Court of Appeals for the District of Columbia. Discussions with FERC The transmission and storage subsidiaries were in confidential discussions with the staff of the FERC to resolve a previously disclosed regulatory issue. In late October 2000, the FERC issued an order approving a settlement between the FERC staff and the transmission subsidiaries resolving all regulatory issues. The financial impact of this settlement was recorded in the third quarter of 2000 and was not material to consolidated results. Columbia Gulf Mainline Capacity Proceeding In 1993, the FERC directed Columbia Gulf to show cause as to why it had not sought FERC abandonment authorization to reduce capacity on its mainline facility. In an August 8, 1997 order, the FERC approved a settlement between Columbia Gulf and FERC's enforcement staff requiring Columbia Gulf to conduct a 30-day open season on additional firm mainline capacity up to its certificated design. Although certain of Columbia Gulf's customers challenged the terms of the settlement, Columbia Gulf concluded the open season on December 15, 1997 which resulted in requests for capacity that exceeded the capacity specified in Columbia Gulf's FERC certificate. In orders issued in December 1998 and 1999, the FERC has rejected challenges to the settlement and denied rehearing. In its order issued December 22, 1999, the FERC affirmed the validity of the 1997 open season but indicated that an additional open season in compliance with the settlement will be necessary. In early February 2000, several appeals of the FERC's orders in this proceeding were filed with the federal circuit court of appeals and are still pending. Columbia Gulf Voluntary Severance Plan Columbia Gulf announced a voluntary severance plan (VSP) on September 19, 2000, for its workforce to assist in the elimination of approximately 70 positions. The positions were eliminated by December 31, 2000. The cost of the VSP was approximately $6.6 million and was recognized in the fourth quarter of 2000. Storage Base Gas Sales Columbia Transmission has agreements to sell 5.2 Bcf of base gas volumes in the first quarter of 2001. In addition, Columbia also sold 4.8 Bcf of base gas volumes in the first quarter of 2000 and 7 Bcf in the first quarter of 1999 resulting in a pre-tax gain of $10.9 and $14.4 million, respectively. Base gas represents storage volumes that are maintained to ensure that adequate pressure exists to deliver current inventory. However, as a result of ongoing improvements made in Columbia Transmission's storage operations, there are instances when these storage volumes are determined to be unnecessary to maintain deliverability of current inventory. As a result of first quarter 2000 base gas sales, Columbia Transmission reached the cumulative $60 million pre-tax gain level above which it must share any future gains equally with its customers pursuant to the terms of a prior rate settlement. Capital Expenditure Program The transmission and storage segment's net capital expenditure program was $128.9 million in 2000 and is projected to be approximately $132 million in 2001. New business initiatives totaled approximately $24 million in 2000 and are expected to be $49.2 million in 2001. The remaining expenditures are for modernizing and upgrading facilities. Environmental Matters Columbia Transmission continues to conduct assessment, characterization and remediation activities at specific sites under a 1995 Environmental Protection Agency (EPA) Administrative Order by Consent (AOC). The program pursuant to the AOC covers approximately 240 facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations and about 3,700 storage well locations. As of December 31, 2000, field characterization has been performed at almost all of these sites, with the exception of the storage well locations. Site characterization reports and remediation plans, which must be submitted to the EPA for approval, are in various stages of development and completion. Characterization of the storage well locations were initiated in the fall of 2000 and are yet to be completed. Significant remediation has taken place at mercury measurement stations, liquid removal point sites, and at a limited number of the 240 facilities. 17 18 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Only those site investigation, characterization and remediation costs currently known and determinable can be considered "probable and reasonably estimable" under Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" (SFAS No. 5). As costs become probable and reasonably estimable, the associated reserves will be adjusted as appropriate. Columbia Transmission is unable, at this time, to accurately estimate the time frame and potential costs of the entire program. Management expects that as characterization is completed and approved by the EPA, additional remediation work is performed and more facts become available, Columbia Transmission will be able to develop a probable and reasonable estimate for the entire program or a major portion thereof consistent with Securities and Exchange Commission's Staff Accounting Bulletin No. 92, SFAS No. 5, and American Institute of Certified Public Accountants Statement of Position 96-1. At the end of 2000, the remaining environmental liability recorded on the balance sheet for the gas transmission and storage operations was $104.5 million. Columbia Transmission's environmental cash expenditures are expected to be approximately $16 million in 2001 and to remain at this level in the foreseeable future. These expenditures will be charged against the previously recorded liability. A regulatory asset has been recorded to the extent environmental expenditures are expected to be recovered through rates. Management does not believe that Columbia Transmission's environmental expenditures will have a material adverse effect on its operations, liquidity or financial position, based on known facts, existing laws, regulations, its cost recovery settlement with customers and the long time period over which expenditures will be made. In addition, predecessor companies of Columbia Transmission may have been involved in the operation of manufactured gas plants. When such plants were abandoned, material used and created in the process was sometimes buried at the site. Columbia Transmission is as yet unable to determine if it will become liable for any characterization or remediation costs at such sites. Throughput Columbia Transmission's throughput consists of transportation and storage services for LDCs and other customers within its market area. Throughput for Columbia Gulf reflects mainline transportation services from Rayne, Louisiana to Leach, Kentucky and short-haul transportation services from the Gulf of Mexico to Rayne, Louisiana. In 2000, throughput for the transmission and storage segment of 1,267.3 Bcf increased 16.5 Bcf over 1999, due to colder weather, increased mainline requirements, and increased transportation services from Columbia Transmission's market expansion project. Market area transportation by Columbia Transmission of 1,043 Bcf increased by 37.3 Bcf. Mainline transportation for Columbia Gulf increased 23.2 Bcf in 2000, reflecting the impact of colder weather in Columbia Transmission's operating territory and the sale of all of the remaining Mainline `99 capacity. Short-haul transportation of 194.7 Bcf in 2000 was down 25.5 Bcf from 1999, due to a reduced need for transportation services and reduced throughput from off system supply sources. Throughput for 1999 of 1,250.8 Bcf increased 53.3 Bcf when compared to the year earlier primarily due to colder weather in 1999 and increased transportation services from Columbia Transmission's market expansion project. Market area transportation of 1,005.7 Bcf by Columbia Transmission increased 57.9 Bcf in 1999. Mainline transportation for Columbia Gulf increased 30.9 Bcf in 1999 over 1998, reflecting the impact of colder weather in Columbia Transmission's operating territory. Short-haul transportation of 220.2 Bcf in 1999 was down 11 Bcf from 1998, due to a decline in market demand in the area south of Rayne, Louisiana. Operating Revenues Operating revenues of $855.8 million in 2000 were up $19.4 million over 1999. After adjusting for revenue items that are offset in operating expenses, operating revenues increased by $14.5 million, due to increased transportation services and higher revenues related to Columbia Transmission's market expansion projects. Operating revenues in 1999 of $836.4 million were essentially unchanged from 1998. After adjusting for revenue items that are offset in operating expenses, operating revenues in 1999 increased by $6.1 million primarily due to an increase in Columbia Transmission's market expansion contracts. Operating Income In 2000, operating income for the transmission and storage segment of $264.9 million decreased $85.2 million from 1999. This decrease primarily reflected the impact of merger-related expenditures and the favorable impact of a 1999 producer settlement. The 2000 results benefited from increased transportation services and higher revenues related to Columbia Transmission's market expansion project in addition to the positive impact of lower operating costs as a result of the VIRP. 18 19 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Operating income of $350.1 million for 1999 increased $24 million over 1998. This increase primarily reflected the pre-tax benefit of a producer settlement and higher revenues primarily resulting from Columbia Transmission's market expansion project. STATEMENTS OF OPERATING INCOME FROM TRANSMISSION AND STORAGE OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 2000 1999 1998 ----------------------------------------------------------------------------- OPERATING REVENUES Transportation revenues $ 649.3 $ 615.0 $ 620.4 Storage revenues 177.8 182.4 186.0 Other revenues 28.7 39.0 32.3 ----------------------------------------------------------------------------- Total Operating Revenues 855.8 836.4 838.7 ----------------------------------------------------------------------------- OPERATING EXPENSES Operation and maintenance 427.9 358.9 358.9 Settlement of gas supply charges - (31.7) - Depreciation 109.3 106.2 101.8 Other taxes 53.7 52.9 51.9 ----------------------------------------------------------------------------- Total Operating Expenses 590.9 486.3 512.6 ----------------------------------------------------------------------------- OPERATING INCOME $ 264.9 $ 350.1 $ 326.1 -----------------------------------------------------------------------------
TRANSMISSION AND STORAGE OPERATING HIGHLIGHTS
2000 1999 1998 1997 1996 ------------------------------------------------------------------------------------------ CAPITAL EXPENDITURES ($ in millions) 128.9 183.4 210.0 251.4 142.7 ------------------------------------------------------------------------------------------ THROUGHPUT (Bcf) Transportation Columbia Transmission Market area 1,043.0 1,005.7 947.8 1,032.6 1,102.4 Columbia Gulf Mainline 617.4 594.2 563.3 607.5 633.7 Short-haul 194.7 220.2 231.2 252.4 266.5 Intrasegment eliminations (587.8) (569.3) (544.8) (591.0) (624.5) ------------------------------------------------------------------------------------------ TOTAL THROUGHPUT 1,267.3 1,250.8 1,197.5 1,301.5 1,378.1 ------------------------------------------------------------------------------------------
19 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) DISTRIBUTION OPERATIONS Columbia's five distribution subsidiaries (Distribution) provide natural gas service to nearly 2.1 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. Market Conditions Weather in Distribution's market area during 2000 was 9% colder than 1999. As a result, Distribution's weather-sensitive deliveries were up 43 Bcf from 1999. Competition Distribution competes with investor-owned, municipal, and cooperative electric utilities throughout its five-state service area, and to a lesser extent with propane and fuel oil suppliers. Electric competition is generally strongest in the residential and commercial markets of Kentucky, southern Ohio, southwestern Pennsylvania and western Virginia where rates are primarily driven by low-cost coal-fired generation. The northern Ohio and Pittsburgh areas have less competitive electric rates due to the use of higher-cost nuclear-generated power. It is too soon to determine what impact, if any, deregulation of the electric industry will have on the competitive situation. Distribution continues to be a strong competitor in the energy market for new homes as a result of strong customer preference for natural gas. Approximately 35% of Distribution's industrial and commercial throughput, or 122 Bcf, is susceptible to bypass because these customers are located close to multiple natural gas pipelines and local gas distribution companies. As a result of Distribution's competitive strategies, substantial inroads by other natural gas competitors have been avoided to date. Regulatory Matters In December 1999, the Public Utilities Commission of Ohio (PUCO) approved a request from Columbia of Ohio that extends Columbia of Ohio's Customer CHOICE(SM) program through October 31, 2004, freezes base rates through October 31, 2004, and resolves the issue of transition capacity costs. Under the agreement, Columbia of Ohio would assume total financial risk for mitigation of transition capacity costs at no additional cost its to customers. Among other items, Columbia of Ohio has the opportunity to utilize non-traditional revenue sources as a means of offsetting the costs. Columbia of Ohio extended its Customer CHOICE(SM) program to all of its nearly 1.3 million customers in mid-1998 and there are over 470,850 customers participating, including approximately 429,000 residential customers. In April 1999, Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) filed an application with the Kentucky Public Service Commission (KPSC), seeking approval to initiate a residential and small commercial transportation program. In January 2000, the KPSC approved Columbia of Kentucky's application, but did not renew Columbia of Kentucky's gas cost incentive program originally approved in 1996. As an alternative, an incentive sharing mechanism was approved that allows Columbia of Kentucky to retain 25% of annual off-system sales over the term of the pilot program. Additionally, Columbia of Kentucky will remain responsible for mitigating transition capacity costs through the utilization of non-traditional revenues. Columbia of Kentucky began customer enrollment in the pilot program in September 2000, for gas deliveries beginning November 1, 2000. The program is scheduled to run through 2004. Currently, Columbia of Kentucky has approximately 14,000 customers enrolled and participating in its CHOICE(SM) program. The tightening of supply in the natural gas market over the last half of 2000, along with the resultant increase in price of natural gas, has caused several marketers to default on their obligation to deliver gas to Columbia of Ohio and Columbia of Kentucky under both the traditional and CHOICE(SM) transportation programs. Columbia of Ohio and Columbia of Kentucky have terminated marketers with 19,500 customers in traditional and CHOICE(SM) transportation programs. Columbia of Ohio is also a party to two lawsuits involving Energy Max, one of the terminated marketers. A customer in Toledo, Ohio filed the first suit on October 18, 2000 against both Energy Max and Columbia of Ohio, asking that the complaint be certified as a class action (Hull v. Columbia Gas of Ohio and Energy Max). The plaintiff is seeking to recover the difference between what he would have paid for gas under his Energy Max contract, and what he is paying under Columbia of Ohio's gas costs recovery rate. On January 26, 2001, Columbia of Ohio filed its Answer and a Motion to Dismiss. Energy Max has not filed an answer and is subject to a motion for default judgement. The second suit was filed by Columbia of Ohio against Energy Max on January 2, 2001 in 20 21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Youngstown, Ohio (Columbia Gas of Ohio v. Energy Max). In this case, Columbia of Ohio is seeking to recover in excess of $340,000 from Energy Max due to its non-delivery of gas in Columbia of Ohio's traditional transportation program. Columbia of Ohio has been given the right to bill the end users for their gas consumption during the months of November and December 2000. The Ohio Office of Consumers' Counsel has also filed a complaint at the PUCO against certain marketers, but Columbia of Ohio is not a party to that complaint at this time. FERC Order No. 637 The FERC issued Order No. 637 on February 9, 2000. The order sets forth revisions to FERC regulations governing short-term natural gas transportation services and policies governing the regulation of interstate natural gas pipelines. Among other things, the order lifts the price cap for short-term capacity release by pipeline customers for an experimental period ending September 1, 2002. Distribution is currently in the process of evaluating the potential changes and impact Order 637 may have on operations; however, it is not anticipated that the implementation of Order 637 will have a material impact on Columbia's consolidated results. Capital Expenditure Program Distribution's 2000 capital expenditures were $139.6 million, a decrease of $5.9 million from 1999. In addition to maintaining and upgrading facilities to assure safe, reliable and efficient operation, 2000 expenditures included $56.4 million for extending service to new areas and $60.4 million for replacement and betterment projects. The estimated 2001 capital expenditure program amounts to approximately $113 million, including $51 million for new business and development, with the remainder primarily for support services and replacement and betterment projects. Environmental Matters Distribution's primary environmental issues relate to 18 former manufactured gas plant sites. Investigations or remedial activities are currently underway at six sites and remedial construction has been completed at two sites. Additional site investigations may be required at some of the remaining sites. To the extent Distribution's site investigations have been conducted, remediation plans developed and the responsibility for remediation established, the appropriate estimated liabilities have been recorded. Regulatory assets have also been recorded for a majority of these costs as rate recovery has been authorized or is probable. In June 1999, Columbia Gas of Pennsylvania (Columbia of Pennsylvania), was notified by the United States Environmental Protection Agency (USEPA) Region 5, that it was the potential responsible party (PRP) under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) concerning a site in Wooster, Ohio, known as 7-7 Merger, Inc. Columbia of Pennsylvania, along with 23 other parties, entered into an Administrative Consent order with USEPA Region 5 and the work was nearly completed during the year 2000. The PRP group working with Region 5 shared costs on this project. Columbia of Pennsylvania's share of the cost is $20,000. With additional miscellaneous costs, it is not anticipated that Columbia of Pennsylvania's liability will exceed $25,000 for this project. Only a minor amount of disposal remains to be accomplished during 2001 and there is sufficient funding in the PRP to fund the balance of this work. Throughput In 2000, total volumes sold and transported of 551.5 Bcf decreased 145.3 Bcf from 1999. The decreased throughput primarily reflects a 159.8 Bcf decrease in off-system sales partially offset by increased transportation services. Distribution's 1999 total volumes sold and transported of 696.8 Bcf increased 138.6 Bcf from 1998 primarily due to an increase in off-system sales as Distribution took advantage of higher spot prices in March 1999. Net Revenues Net revenues for 2000 of $886.7 million were up $34.1 million over 1999 primarily due to increased transportation services. In 1999, net revenues of $852.6 million were up $5.6 million over 1998 reflecting the positive impact of Columbia of Virginia's regulatory settlement and increased customer usage as a result of colder weather, partially offset by the impact of lower sales due to the switch to CHOICE(SM) transportation services. 21 22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Operating Income Operating income for 2000 of $176 million decreased $78.6 million from 1999, primarily due to $100.9 million in costs related to merger-related and restructuring activities. Partially offsetting these decreases was the favorable impact of the 1997 Columbia of Ohio regulatory settlement and reduced employee related costs as a result of the VIRP. Operating income in 1999 of $254.6 million increased by $28.8 million over 1998, primarily due to the increase in net revenues, reduced operating expenses attributable to lower gross receipts and property taxes, as noted above. However, the favorable effect of lower depreciation expense attributable to the 1999 Columbia of Ohio regulatory settlement is offset by charges to revenues for reserves established for recovery of future stranded costs as provided for under this settlement and therefore has no effect on operating income. STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 2000 1999 1998 ---------------------------------------------------------------------------------------------------------------------------------- NET REVENUES Sales revenues $ 1,684.5 $ 1,705.5 $ 1,686.3 Less: Cost of gas sold 1,124.9 1,137.6 1,005.4 ---------------------------------------------------------------------------------------------------------------------------------- Net Sales Revenues 559.6 567.9 680.9 ---------------------------------------------------------------------------------------------------------------------------------- Transportation revenues 351.4 317.3 183.2 Less: Associated gas costs 24.3 32.6 17.1 ---------------------------------------------------------------------------------------------------------------------------------- Net Transportation Revenues 327.1 284.7 166.1 ---------------------------------------------------------------------------------------------------------------------------------- Net Revenues 886.7 852.6 847.0 ---------------------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Operation and maintenance 523.4 406.9 386.7 Depreciation 57.4 54.5 82.2 Other taxes 129.9 136.6 152.3 ---------------------------------------------------------------------------------------------------------------------------------- Total Operating Expenses 710.7 598.0 621.2 ---------------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME $ 176.0 $ 254.6 $ 225.8 ----------------------------------------------------------------------------------------------------------------------------------
22 23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) DISTRIBUTION OPERATING HIGHLIGHTS
2000 1999 1998 1997 1996 ------------------------------------------------------------------------------------------------------------------------ CAPITAL EXPENDITURES ($ in millions) 139.6 145.5 151.9 159.5 148.4 ------------------------------------------------------------------------------------------------------------------------ THROUGHPUT (Bcf) Sales Residential 130.6 132.5 149.1 190.9 209.4 Commercial 45.0 43.7 54.1 72.7 85.7 Industrial and Other 4.2 3.5 4.4 4.2 10.3 ------------------------------------------------------------------------------------------------------------------------ Total Sales 179.8 179.7 207.6 267.8 305.4 Transportation 360.6 346.2 287.7 258.9 248.8 ------------------------------------------------------------------------------------------------------------------------ Total Throughput 540.4 525.9 495.3 526.7 554.2 Off-System Sales 11.1 170.9 62.9 45.4 10.8 ------------------------------------------------------------------------------------------------------------------------ Total Sold and Transported 551.5 696.8 558.2 572.1 565.0 ------------------------------------------------------------------------------------------------------------------------ SOURCES OF GAS FOR THROUGHPUT (Bcf) Sources of Gas Sold Spot market* 284.8 302.2 229.8 314.0 323.2 Producers 10.6 12.6 20.8 38.9 50.2 Storage withdrawals (injections) (0.4) 15.5 12.4 4.0 (20.8) Company use, exchange and other (104.1) 20.3 7.5 (43.7) (36.4) ------------------------------------------------------------------------------------------------------------------------ Total Sources of Gas Sold 190.9 350.6 270.5 313.2 316.2 Gas received for delivery to customers 360.6 346.2 287.7 258.9 248.8 ------------------------------------------------------------------------------------------------------------------------ Total Sources 551.5 696.8 558.2 572.1 565.0 ------------------------------------------------------------------------------------------------------------------------ CUSTOMERS Sales Residential 1,387,801 1,366,869 1,612,124 1,769,647 1,815,269 Commercial 127,504 123,673 148,529 168,413 173,689 Industrial and Other 2,205 2,264 2,295 2,340 2,285 ------------------------------------------------------------------------------------------------------------------------ Total Sales Customers 1,517,510 1,492,806 1,762,948 1,940,400 1,991,243 Transportation 534,854 603,901 298,107 93,923 12,804 ------------------------------------------------------------------------------------------------------------------------ Total Customers 2,052,364 2,096,707 2,061,055 2,034,323 2,004,047 ------------------------------------------------------------------------------------------------------------------------ DEGREE DAYS 5,610 5,171 4,635 5,736 5,975 ------------------------------------------------------------------------------------------------------------------------
* Reflects volumes under purchase contracts of less than one year. EXPLORATION AND PRODUCTION OPERATIONS Columbia's exploration and production subsidiary, Columbia Resources, is one of the largest independent natural gas and oil producers in the Appalachian Basin and also has production operations in Ontario, Canada and the Canadian Maritimes. Columbia Resources produced 53.7 Bcf equivalents (Bcfe) of natural gas and oil in 2000 and has financial interests in approximately 8,000 wells, and has net proven gas and oil reserve holdings of 1.1 trillion cubic feet equivalent at December 31, 2000. Columbia Resources also owns and operates approximately 6,200 miles of gathering pipelines. Columbia Resources seeks to achieve asset and profit growth primarily through expanded drilling activities. During 2000, Columbia Resources' drilling activity resulted in the discovery of 78.6 net Bcfe of gas and oil reserves. For 1999, reserves of 69.5 Bcfe were developed. Through December 2000, Columbia Resources has participated in 259 gross (239 net) wells with a success rate of 85 percent compared to 263 gross (240 net) wells with a success rate of 82 percent in 1999. 23 24 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) Capital Expenditure Program Columbia Resources' 2000 capital expenditures of $128.9 million primarily reflect investments in drilling and production activities. The 2001 capital expenditure program is estimated at $132 million and provides for the drilling of 223 new wells in the Appalachian Basin and Canada. This investment will include the expansion of Columbia Resources' gathering facilities in the Appalachian Basin and the continued expansion of its acreage position. Forward Sale of Natural Gas On August 24, 2000, Columbia Resources entered into an agreement with Mahonia II Limited, whereby Columbia Resources agreed to sell 111.7 Bcf of natural gas to Mahonia for the period August 2000, through July 2005. This forward sale provided $246.4 million in cash proceeds, net of expenses. Production Gas production of 52.4 Bcf in 2000 increased 6.6 Bcf over 1999, primarily due to new well completions coming on-line. In 1999, gas production of 45.8 Bcf increased 6.7 Bcf over 1998, primarily due to the acquisition of Wiser Oil and Meridian Exploration. Oil and liquids production in 1999 decreased 14% from 1998 to 185,207 barrels primarily reflecting normal production declines in Ohio wells. Operating Revenues Operating revenues for 2000 of $178.5 million increased $33.7 million over 1999. The increase reflects higher average natural gas prices that were $2.99 per Mcf in 2000 compared to $2.66 per Mcf in 1999. Approximately 63% of Columbia Resources' natural gas production for 2000 was hedged or committed through fixed price contracts at an average price of $3.51 per Mcf. Operating revenues for 1999 of $144.8 million increased $17.3 million over 1998 reflecting increased gas production that was partially offset by lower average 1999 gas prices. Also contributing to the increase in operating revenues in 1999 was $6 million of revenues received from the termination of long-term sales contracts with two co-generation facilities. Operating Income Operating income of $49.3 million for 2000 increased $5.1 million over 1999 reflecting the impact of higher natural gas production and a lower depletion rate in effect due to higher commodity prices. Tempering this increase were merger-related expenditures of $17.6 million and expenses related to the implementation of the VIRP. In 1999, operating income of $44.2 million improved $7 million over 1998 reflecting higher operating revenues, partially offset by higher operating expense due largely to costs related to acquisitions and increased drilling activity. STATEMENTS OF OPERATING INCOME FROM EXPLORATION AND PRODUCTION OPERATIONS (UNAUDITED)
Year Ended December 31, (in millions) 2000 1999 1998 --------------------------------------------------------------------------------------- OPERATING REVENUES Gas revenues $ 159.5 $ 123.1 $ 113.9 Other revenues 19.0 21.7 13.6 --------------------------------------------------------------------------------------- Total Operating Revenues 178.5 144.8 127.5 --------------------------------------------------------------------------------------- OPERATING EXPENSES Operation and maintenance 82.3 53.9 44.6 Depreciation and depletion 33.0 36.9 36.5 Other taxes 13.9 9.8 9.2 --------------------------------------------------------------------------------------- Total Operating Expenses 129.2 100.6 90.3 --------------------------------------------------------------------------------------- OPERATING INCOME $ 49.3 $ 44.2 $ 37.2 ---------------------------------------------------------------------------------------
24 25 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) EXPLORATION AND PRODUCTION OPERATING HIGHLIGHTS
2000 1999 1998 1997 1996 ----------------------------------------------------------------------------------------------------------------------- CAPITAL EXPENDITURES ($ in millions) 128.9 166.5 75.7 135.6 12.1 ----------------------------------------------------------------------------------------------------------------------- PROVED RESERVES Gas (Bcf) 1,099.6 951.6 790.5 800.5 644.5 Oil and Liquids (000 Bbls) 1,399 2,375 1,835 1,700 774 ----------------------------------------------------------------------------------------------------------------------- PRODUCTION Gas (Bcf) 52.4 45.8 39.1 34.7 33.6 Oil and Liquids (000 Bbls) 215 185 214 210 281 ----------------------------------------------------------------------------------------------------------------------- AVERAGE PRICES Gas ($ per Mcf)* 2.99 2.66 2.91 2.63 2.84 Oil and Liquids ($ per barrel) 25.29 14.96 12.76 17.99 19.07 -----------------------------------------------------------------------------------------------------------------------
* Includes the effect of hedging activities as discussed in Note 7 of Notes to Consolidated Financial Statements. OTHER PRODUCTS AND SERVICES Telecommunications Network In 1999, Transcom, a wholly-owned subsidiary of Columbia, began the construction of its telecommunications network between New York and Washington, D.C. Transcom is building its fiber optics network primarily on rights-of-way of Columbia's pipeline companies. The route covers 260 miles and provides access to 16 million people in the busiest telecommunications corridor in the United States. Transcom expects to complete the D.C. to New York fiber optics link in the first half of 2001. Columbia is currently pursuing strategic alternatives for its telecommunications network. Sale of Columbia Electric In December, Columbia Electric sold its interests in four power generation plants to a partnership between Delta Power Company and John Hancock Life Insurance Company. These facilities include the Gregory Power Project in Corpus Christi, Texas; a co-generation facility in Rumford, Maine; and two combined-cycle facilities, one located near Pedericktown, New Jersey and the other near Vineland, New Jersey. These projects are qualifying facilities under the Public Utility Regulatory Policies Act (PURPA). Also in December, Columbia sold the remainder of Columbia Electric to Orion Power Holdings, Inc. In aggregate, the sale of Columbia Electric and its operations resulted in a gain that improved Columbia's consolidated results by approximately $86 million after-tax. Capital Expenditures The capital expenditure program for 2000 was $96 million and included amounts for the development of Transcom's fiber optics network. The 2001 program is projected to be $2 million for miscellaneous activities. Environmental Matters In spring 2000, Transcom received directives from The Philadelphia District of the U.S. Army Corps of Engineers (Philadelphia District) and an administrative order from the PA DEP addressing alleged violations of federal and state laws resulting from construction activities associated with the corporation's laying of fiber optic cable along portions of a route between Washington, D.C. and New York City. The order and directives required Transcom to largely cease construction activities. On September 18, 2000, Transcom entered into a voluntary settlement agreement with the Philadelphia District under which Transcom contributed $1.2 million to the Pennsylvania chapter of the Nature Conservancy and the Philadelphia District lifted its directives. As a result of the voluntary agreement with the Philadelphia District and communications with the PA DEP, the Maryland Department of Environment and the Baltimore District of the U.S. Army Corps of Engineers, work in Pennsylvania and Maryland is now ongoing. Transcom cannot predict the effect of the ongoing discussions on the completion schedule for the 25 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued) project, nor the nature or amount of total remedies that may be sought in connection with the foregoing construction activities. Operating Revenues In 2000, operating revenues of $50.1 million decreased $46.2 million from 1999 million largely due to a gain in 1999 resulting from the termination of a long-term power purchase contract between Columbia Electric and Atlantic Generation, Inc. In 1999, operating revenues of $96.3 million increased $73.1 million over 1998. The increase largely reflected the gain from the termination of the power purchase contract previously mentioned. Operating Income (Loss) In 2000, the other products and services segment reported an operating loss of $32.3 million compared to operating income of $63.8 million in 1999. The 1999 results included a gain from the termination of the power purchase contract, mentioned above. The higher operating expenses in 2000 included $10.8 million of merger-related expenditures and employee-related payments resulting from the achievement of specific objectives in the development of co-generation projects by Columbia Electric. In 1999, operating income of $63.8 million increased $61.5 million from 1998 as the increase in operating revenues was only partially offset by a $11.6 increase in operating expenses. STATEMENTS OF OTHER PRODUCTS AND SERVICES (UNAUDITED)
Year Ended December 31, (in millions) 2000 1999 1998 ------------------------------------------------------------------------------------ OPERATING REVENUES Gas revenues $ 35.0 $ 7.7 $ 4.0 Power generation revenues 8.8 78.5 8.3 LNG revenues 3.8 9.3 10.4 Other revenues 2.5 0.8 0.5 ------------------------------------------------------------------------------------- Total Operating Revenues 50.1 96.3 23.2 ------------------------------------------------------------------------------------ OPERATING EXPENSES Products purchased 26.6 4.9 0.5 Operation and maintenance 55.0 26.8 19.9 Depreciation 0.2 0.4 0.3 Other taxes 0.6 0.4 0.2 ------------------------------------------------------------------------------------ Total Operating Expenses 82.4 32.5 20.9 ------------------------------------------------------------------------------------ OPERATING INCOME (LOSS) $ (32.3) $ 63.8 $ 2.3 ------------------------------------------------------------------------------------
OTHER PRODUCTS AND SERVICES OPERATING HIGHLIGHTS
2000 1999 1998 1997 1996 ------------------------------------------------------------------------------------------------------------- CAPITAL EXPENDITURES ($ in millions) 96.0 57.3 12.1 1.5 0.2 -------------------------------------------------------------------------------------------------------------
26 27 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item is in Item 7 beginning on page 14. 27 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index Page Report of Independent Public Accountants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Statements of Consolidated Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Statements of Consolidated Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Statements of Consolidated Common Stock Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Notes of Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Schedule II - Valuation and Qualifying Accounts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
28 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholder of Columbia Energy Group: We have audited the accompanying consolidated balance sheets of Columbia Energy Group (a Delaware corporation, the "Corporation" and a wholly-owned subsidiary of NiSource Inc.) and subsidiaries as of December 31, 2000, and 1999, and the related statements of consolidated income, cash flows and common stock equity for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Corporation and subsidiaries as of December 31, 2000, and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The schedule listed in the Index to Item 8, Financial Statements and Supplementary Data, is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP New York, New York January 30, 2001 29 30 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) STATEMENTS OF CONSOLIDATED INCOME Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions) 2000 1999 1998 ------------------------------------------------------------------------------------------------------------- NET REVENUES Energy sales $ 1,723.1 $ 1,717.8 $ 1,651.1 Less: Products purchased 922.5 892.9 722.2 ------------------------------------------------------------------------------------------------------------- Gross Margin 800.6 824.9 928.9 Transportation 801.2 706.5 577.2 Production gas sales 154.9 120.2 111.8 Other 179.8 256.4 206.0 ------------------------------------------------------------------------------------------------------------- Total Net Revenues 1,936.5 1,908.0 1,823.9 ------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Operation and maintenance (Note 4) 1,110.5 838.6 790.5 Settlement of gas supply charges -- (31.7) -- Depreciation and depletion 205.2 202.7 226.3 Other taxes 202.5 203.2 216.5 ------------------------------------------------------------------------------------------------------------- Total Operating Expenses 1,518.2 1,212.8 1,233.3 ------------------------------------------------------------------------------------------------------------- OPERATING INCOME 418.3 695.2 590.6 ------------------------------------------------------------------------------------------------------------- OTHER INCOME (DEDUCTIONS) Interest income and other, net (Note 15) 236.3 34.9 14.7 Interest expense and related charges (Note 16) (169.6) (164.2) (144.2) ------------------------------------------------------------------------------------------------------------- Total Other Income (Deductions) 66.7 (129.3) (129.5) ------------------------------------------------------------------------------------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 485.0 565.9 461.1 Income Taxes (Note 9) 190.4 178.1 152.2 ------------------------------------------------------------------------------------------------------------- INCOME FROM CONTINUING OPERATIONS 294.6 387.8 308.9 ------------------------------------------------------------------------------------------------------------- DISCONTINUED OPERATIONS - NET OF TAXES (Loss) from operations (1.5) (112.8) (39.7) Estimated (loss) on disposal (159.4) (25.8) -- ------------------------------------------------------------------------------------------------------------- (Loss) from Discontinued Operations - net of taxes (160.9) (138.6) (39.7) ------------------------------------------------------------------------------------------------------------- NET INCOME $ 133.7 $ 249.2 $ 269.2 -------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 30 31 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) CONSOLIDATED BALANCE SHEETS Columbia Energy Group and Subsidiaries
ASSETS as of December 31, (in millions) 2000 1999 ------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT Gas utility and other plant, at original cost $ 8,174.2 $ 7,886.2 Accumulated depreciation (3,778.3) (3,659.4) ------------------------------------------------------------------------------------------------ Net Gas Utility and Other Plant 4,395.9 4,226.8 ------------------------------------------------------------------------------------------------ Gas and oil producing properties, full cost method United States cost center 913.6 823.5 Canadian cost center 20.2 12.6 Accumulated depletion (272.7) (251.6) ------------------------------------------------------------------------------------------------ Net Gas and Oil Producing Properties 661.1 584.5 ------------------------------------------------------------------------------------------------ Net Property, Plant and Equipment 5,057.0 4,811.3 ------------------------------------------------------------------------------------------------ INVESTMENTS AND OTHER ASSETS Unconsolidated affiliates 28.1 65.6 Net assets of discontinued operations 236.3 410.0 Other 27.4 61.4 ------------------------------------------------------------------------------------------------ Total Investments and Other Assets 291.8 537.0 ------------------------------------------------------------------------------------------------ CURRENT ASSETS Cash and temporary cash investments 73.5 58.1 Accounts receivable Customer (less allowance for doubtful accounts of $15.8 and $11.3, respectively) 569.8 401.7 Affiliated 2.7 -- Other 113.5 96.8 Gas inventory 147.4 144.9 Other inventories - at average cost 14.5 16.1 Prepayments 73.8 70.7 Regulatory assets 57.4 52.7 Underrecovered gas costs 169.0 40.5 Deferred property taxes 45.2 79.9 Exchange gas receivable 615.9 275.4 Other (2.3) 31.0 ------------------------------------------------------------------------------------------------ Total Current Assets 1,880.4 1,267.8 ------------------------------------------------------------------------------------------------ REGULATORY ASSETS 351.8 358.1 DEFERRED CHARGES 45.2 63.1 ------------------------------------------------------------------------------------------------ TOTAL ASSETS $ 7,626.2 $ 7,037.3 ------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 31 32 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CAPITALIZATION AND LIABILITIES as of December 31, (in millions) 2000 1999 ------------------------------------------------------------------------------------------------------- COMMON STOCK EQUITY Common stock, par value $.01 per share - issued 79,539,295 and 83,786,942 shares, respectively $ 0.8 $ 0.8 Additional paid in capital 1,369.0 1,611.6 Retained earnings 666.5 586.9 Unearned employee compensation -- (0.6) Accumulated other comprehensive income: Foreign currency translation adjustment (0.4) 0.3 Treasury stock -- (135.0) ------------------------------------------------------------------------------------------------------- Total Common Stock Equity 2,035.9 2,064.0 LONG-TERM DEBT (Note 11) 1,639.1 1,639.3 ------------------------------------------------------------------------------------------------------- Total Capitalization 3,675.0 3,703.3 ------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Short-term debt (Note 12) 521.0 465.5 Current maturities of long-term debt 0.2 311.1 Accounts and drafts payable 398.0 240.8 Affiliated payable 7.2 -- Accrued taxes 177.1 216.1 Accrued interest 17.7 32.4 Estimated rate refunds 6.8 21.4 Overrecovered gas costs -- 14.6 Transportation and exchange gas payable 358.5 297.5 Deferred revenue 451.5 40.0 Other 366.0 366.8 ------------------------------------------------------------------------------------------------------- Total Current Liabilities 2,304.0 2,006.2 ------------------------------------------------------------------------------------------------------- OTHER LIABILITIES AND DEFERRED CREDITS Deferred income taxes - noncurrent 766.8 661.9 Investment tax credits 31.2 32.6 Postretirement benefits other than pensions 114.7 91.0 Regulatory liabilities 32.4 36.4 Deferred revenue 498.0 300.8 Other 204.1 205.1 ------------------------------------------------------------------------------------------------------- Total Other Liabilities and Deferred Credits 1,647.2 1,327.8 ------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES (Note 14) -- -- ------------------------------------------------------------------------------------------------------- TOTAL CAPITALIZATION AND LIABILITIES $ 7,626.2 $ 7,037.3 -------------------------------------------------------------------------------------------------------
32 33 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) STATEMENTS OF CONSOLIDATED CASH FLOWS Columbia Energy Group and Subsidiaries
Year Ended December 31, (in millions) 2000 1999 1998 --------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income $ 133.7 $ 249.2 $ 269.2 Adjustments to reconcile net income to net cash from continuing operations: Loss from discontinued operations 1.5 112.8 39.7 Loss on disposal 159.4 25.8 -- Depreciation and depletion 205.2 202.7 226.3 Deferred income taxes 119.5 47.6 35.7 Gain on sale of investments (221.0) -- -- Earnings from equity investment, net of distributions (16.4) 23.3 (8.5) Deferred revenue 197.2 109.4 124.4 Other - net 47.9 (59.0) 2.0 --------------------------------------------------------------------------------------------------------------- 627.0 711.8 688.8 Changes in components of working capital: Accounts receivable, net of sale (200.6) (145.9) 66.8 Sale of accounts receivable -- 81.1 -- Gas inventory (2.5) 41.1 40.8 Prepayments (3.1) (7.4) (4.0) Accounts payable 142.4 87.6 5.8 Accrued taxes (58.1) (2.5) 77.2 Accrued interest (13.6) 15.1 (12.1) Estimated rate refunds (14.6) (37.8) (9.2) Estimated supplier obligations -- (40.6) (1.5) Under/Overrecovered gas costs (143.0) (35.7) (33.4) Exchange gas receivable/payable (279.5) 78.4 62.1 Deferred revenue 411.5 27.9 12.1 Other working capital 79.3 9.9 (14.0) --------------------------------------------------------------------------------------------------------------- Net Cash From Continuing Operations 545.2 783.0 879.4 Net Cash From Discontinued Operations 12.8 (246.3) (193.3) --------------------------------------------------------------------------------------------------------------- Net Cash From Operating Activities 558.0 536.7 686.1 --------------------------------------------------------------------------------------------------------------- INVESTMENT ACTIVITIES Capital expenditures (476.0) (447.6) (434.8) Purchases and sales of investments - net 312.9 (62.1) (8.7) --------------------------------------------------------------------------------------------------------------- Net Investment Activities (163.1) (509.7) (443.5) --------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Retirement of long-term debt (310.9) (52.5) (0.9) Dividends paid (54.1) (71.8) (63.9) Issuance of common stock 6.5 15.5 10.5 Issuance (repayment) of short-term debt 55.5 320.7 (182.4) Purchase of treasury stock (114.1) (135.0) -- Other financing activities 37.6 (66.6) (11.6) --------------------------------------------------------------------------------------------------------------- Net Financing Activities (379.5) 10.3 (248.3) --------------------------------------------------------------------------------------------------------------- Increase (decrease) in cash and temporary cash investments 15.4 37.3 (5.7) Cash and temporary cash investments at beginning of year 58.1 20.8 26.5 --------------------------------------------------------------------------------------------------------------- CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR $ 73.5 $ 58.1 $ 20.8 --------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid for interest $ 162.7 $ 148.6 $ 147.0 Cash paid for income taxes (net of refunds) $ 69.2 $ 61.6 $ 38.2 ---------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 33 34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY Columbia Energy Group and Subsidiaries
Common Stock* -------------------------------------------------------- Shares. Additional Outstanding ** Par Treasury Paid In (in millions, except for share amounts) (Thousands) Value Stock Capital ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1997 55,496 $ 554.9 $ - $ 754.2 Comprehensive income: Net income Foreign currency translation adjustment Comprehensive income Cash dividends: Common stock Common stock issued: Long-term incentive plan 231 2.3 7.6 Three-for-two stock split 27,785 277.9 ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1998 83,512 835.1 - 761.8 Comprehensive income: Net income Foreign currency translation adjustment Comprehensive income Cash dividends: Common stock Reduction in par from $10 to $.01 per share (834.3) 834.3 Common stock issued: Long-term incentive plan 275 15.5 Purchase of treasury stock (2,479) (135.0) ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1999 81,308 0.8 (135.0) 1,611.6 Comprehensive income: Net income Foreign currency translation adjustment Comprehensive income Cash dividends: Common stock Common stock issued: Long-term incentive plan 120 6.5 Purchase of treasury stock (1,889) (114.1) Retirement of treasury stock 249.1 (249.1) ------------------------------------------------------------------------------------------------------------------------------------ BALANCE AT DECEMBER 31, 2000 79,539 $ 0.8 $ - $ 1,369.0 ------------------------------------------------------------------------------------------------------------------------------------
Accumulated Unearned Other Retained Employee Comprehensive (in millions, except for share amounts) Earnings Compensation Income (Loss) Total ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1997 $ 482.7 $ (1.1) $ - $ 1,790.7 Comprehensive income: Net income 269.2 269.2 Foreign currency translation adjustment (0.2) (0.2) ------------- Comprehensive income 269.0 ------------- Cash dividends: Common stock (63.9) (63.9) Common stock issued: Long-term incentive plan 0.2 10.1 Three-for-two stock split (278.5) (0.6) ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1998 409.5 (0.9) (0.2) 2,005.3 Comprehensive income: Net income 249.2 249.2 Foreign currency translation adjustment 0.5 0.5 ------------- Comprehensive income 249.7 ------------- Cash dividends: Common stock (71.8) (71.8) Reduction in par from $10 to $.01 per share - Common stock issued: Long-term incentive plan 0.3 15.8 Purchase of treasury stock (135.0) ------------------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1999 586.9 (0.6) 0.3 2,064.0 Comprehensive income: Net income 133.7 133.7 Foreign currency translation adjustment (0.7) (0.7) ------------- Comprehensive income 133.0 ------------- Cash dividends: Common stock (54.1) (54.1) Common stock issued: Long-term incentive plan 0.6 7.1 Purchase of treasury stock (114.1) Retirement of treasury stock - ------------------------------------------------------------------------------------------------------------------------------------ BALANCE AT DECEMBER 31, 2000 $ 666.5 $ - $ (0.4) $2,035.9 ------------------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. ------------- * Effective May 19, 1999, the authorized number of shares of common stock increased from 100 million to 200 million and the par value of common stock decreased from $10 to $.01 per share. ** The common shares outstanding at December 31, 1997 do not reflect the three-for-two common stock split, in the form of a stock dividend, effective June 15, 1998. 34 35 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the accounts of the Columbia Energy Group (Columbia) and all subsidiaries. All intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the 1999 and 1998 financial statements to conform to the 2000 presentation. B. CASH AND CASH EQUIVALENTS. Columbia considers all highly liquid short-term investments to be cash equivalents. C. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Columbia's transmission and gas distribution subsidiaries follow the accounting and reporting requirements of SFAS No. 71. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. In Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1999 rate agreement (See Note 2), the Public Utilities Commission of Ohio (PUCO) authorized Columbia of Ohio to revise its depreciation accrual rates for the period January 1, 1999 through December 31, 2004. The revised depreciation rates are lower than those which would have been utilized if Columbia of Ohio were not subject to regulation. The amount of depreciation that would have been recorded for 2000 had Columbia of Ohio not been subject to rate regulation is $34.5 million, a $21.1 million increase over the $13.4 million reflected in rates. Accordingly, a regulatory asset has been established in the amount of $39.9 million at December 31, 2000. Information for assets and liabilities subject to utility regulation and rate determination are as follows:
TRANSMISSION DISTRIBUTION SUBSIDIARIES SUBSIDIARIES ---------------- ---------------- At December 31, ($ in millions) 2000 1999 2000 1999 ------------------------------------------------------------------------------------------------------------------------- ASSETS Environmental costs 78.3 95.5 4.5 5.0 Postemployment and postretirement benefits costs 52.3 56.2 97.3 105.5 Percent of income plan receivables - - 6.4 8.0 Retirement income plan costs 9.2 12.7 11.9 14.9 Regulatory effects of accounting for income taxes - - 77.0 64.4 Post in-service carrying charges - - 15.3 16.0 Underrecovered gas costs - - 169.0 40.5 Depreciation - - 39.9 18.8 Other 6.8 7.9 10.3 5.9 ------------------------------------------------------------------------------------------------------------------------- TOTAL REGULATORY ASSETS 146.6 172.3 431.6 279.0 ------------------------------------------------------------------------------------------------------------------------- LIABILITIES Rate refunds and reserves - 5.3 6.8 16.1 Overrecovered gas costs - - - 14.6 Regulatory effects of accounting for income taxes 13.4 15.2 19.2 21.0 Other 6.4 23.1 2.0 2.0 ------------------------------------------------------------------------------------------------------------------------ TOTAL REGULATORY LIABILITIES 19.8 43.6 28.0 53.7 ------------------------------------------------------------------------------------------------------------------------
Regulatory assets of approximately $428.3 million are not presently included in the rate base and consequently are not earning a return on investment. These regulatory assets are being recovered through cost of service. The remaining recovery periods generally range from one to fifteen years. Regulatory assets of approximately $57.3 million require specific rate action. All regulatory assets are probable of recovery. 35 36 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) D. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant and equipment (principally utility plant) are stated at cost. The cost of gas utility and other plant of the rate-regulated subsidiaries includes an allowance for funds used during construction (AFUDC). Property, plant and equipment of other subsidiaries includes interest during construction (IDC). The 2000 before-tax rates for AFUDC and IDC were 6.84% and 6.82%, respectively. The 1999 and 1998 before-tax rates for AFUDC were 5.91% and 7.43%, respectively, and for IDC were 6.94% and 6.96%, respectively. Improvements and replacements of retirement units are capitalized at cost. When units of property are retired, the accumulated provision for depreciation is charged with the cost of the units and the cost of removal, net of salvage. Maintenance, repairs and minor replacements of property are charged to expense. Columbia's subsidiaries provide for annual depreciation on a composite straight-line basis. The average annual depreciation rate for the transmission subsidiaries' property was 2.4% in 2000, 1999 and 1998. The average annual depreciation rate for the distribution subsidiaries' property was 2.8% in 2000 and in 1999, and 3.1% in 1998. E. GAS AND OIL PRODUCING PROPERTIES. Columbia's subsidiaries engaged in exploring for and developing gas and oil reserves follow the full cost method of accounting. Under this method of accounting, all productive and nonproductive costs directly identified with acquisition, exploration and development activities including certain payroll and other internal costs are capitalized. Depletion is based upon the ratio of current year revenues to expected total revenues, utilizing current prices, over the life of production. If costs exceed the sum of the estimated present value of the net future gas and oil revenues and the lower of cost or estimated value of unproved properties, an amount equivalent to the excess is charged to current depletion expense. Gains or losses on the sale or other disposition of gas and oil properties are normally recorded as adjustments to capitalized costs, except in the case of a sale of a significant amount of properties, which would be reflected in the income statement. F. INTANGIBLE ASSETS. Intangible assets are recorded at original cost and are amortized on a straight line basis. Goodwill represents the excess of the purchase price over the fair value of net assets acquired and is being amortized over 40 years. Customer lists are being amortized over periods of 10 to 20 years. Intangible assets are immaterial to the consolidated financial statements. G. ACCOUNTING FOR RISK MANAGEMENT ACTIVITIES. Columbia's exploration and production subsidiary is exposed to market risk due primarily to fluctuations in commodity prices. In order to help minimize this risk, Columbia has adopted a policy that provides for the use of commodity derivative instruments to help ensure stable cash flow, favorable prices and margins. In accordance with Statement of Financial Accounting Standards No. 80, "Accounting for Futures Contracts," a futures contract qualifies as a hedge if the commodity to be hedged is exposed to price risk and the futures contract reduces that exposure and is designated as a hedge. The hedging objectives include assurance of stable and known cash flows, fixing favorable prices and margins when they become available. Columbia's exploration and production company utilize commodity price swaps and basis swaps. Swaps are negotiated and executed over-the-counter and are structured to provide the same risk protection as futures and options. Basis swaps are used to manage risk by fixing the basis or differential that exists between a delivery location index and the commodity futures prices. Margin requirements for natural gas are also recorded as current assets. Unrealized gains and losses on all futures contracts are deferred on the consolidated balance sheets as either current assets or other deferred credits. Realized gains and losses from the settlement swaps are included in revenues concurrent with the associated physical transaction. The cash flows from commodity hedging are included in operating activities in the consolidated statements of cash flows. Columbia's exploration and production company is exposed to credit losses in the event of nonperformance by the counterparties to its various financial contracts. Management has evaluated such risk and believes that overall business risk is significantly reduced as these financial contracts are primarily with major investment grade financial institutions or their affiliates. Columbia utilizes fixed-to-floating interest rate swap agreements to modify the interest characteristics of a portion of its outstanding long-term debt. The differentials between amounts received and paid under the agreements are recorded as adjustments to interest expense. 36 37 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) H. GAS INVENTORY. The distribution subsidiaries' gas inventory is carried at cost on a last-in, first-out (LIFO) basis. The excess of replacement cost of gas inventory at December 31, 2000, over the carrying value is approximately $529.7 million. Liquidation of LIFO layers related to gas delivered by the distribution subsidiaries does not affect income since the effect is passed through to customers as part of purchased gas adjustment tariffs. I. INCOME TAXES AND INVESTMENT TAX CREDITS. Columbia and its subsidiaries record income taxes to recognize full interperiod tax allocations. Under the liability method of income tax accounting, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Previously recorded investment tax credits of the regulated subsidiaries were deferred and are being amortized over the life of the related properties to conform with regulatory policy. J. ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management's current judgment of the ultimate outcome of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome. K. DEFERRED GAS PURCHASE COSTS. Columbia's gas distribution subsidiaries defer differences between gas purchase costs and the recovery of such costs in revenues, and adjust future billings for such deferrals on a basis consistent with applicable tariff provisions. L. REVENUE RECOGNITION. Columbia's gas distribution subsidiaries bill customers on a monthly cycle billing basis. Revenues are recorded on the accrual basis and include an estimate for gas delivered but unbilled at the end of each accounting period. Cash received in advance from sales of commodities to be delivered in the future is deferred and recognized as income upon delivery of the commodity. M. ENVIRONMENTAL EXPENDITURES. Columbia accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated, regardless of when expenditures are made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and, when possible, site-specific costs. The reserve is adjusted as further information is developed or circumstances change. Rate-regulated subsidiaries applying SFAS No. 71 establish a regulatory asset on the balance sheet to the extent that future recovery of environmental remediation costs is probable through the regulatory process. N. ACCOUNTS RECEIVABLE SALES PROGRAM. Columbia enters into agreements with third parties to sell certain accounts receivable without recourse. These sales are reflected as reductions of accounts receivable in the accompanying consolidated balance sheets and as operating cash flows in the accompanying consolidated statements of cash flows. The costs of this program, which are based upon the purchasers' level of investment and borrowing costs, are charged to other income in the accompanying consolidated statements of income. O. USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. REGULATORY MATTERS In 1993, the Federal Energy Regulatory Commission (FERC) directed Columbia Gulf to show cause as to why it had not sought FERC abandonment authorization to reduce capacity on its mainline facility. In an August 8, 1997 order, the FERC approved a settlement between Columbia Gulf and FERC's enforcement staff requiring Columbia Gulf to conduct a 30-day open season on additional firm mainline capacity up to its certificated design. Although certain of Columbia Gulf's customers challenged the terms of the settlement, Columbia Gulf concluded the open season on December 15, 1997 which resulted in requests for capacity that exceeded the capacity specified in Columbia Gulf's FERC certificate. In orders issued in December 1998 and 1999, the FERC has rejected challenges to the settlement and denied rehearing. In its order issued December 22, 1999, the FERC affirmed the validity of the 1997 open 37 38 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) season but indicated that an additional open season in compliance with the settlement will be necessary. In early February 2000, several appeals of the FERC's orders in this proceeding were filed. Columbia Gulf filed an application with the FERC on June 5, 1998, for authority to increase the maximum certificated capacity of its mainline facilities. The expansion project, referred to as Mainline `99, increased Columbia Gulf's certificated capacity to nearly 2.2 Bcf/day, by replacing certain compressor units and increasing the horsepower capacity of other compressor stations. Various shippers contracted for the additional service through an open bidding process held in late 1997 and early 1998. On February 10, 1999, the FERC issued an order approving Columbia Gulf's June 1998 filing and construction commenced on March 3, 1999. On March 12, 1999, requests for rehearing of the FERC order were filed by three parties. On January 31, 2000, the FERC issued an order denying the requests for rehearing and validating the open season held in conjunction with Mainline `99. Appeals challenging the FERC's authorization of the Mainline `99 facilities have been filed and are pending before the United States Court of Appeals for the District of Columbia. Columbia Transmission's rate case settlement, approved by the FERC in April 1997, provided for a hearing in the fall of 1998 to address environmental cost recovery that was excluded from the settlement. As a result of settlement discussions, the active parties reached an agreement on the overall components of an environmental settlement. The comprehensive agreement includes such major components as Columbia Transmission's total allowed recovery of environmental remediation program costs and the disposition of any proceeds received by Columbia Transmission from insurance carriers and others. Columbia Transmission filed the stipulation and agreement with the FERC on April 5, 1999 and on September 15, 1999, the FERC approved the settlement. No requests for rehearing were filed. The approval of the settlement did not have a material impact on Columbia's consolidated financial results. The distribution subsidiaries (Distribution) continue to pursue initiatives that give retail customers the opportunity to purchase natural gas directly from marketers and to use Distribution's facilities for transportation services. These opportunities are being pursued through regulatory initiatives in all of its jurisdictions, which resulted in transportation programs being initiated in all five of its service areas. Once fully implemented, these programs would reduce Distribution's merchant function and provide all customer classes with the opportunity to obtain gas supplies from alternative merchants. As these programs expand to all customers, regulations will have to be implemented to provide for the recovery of transition capacity costs and other transition costs incurred by a utility serving as the supplier of last resort if the marketing company cannot supply the gas. Transition capacity costs are created as customers enroll in these programs and purchase their gas from other suppliers, leaving Distribution with pipeline capacity it has contracted for but no longer needs. The state commissions in Distribution's five jurisdictions are at various stages in addressing these issues and other transition considerations. Distribution is currently recovering, or has the opportunity to recover, the costs resulting from the unbundling of its services and believes that most of such future costs and costs resulting from being the supplier of last resort will be mitigated or recovered. On October 25, 1999, Columbia of Ohio and a group comprising diverse interested parties, also known as the Collaborative, filed with the Public Utilities Commission of Ohio (PUCO) a third amendment to its 1994 rate case. The filing, which was approved by the PUCO on December 2, 1999, extends Columbia of Ohio's CHOICE(SM) program through October 31, 2004, freezes base rates through October 31, 2004 and resolves the issue of transition capacity costs. Under the agreement, Columbia of Ohio would assume total financial risk for mitigation of transition capacity costs at no additional cost to customers. Among other items, Columbia of Ohio would have the opportunity to utilize non-traditional revenue sources as a means of offsetting the costs. 3. NiSOURCE ACQUISITION On November 1, 2000, NiSource Inc. (NiSource) completed its acquisition of Columbia for an aggregate consideration of approximately $6 billion, primarily consisting of 72.4 million shares of common stock valued at $1,761 million, with the remaining approximately $3,888 million paid in cash and Stock Appreciation Income Linked Securities(SM), referred to as SAILS(SM), (units each consisting of zero coupon debt security coupled with a forward equity contract) valued at $114 million. NiSource also assumed approximately $2 billion in Columbia debt. As part of the Merger Agreement, the stock options under Columbia's Long-Term Incentive Plans were cancelled. The holders of the stock options received approximately $120.6 million from the cash-out of the stock options. The acquisition of Columbia by NiSource triggered change in control payments of approximately $44.5 million under certain employment agreements. The cost of the cash-out of the stock options and the change of control payments of approximately $155.9 million were charged to expense in the fourth quarter of 2000. As provided for in the Merger Agreement, NiSource organized a new company that will serve as the holding company for Columbia and its subsidiaries. 38 39 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 4. RESTRUCTURING ACTIVITIES During 2000, Columbia developed and began the implementation of a plan to restructure its operations as a result of the acquisition of Columbia by NiSource, discussed above. The restructuring plan included a severance program, a transition plan to implement operational efficiency throughout NiSource's operations and a voluntary early retirement program (See Note 10). As a result of the restructuring plan, it is estimated that approximately 781 management, professional, administrative and technical positions have been or will be eliminated. In October 2000, Columbia recorded pre-tax charges of $66.9 million in operating expense representing restructuring costs. This charge included $47.5 million for severance and related benefits, $10.8 million for costs to terminate leases and $8.6 million for relocation costs. As of December 31, 2000, approximately 288 employees had been terminated as a result of the restructuring plan. At December 31, 2000, the consolidated balance sheet reflected an accrual of $61.7 million related to the restructuring plan. 5. DISCONTINUED OPERATIONS On May 22, 2000, as a result of its ongoing strategic assessment, Columbia announced that it decided to sell Columbia Propane Corporation (Columbia Propane), a propane marketer. Columbia also announced its decision to sell Columbia Petroleum Corporation (Columbia Petroleum), a diversified petroleum distribution company. On January 31, 2001, Columbia signed a definitive agreement to sell the stock and assets of Columbia Propane to AmeriGas Partners L.P. (AmeriGas) for approximately $208 million, including $53 million of AmeriGas partnership common units. The transaction is expected to close in the second quarter of 2001. Columbia Propane and Columbia Petroleum are reported as discontinued operations and therefore the financial statements for prior periods have been reclassified accordingly. In the third quarter 2000, Columbia sold its Retail Mass Marketing business to The New Power Company. The proceeds from the sale were $44.2 million. Columbia Energy Services ceased operations of its Major Accounts business during the third quarter of 2000. Columbia Energy Services' Wholesale and Trading operations, Major Accounts and Retail Mass Markets businesses are reported as discontinued operations and at December 31, 2000, have essentially ceased all operations. The revenues from discontinued operations were $867.4 million (Gas $187 million, Power Trading $12.2 million, Propane $331 million, Petroleum $300.5 million and Other $36.7 million) and $5,761.8 million (Gas $4,433.3 million, Power Trading $1,021 million, Propane $152.9 million, Petroleum $127.7 million and Other $26.9 million) and $4,139.1 million (Gas $3,504.1 million, Power Trading $564.4 million, Propane $63.1 million and Other $7.5 million) for the years ended December 31, 2000, December 31, 1999 and December 31, 1998, respectively. The loss from discontinued operations and the estimated loss on disposal information are provided in the following table:
($ in millions) 2000 1999 1998 ================================================================================ Loss from discontinued operations (2.0) (175.9) (61.1) Income tax benefit (0.5) (63.1) (21.4) -------------------------------------------------------------------------------- NET LOSS FROM DISCONTINUED OPERATIONS (1.5) (112.8) (39.7) -------------------------------------------------------------------------------- Estimated loss on disposal (226.6) (39.5) -- Income tax benefits (67.2) (13.7) -- -------------------------------------------------------------------------------- NET ESTIMATED LOSS ON DISPOSAL (159.4) (25.8) -- --------------------------------------------------------------------------------
The net assets of the discontinued operations were as follows:
($ in millions) 2000 1999 =============================================================================== NET ASSETS OF DISCONTINUED OPERATIONS Accounts receivable, net 91.3 416.7 Property, Plant and Equipment, net 212.2 212.0 Other assets 70.2 239.6 Accounts payable (68.3) (388.4) Other liabilities (69.1) (69.9) -------------------------------------------------------------------------------- NET ASSETS OF DISCONTINUED OPERATIONS 236.3 410.0 --------------------------------------------------------------------------------
39 40 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 6. COMMON STOCK EQUITY A. STOCK SPLIT EFFECTED IN THE FORM OF A STOCK DIVIDEND. On May 20, 1998, Columbia's Board of Directors (Columbia's Board) approved a three-for-two common stock split, effected in the form of a 50% stock dividend (stock split), on June 15, 1998, payable to shareholders of record as of June 1, 1998. In connection with the stock split, 27.8 million shares were issued on June 15, 1998, and $277.9 million was transferred to common stock from retained earnings. The value of fractional shares resulting from the stock split was determined at the closing price on June 1, 1998, and $0.6 million was paid in cash to the shareholders for fractional-share interests. All references in the financial statements and notes to the number of common shares outstanding except where otherwise noted, reflect the retroactive effect of the stock split. B. TREASURY STOCK. In March 2000, Columbia announced that it had restarted its open market share repurchase program, that was authorized by Columbia's Board. Under the recommenced program, Columbia was allowed to repurchase up to $300 million of its common shares through July 14, 2000. The repurchase program authorized Columbia to make purchases in the open market or otherwise. The timing and terms of purchases, and the number of shares actually purchases, were determined by management based on several factors including market conditions. Purchased shares were held in treasury at cost and were available for general corporate purposes, resale or retirement. During 2000, Columbia purchased 1,889,800 common shares at a cost of $114.1 million under the recommenced program. As of July 14, 2000, Columbia had purchased 4,368,300 common shares at a cost of $249.1 million. In November 2000, as part of the merger of Columbia with NiSource, the Treasury Stock was retired. C. COMMON STOCK - AMENDMENTS. At Columbia's Annual Meeting of Shareholders held on May 19, 1999, the shareholders voted to approve an amendment of Columbia's Restated Certificate of Incorporation to increase the authorized number of shares of common stock from 100 million to 200 million and decrease the par value of common stock from $10 to $.01 per share. This change resulted in a transfer during the second quarter of 1999 of $834.3 million from Common Stock to Additional Paid In Capital. 7. RISK MANAGEMENT ACTIVITIES Columbia's exploration and production subsidiary is exposed to market risk due primarily to fluctuations in commodity prices. In order to help minimize this risk, Columbia has adopted a policy that provides for commodity hedging activities to help ensure stable cash flow, favorable prices and margins. Financial instruments authorized for use by Columbia for hedging include futures, swaps and options. Columbia's exploration and production subsidiary hedged a portion of its gas production that was subject to price volatility. At December 31, 2000, there were 7,676 open contracts representing a notional quantity amounting to 67.3 Bcf of commodity contracts for natural gas production through December 2002 at an average price of $3.66 per Mcf. Also at December 31, 2000, there were 23,009 open contracts representing a notional quantity amounting to 201.8 Bcf of basis contracts through 2005 at an average price of $.22 per Mcf. A total of $188.6 million of unrealized losses were deferred on the consolidated balance sheets with respect to these open contracts. During the year ended December 31, 2000, $44.2 million of losses were realized on contracts settled. At December 31, 1999, there were 4,214 open contracts representing a notional quantity amounting to 6.6 Bcf of commodity contracts and 30.4 Bcf of basis contracts for natural gas production through February and October 2000, respectively at a combined average price of $3.61 per Mcf. A total of $6.1 million of unrealized gains had been deferred on the consolidated balance sheets, at December 31, 1999, with respect to these open contracts. During the year ended December 31, 1999, $0.5 million of losses were realized on contracts settled. 8. NEW ACCOUNTING STANDARDS A. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). This statement, as amended, 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. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative depends on the intended use of the 40 41 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) derivative and resulting designation. A company may implement SFAS No. 133 as of the beginning of any fiscal quarter, however the statement cannot be applied retroactively. The adoption of this statement on January 1, 2001, is estimated to result in a cumulative after-tax increase to net income of approximately $5 million and an after-tax reduction to other comprehensive income of approximately $35 million. The adoption is also estimated to result in approximately $165 million of derivatives to be recognized on the consolidated balance sheet as assets and approximately $210 million of derivatives to be recognized as liabilities. B. In September 2000, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, a Replacement of FASB Statement No. 125" (SFAS No. 140). This statement replaces FASB Statement No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." It revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, but it carries over most of Statement 125's provisions without reconsideration. This statement provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. Those standards are based on consistent application of a financial-components approach that focuses on control. Under that approach, after a transfer of financial assets, an entity recognizes the financial and servicing assets it controls and the liabilities it has incurred, derecognizes financial assets when control has been surrendered, and derecognizes liabilities when extinguished. This Statement provides consistent standards for distinguishing transfers of financial assets that are sales from transfers that are secured borrowings. This statement has no new impact on Columbia's current accounts receivable sales program. C. In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements." This SAB summarized certain of the SEC Staff's views in applying generally accepted accounting principles to revenue recognition in financial statements. In June 2000, the SEC issued SAB No. 101B, which delayed the implementation of SAB No. 101 until no later than the fourth fiscal quarter of fiscal years beginning after December 15, 1999. The adoption of this SAB did not have a material effect on Columbia's financial statements. 41 42 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 9. INCOME TAXES The components of income tax expense are as follows:
Year Ended December 31, ($ in millions) 2000 1999 1998 ===================================================================================== INCOME TAXES Current Federal 63.4 125.7 114.5 State 7.4 4.8 2.0 ------------------------------------------------------------------------------------- Total Current 70.8 130.5 116.5 ------------------------------------------------------------------------------------- Deferred Federal 102.0 71.4 50.8 State 19.0 (22.3) (13.6) ------------------------------------------------------------------------------------- Total Deferred 121.0 49.1 37.2 ------------------------------------------------------------------------------------- Deferred Investment Credits (1.4) (1.5) (1.5) ------------------------------------------------------------------------------------- Income Taxes Included in Continuing Operations 190.4 178.1 152.2 ------------------------------------------------------------------------------------- Income Taxes Related to Discontinued Operations (67.7) (76.8) (21.4) ------------------------------------------------------------------------------------- TOTAL INCOME TAXES 122.7 101.3 130.8 -------------------------------------------------------------------------------------
Total income taxes from continuing operations are different from the amount that would be computed by applying the statutory Federal income tax rate to book income before income tax. The major reasons for this difference are as follows:
Year Ended December 31, ($ in millions) 2000 1999 1998 ====================================================================================================================== Income before income taxes from continuing operations 485.0 565.9 461.1 Tax expense at statutory Federal income tax rate 169.8 35.0% 198.1 35.0% 161.4 35.0% Increases (reductions) in taxes resulting from: State income taxes, net of Federal income tax benefit 17.2 3.6 (11.4) (2.0) (7.5) (1.6) Estimated non-deductible expenses 17.5 3.6 1.4 0.2 1.6 0.3 Effect of change in deferred taxes previously provided (3.3) (0.7) (3.5) 1.5 0.3 (0.6) Other (10.8) (2.2) (6.5) (1.1) (4.8) (1.0) ----------------------------------------------------------------------------------------------------------------------- INCOME TAXES FROM CONTINUING OPERATIONS 190.4 39.3% 178.1 31.5% 152.2 33.0% -----------------------------------------------------------------------------------------------------------------------
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The principal components of Columbia's net deferred tax liability are as follows:
At December 31, ($ in millions) 2000 1999 ====================================================================================== Deferred tax liabilities Property basis differences 768.9 728.1 Gas purchase costs 80.1 47.6 Investment in Partnerships 2.9 5.4 Other 33.5 28.1 -------------------------------------------------------------------------------------- Gross Deferred Tax Liabilities 885.4 809.2 -------------------------------------------------------------------------------------- Deferred tax assets Estimated rate refunds (5.9) (12.7) Inventory (15.9) (16.3) Benefit plan accruals (7.2) (12.5) Environmental liabilities (7.1) (14.2) State tax loss carryforwards (33.6) (43.7) Deferred revenue (6.0) (20.8) Other (32.9) (57.0) -------------------------------------------------------------------------------------- Gross Deferred Tax Assets (108.6) (177.2) -------------------------------------------------------------------------------------- Deferred Tax Asset Valuation Allowance 7.7 11.4 -------------------------------------------------------------------------------------- TOTAL NET DEFERRED TAX LIABILITY 784.5 643.4 -------------------------------------------------------------------------------------- Deferred income taxes related to current assets and liabilities (17.7) 18.5 -------------------------------------------------------------------------------------- Deferred Income Taxes-Noncurrent 766.8 661.9 --------------------------------------------------------------------------------------
42 43 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) As reflected by the valuation allowance in the table above, Columbia had potential tax benefits of $7.7 million and $11.4 million at December 31, 2000, and 1999, respectively, which were not recognized in the statements of consolidated income when generated. These benefits result primarily from state income tax operating loss carryforwards which are available to reduce future tax liabilities. The net decrease of $3.7 million in the valuation allowance reflects realization of state income tax carry forward benefits upon the sale of certain assets. The expiration of the tax loss carryforward benefits, net of federal taxes, in 2001 is $0.1 million, in 2002 is $0.1 million, in 2003 is $0.1 million, in 2004 is $0.1 million, in 2005 is $0.1 million and beyond is $33.1 million. 10. PENSION AND OTHER POSTRETIREMENT BENEFITS Columbia has a noncontributory, qualified defined benefit pension plan covering essentially all employees. Benefits are based primarily on years of credited service and employees' highest three-year average annual compensation in the final five years of service. Effective January 1, 2000, Columbia adopted a cash balance feature to the pension plan that provides benefits based on a percentage, which may vary with age and years of service, of current eligible compensation and current interest credits. Columbia's funding policy complies with Federal law and tax regulations. In addition, Columbia has a nonqualified pension plan that provides benefits to some employees in excess of the qualified plan's Federal tax limits. Columbia also provides medical coverage and life insurance to retirees. Essentially all active employees are eligible for these benefits upon retirement after completing ten consecutive years of service after age 45. Normally, spouses and dependents of retirees are also eligible for medical benefits. Columbia is reflecting the information presented below as of September 30, rather than December 31. The effect of utilizing September 30, rather than December 31, is not significant. During 2000, Columbia announced the introduction of a voluntary incentive retirement program (VIRP). Approximately 1,880 employees were eligible for the VIRP, which provides a retirement incentive for active employees who were age fifty and above with at least five years of service as of certain retirement-window dates. During the acceptance periods, approximately 1,337 employees elected early retirement. The majority of the retirements occurred during 2000. The VIRP resulted in special termination benefits of $59.3 million and curtailment losses of $47.7 million. The curtailment losses were offset by previously unrecognized actual gains. As a result of the VIRP, Columbia recognized $35.7 million of net settlement gains. On October 13, 2000, the Columbia Retirement Board determined that, under the terms of the Retirement Plan of Columbia Energy Group Companies (The Plan), a partial plan termination had occurred. As a result, participants in the Plan will be granted additional vesting service if they have terminated or will terminate their employment with Columbia Energy Group or any of its subsidiaries between January 1, 1999 and June 30, 2001. Employees who have terminated or will terminate employment during this time period with less than 5 years of plan participation will be 100% vested in the Plan as of their date of termination. As a result, Columbia recorded additional expense of approximately $3.1 million in October 2000. 43 44 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The following tables provide a reconciliation of the plans' funded status and amounts reflected in Columbia's consolidated balance sheets at December 31:
PENSION BENEFITS OTHER BENEFITS ($ in millions) 2000 1999 2000 1999 ============================================================================================= CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year 883.8 946.8 182.2 198.9 Service cost 29.5 30.6 11.1 12.6 Interest cost 65.0 62.9 16.6 14.0 Plan participants' contributions -- -- 2.6 2.4 Plan amendments -- 3.9 -- 4.5 Actuarial (gain) loss 13.3 (59.8) (10.5) (12.2) Partial plan termination 3.1 -- -- -- Curtailments 47.7 -- 35.4 -- Settlements (269.2) -- -- (24.5) Special termination benefits 59.3 -- 31.9 -- Actual expense paid -- (4.7) -- -- Benefits paid (55.9) (95.9) (9.3) (13.5) --------------------------------------------------------------------------------------------- Benefit obligation at end of year 776.6 883.8 260.0 182.2 --------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year 1,201.1 1,091.5 115.8 117.0 Actual return on plan assets 135.7 210.0 13.6 26.0 Columbia contributions 0.4 -- 17.5 15.5 Plan participants' contributions -- -- 2.6 2.4 Settlements (269.2) -- -- (31.6) Actual expense paid -- (4.7) -- -- Benefits paid (55.9) (95.7) (9.2) (13.5) --------------------------------------------------------------------------------------------- Fair value of plan assets at end of year 1,012.1 1,201.1 140.3 115.8 --------------------------------------------------------------------------------------------- Funded status of plan at end of year 235.5 317.3 (119.7) (66.4) Unrecognized actuarial net gain (266.8) (403.4) (32.3) (54.1) Unrecognized prior service cost 41.3 45.2 2.4 2.6 Unrecognized transition obligation 2.3 3.5 -- -- Fourth quarter contributions 0.4 -- 7.0 3.3 --------------------------------------------------------------------------------------------- PREPAID (ACCRUED) BENEFIT COST 12.7 (37.4) (142.6) (114.6) ---------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS ---------------- -------------- 2000 1999 2000 1999 ============================================================================================= WEIGHTED-AVERAGE ASSUMPTIONS AS OF SEPTEMBER 30, Discount rate assumption 8.00% 7.75% 8.00% 7.75% Compensation growth rate assumption 4.50% 4.50% 4.50% 4.50% Medical cost trend assumption -- -- 5.50% 5.50% Assets earnings rate assumption 9.00% 9.00% 9.00%* 9.00%* ---------------------------------------------------------------------------------------------
* One of the several established medical trusts and the trust established for life insurance are subject to taxation which results in an after-tax asset earnings rate that is less than 9.00% 44 45 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The following table provides the components of the plans expense for each of the three years:
PENSION BENEFITS OTHER BENEFITS ($ in millions) 2000 1999 1998 2000 1999 1998 ==================================================================================================== NET PERIODIC COST Service cost 29.5 30.6 31.3 11.1 12.6 13.0 Interest cost 65.0 62.9 64.7 16.6 14.0 23.5 Expected return on assets (98.0) (94.1) (99.7) (7.7) (9.4) (18.3) Amortization of transition obligation 1.2 1.2 1.2 -- -- -- Recognized gain (18.3) (10.2) (17.5) (1.7) (2.1) (10.3) Prior service cost amortization 3.9 3.7 3.7 0.2 (0.4) -- Special charge for partial plan termination 3.1 -- -- -- -- -- Special termination benefit charge 59.3 -- -- 31.9 -- -- Settlement gain (95.0) -- -- -- (6.1) (46.6) ---------------------------------------------------------------------------------------------------- NET PERIODIC BENEFITS COST (BENEFIT) (49.3) (5.9) (16.3) 50.4 8.6 (38.7) ----------------------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
1% point 1% point increase decrease ===================================================================================================== Effect on service and interest components of net periodic cost $ 2.9 $ (2.6) Effect on accumulated postretirement benefit obligation $22.1 $(19.1) -----------------------------------------------------------------------------------------------------
During 1999 and 1998, Columbia and the trusts established by Columbia purchased insurance policies that provide both medical and life insurance with respect to liabilities to a selected class of current retirees. As a result, pre-tax gains in the amount of $6.1 million and $46.6 million were recorded in 1999 and 1998, respectively. The 1999 gain is reflected in the consolidated financial statements as a $4 million reduction to benefits expense, and a $2.1 million liability of certain rate-regulated companies. The 1998 gain is reflected in the financial statements as a $25.4 million reduction to benefits expense, and a $21.2 million liability of certain rate-regulated companies. 11. LONG-TERM DEBT The long-term debt (exclusive of current maturities) of Columbia and its subsidiaries is as follows:
At December 31, ($ in millions) 2000 1999 ==================================================================================================== Columbia Energy Group Debentures 6.61% Series B due November 28, 2002 281.5 281.5 6.80% Series C due November 28, 2005 281.5 281.5 7.05% Series D due November 28, 2007 281.5 281.5 7.32% Series E due November 28, 2010 281.5 281.5 7.42% Series F due November 28, 2015 281.5 281.5 7.62% Series G due November 28, 2025 229.2 229.2 ---------------------------------------------------------------------------------------------------- Total Debentures 1,636.7 1,636.7 Subsidiary Debt: Capitalized lease obligations 2.4 2.6 ---------------------------------------------------------------------------------------------------- TOTAL LONG-TERM DEBT 1,639.1 1,639.3 ====================================================================================================
In 1999, Columbia repurchased $52.45 million of its 7.62% Series G Debentures due November 28, 2025 at a price of approximately 99% of par value. The net impact of the early extinguishment of such debt was immaterial. Columbia has entered into interest rate swap agreements to modify the interest characteristics of its outstanding long-term debt. At December 31, 2000, Columbia has outstanding four interest rate swap agreements effective through November 28, 2002, on $200 million notional amounts of its 6.61% Series B Debentures due November 28, 2002. In addition, Columbia has outstanding an interest rate swap agreement effective through November 28, 2005, 45 46 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) on a $100 million notional amount of its 6.80% Series C Debentures due November 28, 2005. Under the terms of the agreements, Columbia pays interest based on a floating rate index and receives interest based on a fixed rate. The effect of these agreements is to modify the interest rate characterization of a portion of Columbia's long-term debt from fixed to variable. The effect of these interest rate swaps on interest expense in 2000 and 1999 was immaterial. The aggregate maturities of long-term debt and capitalized lease obligations during the next five years are as follows:
($ in millions) ================================================================================ 2001 0.2 2002 281.7 2003 0.2 2004 0.3 2005 281.9 --------------------------------------------------------------------------------
12. SHORT-TERM DEBT AND CREDIT FACILITIES During 2000, Columbia had two unsecured bank revolving credit facilities available that totaled $1.35 billion (Credit Facilities). On October 11, 2000, the Credit Facilities were amended and restated, and decreased in aggregate to $900 million. The existing $450 million 364-day facility was increased in size to $850 million, and is scheduled to expire in October 2001. The existing $900 million five-year facility was decreased in size to $50 million, shortened to a two-year facility expiring in October 2002, and will be solely used to support the issuance of letters of credit. Interest rates on borrowings under the Credit Facilities are based upon the London Interbank Offered Rate, Certificate of Deposit rate or Citibank's publicly announced "base rate." In addition, the Credit Facilities have a utilization fee if borrowings exceed a certain level. Facility fees and borrowing margins are based on Columbia's public debt ratings. The Credit Facilities contain certain covenants that must be met to borrow funds, including restrictions on the incurrence of liens and a maximum leverage ratio. Compensating balances are not required. Columbia had no borrowings outstanding under the Credit Facilities at December 31, 2000, and December 31, 1999, respectively. On October 28, 1999, Columbia issued a note payable outside of the Credit Facilities in the amount of $125 million at an interest rate of 6.70%. The note matured on January 28, 2000. As of December 31, 2000, Columbia had $14.6 million of letters of credit outstanding under the Credit Facilities. Fees for letters of credit issued are calculated at rates that are based on Columbia's public debt rating plus a commission of 0.125% to the issuing bank. In addition, Columbia had approximately $34.6 million of letters of credit outstanding to guarantee certain transactions of affiliates. Fees for the letter of credit issued were at rates of 0.625% to 1.0%. At December 31, 1999, Columbia had $54.7 million of letters of credit outstanding under the Credit Facilities. Columbia has an $850 million commercial paper program authorized and rated by the rating agencies. The commercial paper program is supported by the Credit Facilities. At December 31, 2000, Columbia had commercial paper outstanding of $521 million (net of discount) at a weighted-average interest rate of 7.76%. The maximum commercial paper indebtedness outstanding during the year occurred on December 5, 2000, in the amount $683.5 million at an average interest rate of 7.1%. At December 31, 1999, Columbia had commercial paper outstanding of $340.5 million (net of discount) at a weighted-average interest rate of 6.34%. Columbia was the guarantor on certain transactions of its former affiliates that were sold during 1999 and 2000. At December 31, 2000, Columbia had an $81.7 million letter of credit outstanding and has issued other guarantees and indemnities in the amount of $741.3 million. At December 31, 2000, approximately $14.5 million of investments were pledged as collateral on outstanding letters of credit related to Columbia's wholly-owned insurance company. 13. FAIR VALUE OF FINANCIAL INSTRUMENTS Statement of Financial Accounting Standards No. 107, "Disclosures about Fair Value of Financial Instruments," requires all entities to disclose the fair value of financial instruments, both assets and liabilities, recognized and not 46 47 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) recognized in the consolidated balance sheets, for which it is practicable to estimate a fair value. For purposes of this disclosure, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale. Fair value may be based on quoted market prices for the same or similar financial instruments or on valuation techniques, such as the present value of estimated future cash flows using a discount rate commensurate with the risks involved. As cash and temporary cash investments, current receivables, current payables, and certain other short-term financial instruments are all short-term in nature, their carrying amount approximates fair value. Columbia utilizes standby letters of credit (See Note 12) and does not believe it is practicable to estimate their fair value. The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: LONG-TERM INVESTMENTS Long-term investments include loans receivable ($5.8 million for 2000 and $7.7 million for 1999) whose estimated fair values are based on the present value of estimated future cash flows using an estimated rate for similar loans. Long-term investments also include pledged assets ($11.6 million for 2000 and $14.4 million for 1999), whose estimated fair value is based on the trading value provided by a financial institution. The financial instruments included in long-term investments are primarily reflected in Investments and Other Assets on the consolidated balance sheets. Long-term investments for which it is practicable to estimate fair value had carrying amounts of $17.5 million and $22.1 million, and estimated fair values of $17.2 million and $21.7 million at December 31, 2000, and 1999, respectively. There are no long-term investments for which it is not practicable to estimate fair value at December 31, 2000, and 1999. LONG-TERM DEBT The estimated fair value of Columbia's debentures, including current maturities and accrued interest, is based on estimates provided by brokers. Long-term debt of $1,647.4 million and $1,960.1 million at December 31, 2000, and 1999, have estimated fair values of $1,586.7 million and $1,858.4 million, respectively. The fair value of Columbia's interest rate swaps agreements are based on the amounts estimated to terminate or settle the agreements. At December 31, 2000, and December 31, 1999, Columbia had interest rate swaps agreements with notional amounts of $300 million. Columbia would have paid $3.9 million and $18 million to terminate the agreements at December 31, 2000, and December 31, 1999, respectively. ACCOUNTS RECEIVABLE SALES PROGRAM In October 1999, Columbia of Ohio entered into an agreement to sell, without recourse, substantially all of its trade accounts receivable to Columbia Accounts Receivable Corporation (CARC), a wholly-owned subsidiary of Columbia. At the same time, CARC entered into an agreement, with a third party, Canadian Imperial Bank of Commerce (CIBC), to sell a percentage ownership interest in a defined pool of accounts receivable (Sales Program). Under this Sales Program, CARC can transfer an undivided interest in a designated pool of its accounts receivable on an ongoing basis up to a maximum of $125 million until April 30, 2001, at which time the maximum decreases to $100 million. The amount available at any measurement date varies based upon the level of eligible receivables. Under this agreement, approximately $108 million of receivables were sold as of December 31, 2000. Under a separate agreement, in conjunction with the Sales Program, Columbia of Ohio acts as agent for CIBC, the ultimate purchaser of the receivables, by performing record keeping and cash collection functions for the accounts receivable sold by CARC. Columbia of Ohio receives a fee, which provides adequate compensation, for such services. 14. OTHER COMMITMENTS AND CONTINGENCIES A. BANKRUPTCY MATTERS. On November 28, 1995, Columbia and its wholly-owned subsidiary, Columbia Transmission emerged from Chapter 11 protection of the United States Bankruptcy Code under the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). Both Columbia and Columbia Transmission had operated under Chapter 11 protection from July 31, 1991, until emergence. Certain residual unresolved bankruptcy-related matters are still within the jurisdiction of the Bankruptcy Court. B. CAPITAL EXPENDITURES. Capital expenditures for 2001 are currently estimated at $379 million. Of this amount, $132 million is for transmission and storage operations, $113 million for distribution operations, $132 million for exploration and production operations and $2 million for other products and services. 47 48 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) C. OTHER LEGAL PROCEEDINGS. In the normal course of its business, Columbia and its subsidiaries have been named as defendants in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material adverse impact on Columbia's consolidated financial position or results of operations. D. ASSETS UNDER LIEN. Substantially all of Columbia Transmission's properties have been pledged to Columbia as security for debt owed by Columbia Transmission to Columbia. E. GUARANTEES AND INDEMNITIES. In connection with the purchase of National Propane Partners, L.P. (National Propane) interests, Columbia has provided an indemnity to reimburse the former Managing General Partner for income taxes that would be due if certain actions by Columbia result in the recognition of certain types of income or gain by the former Managing General Partner. F. INTERNAL REVENUE SERVICE (IRS) AUDIT. All unagreed issues associated with the audit of Columbia's 1995 federal income tax return have been settled with IRS Appeals. The field audit of tax years 1996 and 1997, currently in progress, is expected to be completed in 2001. Management believes adequate reserves have been established for issues related to these returns. G. OPERATING LEASES. Payments made in connection with operating leases are primarily charged to operation and maintenance expense as incurred. Such amounts were $71.6 million in 2000, $61.5 million in 1999 and $63.8 million in 1998. Future minimum rental payments required under operating leases that have initial or remaining noncancellable lease terms in excess of one year are:
($ in millions) ================================================================================ 2001 23.5 2002 20.7 2003 20.4 2004 19.8 2005 19.3 After 159.3 --------------------------------------------------------------------------------
H. PURCHASE COMMITMENTS. Columbia has service agreements that provide for pipeline capacity, transportation and storage services. These agreements which have expiration dates ranging from 2001 to 2014, provide for Columbia to pay fixed monthly charges. The estimated aggregate amounts of such payments at December 31, 2000, were:
($ in millions) ================================================================================ 2001 54.0 2002 49.7 2003 36.7 2004 33.0 2005 28.2 After 155.3 --------------------------------------------------------------------------------
Costs incurred under these contracts are generally recovered under Columbia's regulatory cost recovery mechanisms (See Note 2). I. ENVIRONMENTAL MATTERS. Columbia's subsidiaries are subject to extensive federal, state and local laws and regulations relating to environmental matters. These laws and regulations, which are constantly changing, require expenditures for corrective action at various operating facilities, waste disposal sites and former gas manufacturing sites for conditions resulting from past practices that have subsequently become subject to environmental regulation. Columbia's transmission subsidiaries have implemented programs to continually review compliance with existing environmental standards. In addition, the transmission subsidiaries have reviewed past operational activities and conducted remediation programs where necessary. 48 49 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Columbia Transmission is currently conducting assessment, characterization and remediation activities at specific sites under a 1995 Environmental Protection Agency (EPA) Administrative Order by Consent (AOC). The program pursuant to the AOC covers approximately 240 facilities, approximately 13,000 liquid removal points, approximately 2,200 mercury measurement stations, and about 3,700 storage wells. As of December 31, 2000, field characterization has been performed at many of these sites, and site characterization reports and remediation plans which must be submitted to EPA for approval are in various stages of development and completion. Significant remediation has taken place only at mercury measurement stations and at a limited number of the 240 facilities. Only those site investigation, characterization and remediation costs currently known and determinable can be considered "probable and reasonably estimable" under Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" (SFAS No. 5). As costs become probable and reasonably estimable, the associated reserves will be adjusted as appropriate. Columbia Transmission is unable, at this time, to accurately estimate the time frame and potential costs of the entire program. Management expects that as additional work is performed and more facts become available, it will be able to develop a probable and reasonable estimate for the entire program or a major portion thereof consistent with U.S. Securities and Exchange Commission's Staff Accounting Bulletin No. 92, SFAS No. 5, and American Institute of Certified Public Accountants Statement of Position 96-1. During 2000, actual expenditures of $16.9 million were charged to the liability resulting in a remaining liability at December 31, 2000, of $104.5 million. Columbia Transmission's environmental cash expenditures are expected to be approximately $17 million in 2001 and to remain at this level for the foreseeable future. These expenditures will be charged against the previously recorded liability. Consistent with Statement of Financial Accounting Standards No. 71, a regulatory asset has been recorded to the extent environmental expenditures are probable of recovery through rates. Management does not believe that Columbia Transmission's environmental expenditures will have a material adverse effect on its operations, liquidity or financial position, based on known facts and existing laws and regulations and the long time period over which expenditures will be made. In addition, predecessor companies of Columbia Transmission may have been involved in the operation of manufactured gas plants. When such plants were abandoned, material used and created in the process was sometimes buried at the site. As of the date of this report, Columbia Transmission is unable to determine if it will become liable for any characterization or remediation costs at such sites. Distribution's primary environmental issues relate to 18 former manufactured gas plant sites. Investigations or remedial activities are currently underway at six sites and remedial construction has been completed at two sites. Additional site investigations may be required at some of the remaining sites. To the extent Distribution's site investigations have been conducted, remediation plans developed and any responsibility for remediation established, the appropriate estimated liabilities have been recorded. Regulatory assets have also been recorded for a majority of these costs as rate recovery has been authorized or is anticipated. In spring 2000, Columbia Transmission Communication Corporation (Transcom) received directives from The Philadelphia District of the U.S. Army Corps of Engineers (Philadelphia District) and an administrative order from The Pennsylvania Department of Environmental Protection (PA DEP) addressing alleged violations of federal and state laws resulting from construction activities associated with the Corporation's laying fiber optic cable along portions of a route between Washington, D.C. and New York City. The order and directives required Transcom to largely cease construction activities. On September 18, 2000, Transcom entered into a voluntary settlement agreement with the Philadelphia District under which Transcom contributed $1.2 million to the Pennsylvania chapter of the Nature Conservancy and the Philadelphia District lifted its directives. As a result of the voluntary agreement with the Philadelphia District and communications with the PA DEP, the Maryland Department of the Environment and the Baltimore District of the US Army Corps of Engineers, work in Pennsylvania and Maryland is now ongoing. Transcom cannot predict the effect of the ongoing discussions on the completion schedule for the project, nor the nature or amount of total remedies that may be sought in connection with the foregoing construction activities. Columbia Propane's primary environmental issues relate to former manufactured gas plant sites acquired in the acquisition of National Propane for which accruals have been made. Investigations are currently underway at one site. One other known former manufactured gas plant site is inactive. It is possible that former manufactured gas plant sites exist at two other National Propane properties. Management does not believe that Columbia Propane's environmental expenditures will have a material adverse effect on Columbia's consolidated financial results. The eventual total cost of full future environmental compliance for Columbia is difficult to estimate due to, among other things: (1) the possibility of as yet unknown contamination, (2) the possible effect of future legislation and 49 50 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) new environmental agency rules, (3) the possibility of future litigation, (4) the possibility of future designations as a potential responsible party by the EPA and the difficulty of determining liability, if any, in proportion to other responsible parties, (5) possible insurance and rate recoveries, and (6) the effect of possible technological changes relating to future remediation. However, reserves have been established based on information currently available, which resulted in a total recorded net liability of approximately $106.4 million for Columbia at December 31, 2000. As new issues are identified, additional liabilities will be recorded. It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects most environmental assessment and remediation costs to be recoverable through rates. 15. INTEREST INCOME AND OTHER, NET
Year Ended December 3l, ($ in millions) 2000 1999 1998 ================================================================================ Interest income 22.8 20.0 14.7 Gain on sale of assets 221.0 -- -- Miscellaneous (7.5) 14.9 -- -------------------------------------------------------------------------------- TOTAL INTEREST INCOME AND OTHER, NET 236.3 34.9 14.7 --------------------------------------------------------------------------------
16. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31, ($ in millions) 2000 1999 1998 ================================================================================ Interest on debentures 134.6 138.0 140.4 Interest on short-term debt 26.3 18.2 10.5 Discount on prepayment transactions 22.6 2.3 -- Interest on rate refunds 0.6 3.1 2.3 Interest on prior years' taxes (11.5) 6.2 (6.3) Allowance for borrowed funds used and interest during construction (3.0) (3.6) (2.7) -------------------------------------------------------------------------------- TOTAL INTEREST EXPENSE AND RELATED CHARGES 169.6 164.2 144.2 --------------------------------------------------------------------------------
17. BUSINESS SEGMENT INFORMATION Columbia is a registered holding company under the Public Utility Holding Company Act of 1935, as amended, and derives substantially all of its revenues and earnings from the operating results of its 19 direct subsidiaries. During 2000, Columbia revised the presentation of its business segments and, in accordance with generally accepted accounting principles, all prior periods have been restated. Columbia's operations are divided into four primary business segments. The transmission and storage segment offers transportation and storage services for local distribution companies, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia. The distribution segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. The exploration and production segment explores for, develops, produces and markets gas and oil in the United States and in Canada. The other products and services segment primarily engages in the construction of a dark-fiber optics telecommunications network along its pipeline rights-of-way between Washington, D.C. and New York City. 50 51 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) The following tables provide information concerning Columbia's major business segments. Revenues include intersegment sales to affiliated subsidiaries, which are eliminated when consolidated. Affiliated sales are recognized on the basis of prevailing market or regulated prices. Operating income is derived from revenues and expenses directly associated with each segment.
($ in millions) 2000 1999 1998 ================================================================================ REVENUES Transmission and Storage Unaffiliated 607.8 571.5 546.0 Intersegment 248.0 264.9 292.7 -------------------------------------------------------------------------------- TOTAL 855.8 836.4 838.7 -------------------------------------------------------------------------------- Distribution Unaffiliated 2,037.9 2,021.9 1,868.5 Intersegment (2.0) 0.9 1.0 -------------------------------------------------------------------------------- TOTAL 2,035.9 2,022.8 1,869.5 -------------------------------------------------------------------------------- Exploration and Production Unaffiliated 176.5 143.4 125.4 Intersegment 2.0 1.4 2.1 -------------------------------------------------------------------------------- TOTAL 178.5 144.8 127.5 -------------------------------------------------------------------------------- Other Products and Services Unaffiliated 49.9 96.7 23.3 Intersegment 0.2 (0.4) (0.1) -------------------------------------------------------------------------------- TOTAL 50.1 96.3 23.2 -------------------------------------------------------------------------------- Corporate Unaffiliated 10.0 -- -- Intersegment (247.0) (266.8) (295.7) -------------------------------------------------------------------------------- TOTAL (237.0) (266.8) (295.7) -------------------------------------------------------------------------------- Transportation Costs* (24.3) (32.6) (17.1) -------------------------------------------------------------------------------- CONSOLIDATED 2,859.0 2,800.9 2,546.1 --------------------------------------------------------------------------------
*Transportation revenues on consolidated income statement were reduced by these costs. 51 52 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
($ in millions) 2000 1999 1998 ================================================================================ OPERATING INCOME (LOSS) Transmission and Storage 264.9 350.1 326.1 Distribution 176.0 254.6 225.8 Exploration and Production 49.3 44.2 37.2 Other Products and Services (32.3) 63.8 2.3 Corporate (39.6) (17.5) (0.8) -------------------------------------------------------------------------------- CONSOLIDATED 418.3 695.2 590.6 -------------------------------------------------------------------------------- DEPRECIATION & DEPLETION Transmission and Storage 109.3 106.2 101.8 Distribution 57.4 54.5 82.2 Exploration and Production 33.0 36.9 36.5 Other Products and Services 0.2 0.4 0.3 Corporate 4.8 4.2 5.0 Adjustments and eliminations 0.5 0.5 0.5 -------------------------------------------------------------------------------- CONSOLIDATED 205.2 202.7 226.3 -------------------------------------------------------------------------------- ASSETS Transmission and Storage 2,940.0 2,814.1 2,837.6 Distribution 3,369.4 2,831.3 2,665.1 Exploration and Production 851.2 774.3 590.9 Other Products and Services 370.6 325.9 358.4 Corporate 4,638.1 4,830.2 4,298.0 Adjustments and eliminations (4,543.1) (4,538.5) (4,254.8) -------------------------------------------------------------------------------- CONSOLIDATED 7,626.2 7,037.3 6,495.2 -------------------------------------------------------------------------------- CAPITAL EXPENDITURES Transmission and Storage 128.9 183.4 210.0 Distribution 139.6 145.5 151.9 Exploration and Production 128.9 166.5 75.7 Other Products and Services 96.0 57.3 12.1 Corporate 4.9 5.4 11.0 -------------------------------------------------------------------------------- CONSOLIDATED 498.3 558.1 460.7 --------------------------------------------------------------------------------
52 53 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) 18. QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly financial data does not always reveal the trend of Columbia's business operations due to nonrecurring transactions and seasonal weather patterns which affect earnings and related components of net revenues and operating income.
First Second Third Fourth ($ in millions, except per share data) Quarter Quarter Quarter Quarter =================================================================================================== 2000 Net Revenues 619.4 386.6 354.0 576.5 Operating Income (Loss) 273.7 79.5 73.6 (8.5) Income from Continuing Operations 143.4 82.9 19.5 48.8 Gain (Loss) from Discontinued Operations - net of taxes 6.3 (35.2) (83.3) (48.7) Net Income (Loss) 149.7 47.7(a) (63.8) 0.1(b) =================================================================================================== 1999 Net Revenues 627.4 370.7 333.3 576.6 Operating Income 283.4 74.7 57.9 279.2 Income from Continuing Operations 160.9 35.3 20.5 171.1 (Loss) from Discontinued Operations - net of taxes (10.5) (9.2) (43.2) (75.7) Net Income (Loss) 150.4(c) 26.1(d) (22.7) 95.4(e) ===================================================================================================
(a) Includes $59 million gain on the sale of Cove Point LNG. (b) Includes $86.4 million gain on the sale of Columbia Electric's four power generation plants and the remainder of Columbia Electric. (c) Includes $20.6 million gain from the producer contract settlement stemming from Columbia's bankruptcy proceedings concluded in 1995. (d) Includes $6.9 million benefit from the reduction in tax expense for state net operating loss carryforwards. (e) Includes $49 million gain recorded in connection with the termination of a cogeneration power purchase contract and $7.8 million gain on the sale of Columbia's interest in the Trailblazer pipeline system. 19. EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) During 1999, Columbia Resources' acquisition strategy involved six transactions totaling approximately $61 million, added reserves of 65 Bcfe and expanded the gathering infrastructure by more than 450 miles of pipeline. Also in 1999, Columbia Resources discovered reserves in West Virginia in the Trenton-Black river formation at depths exceeding 10,000 feet. On August 7, 1997, Columbia Resources acquired Alamco, Inc. (Alamco), a gas and oil production company operating in the Appalachian Basin. The information contained in the following tables includes amounts attributable to the operations and reserves of Alamco from August 7, 1997. 53 54 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Reserve information contained in the following tables for the U.S. and Canadian properties is management's estimate, which was reviewed by the independent consulting firms of Ryder Scott Company Petroleum Engineers for the U.S. reserves and Sproule Associates Limited for the Canadian reserves. Reserves are reported as net working interest. Gross revenues are reported after deduction of royalty interest payments.
RESERVE QUANTITY INFORMATION United States Canada ----------------------------------------------------------------------------------------------- Oil & Other Oil & Other Gas Liquids Gas Liquids Proved Reserves (Bcf) (000 Bbls) (Bcf) (000 Bbls) =============================================================================================== Reserves as of December 31, 1997 800.5 1,700 -- -- Revisions of previous estimate (23.1) 178 -- -- Extensions, discoveries and other additions 60.7 94 -- -- Production (39.0) (201) (0.1) (13) Purchase of reserves-in-place -- -- 1.1 77 Sale of reserves-in-place (9.6) -- -- -- ----------------------------------------------------------------------------------------------- Reserves as of December 31, 1998 789.5 1,771 1.0 64 Revisions of previous estimate 34.4 99 -- 9 Extensions, discoveries and other additions 116.8 38 0.3 40 Production (45.6) (175) (0.2) (10) Purchase of reserves-in-place 58.2 539 -- -- Sale of reserves-in-place (2.8) -- -- -- ----------------------------------------------------------------------------------------------- Reserves as of December 31, 1999 950.5 2,272 1.1 103 Revisions of previous estimate 82.2 (764) -- (9) Extensions, discoveries and other additions 120.1 30 -- 95 Production (52.3) (204) (0.1) (11) Purchase of reserves-in-place 2.5 4 -- -- Sale of reserves-in-place (4.4) (117) -- -- ----------------------------------------------------------------------------------------------- RESERVES AS OF DECEMBER 31, 2000 1,098.6 1,221 1.0 178 ----------------------------------------------------------------------------------------------- Proved developed reserves as of December 31, 1998 586.2 1,436 1.0 64 1999 697.2 1,953 1.1 103 2000 820.6 1,043 1.0 178 -----------------------------------------------------------------------------------------------
CAPITALIZED COSTS United States Canada Total ---------------------------------------------------------------------------------------------------------------------------------- ($ in millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 ================================================================================================================================== CAPITALIZED COSTS AT YEAR END Proved properties 838.4 762.5 673.2 9.4 1.7 1.4 847.8 764.2 674.6 Unproved properties (a) 75.2 61.0 40.8 10.8 10.9 3.7 86.0 71.9 44.5 ---------------------------------------------------------------------------------------------------------------------------------- Total capitalized costs 913.6 823.5 714.0 20.2 12.6 5.1 933.8 836.1 719.1 Accumulated depletion (269.9) (251.3) (225.2) (2.8) (0.3) (0.2) (272.7) (251.6) (225.4) ---------------------------------------------------------------------------------------------------------------------------------- NET CAPITALIZED COSTS 643.7 572.2 488.8 17.4 12.3 4.9 661.1 584.5 493.7 ---------------------------------------------------------------------------------------------------------------------------------- COSTS CAPITALIZED DURING YEAR (b) Acquisition properties Proved 3.1 1.2 -- -- -- 0.7 3.1 1.2 0.7 Unproved 17.8 8.6 0.6 1.2 2.9 3.0 19.0 11.5 3.6 Exploration 34.0 6.7 2.3 6.9 1.3 -- 40.9 8.0 2.3 Development 45.9 99.4 62.1 -- 2.9 1.4 45.9 102.3 63.5 ---------------------------------------------------------------------------------------------------------------------------------- COSTS CAPITALIZED 100.8 115.9 65.0 8.1 7.1 5.1 108.9 123.0 70.1 ----------------------------------------------------------------------------------------------------------------------------------
(a) Represents expenditures associated with properties on which evaluations have not been completed. (b) Includes internal costs capitalized pursuant to the accounting policy described in Note 1(E) of Notes to Consolidated Financial Statements of $3.4 million in 2000, 3.5 million in 1999 and $3.3 million in 1998. 54 55 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
OTHER EXPLORATION AND PRODUCTION DATA United States Canada --------------------------------------------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 ========================================================================================================= Average sales price per Mcf of gas ($)(a) 2.99 2.66 2.91 3.79 2.25 2.61 Average sales price per barrel of oil and other liquids ($) 25.01 14.69 12.53 30.86 19.43 16.42 Production (lifting) cost per dollar of gross revenue ($) 0.18 0.19 0.21 0.36 0.18 0.32 Depletion rate per dollar of gross revenue ($) 0.17 0.26 0.29 3.26 0.24 0.27 ---------------------------------------------------------------------------------------------------------
(a) Includes the effect of hedging activities. HISTORICAL RESULTS OF OPERATIONS
--------------------------------------------------------------------------------------------------------- United States Canada Total --------------------------------------------------------------------------------------------------------- ($ in millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 ========================================================================================================= Gross revenues Unaffiliated 159.6 122.4 53.7 0.8 0.5 0.6 160.4 122.9 54.3 Affiliated 2.0 1.4 62.3 -- -- -- 2.0 1.4 62.3 Production costs 28.4 23.7 24.2 0.3 0.1 0.2 28.7 23.8 24.4 Depletion 29.3 32.8 33.5 2.5 0.1 0.2 31.8 32.9 33.7 Income tax expense 39.8 25.0 20.7 (0.9) 0.1 0.1 38.9 25.1 20.8 --------------------------------------------------------------------------------------------------------- RESULTS OF OPERATIONS 64.1 42.3 37.6 (1.1) 0.2 0.1 63.0 42.5 37.7 ---------------------------------------------------------------------------------------------------------
Results of operations for exploration and production activities exclude administrative and general costs, corporate overhead and interest expense. Income tax expense is expressed at statutory rates less Section 29 credits. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
------------------------------------------------------------------------------------------------------------------------------ United States Canada Total ------------------------------------------------------------------------------------------------------------------------------ ($ in millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 ============================================================================================================================== Future cash inflows 11,475.5 2,805.4 2,094.4 14.5 5.5 3.4 11,490.0 2,810.9 2,097.8 Future production costs (1,608.9) (739.8) (585.5) (2.9) (2.1) (1.5) (1,611.8) (741.9) (587.0) Future development costs (302.7) (258.3) (200.4) (0.2) (0.1) (0.1) (302.9) (258.4) (200.5) Future income tax expense (3,842.3) (697.5) (487.8) (2.2) (0.9) (0.7) (3,844.5) (698.4) (488.5) ------------------------------------------------------------------------------------------------------------------------------ Future net cash flows 5,721.6 1,109.8 820.7 9.2 2.4 1.1 5,730.8 1,112.2 821.8 Less: 10% discount 3,416.0 600.6 440.1 3.9 0.9 0.3 3,419.9 601.5 440.4 ------------------------------------------------------------------------------------------------------------------------------ STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW 2,305.6 509.2 380.6 5.3 1.5 0.8 2,310.9 510.7 381.4 ------------------------------------------------------------------------------------------------------------------------------
Future cash inflows are computed by applying year-end prices to estimated future production of proved gas and oil reserves. Future expenditures (based on year-end costs) represent those costs to be incurred in developing and producing the reserves. Discounted future net cash flows are derived by applying a 10% discount rate, as required by the Financial Accounting Standards Board, to the future net cash flows. This data is not intended to reflect the actual economic value of Columbia's gas and oil producing properties or the true present value of estimated future cash flows since many arbitrary assumptions are used. The data does provide a means of comparison among companies through the use of standardized measurement techniques. 55 56 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) A reconciliation of the components resulting in changes in the standardized measure of discounted cash flows attributable to proved gas and oil reserves for the three years ending December 31, follows:
United States Canada Total ---------------------------------------------------------------------------------------------------------------------------------- ($ in millions) 2000 1999 1998 2000 1999 1998 2000 1999 1998 ================================================================================================================================== Beginning of year 509.2 380.6 460.7 1.5 0.8 -- 510.7 381.4 460.7 ---------------------------------------------------------------------------------------------------------------------------------- Gas and oil sales, net of production costs (133.2) (100.1) (91.9) (0.5) (0.4) (0.4) (133.7) (100.5) (92.3) Net changes in prices and production costs 2,828.2 74.7 (108.5) 4.6 0.6 -- 2,832.8 75.3 (108.5) Change in future development costs (19.0) (35.8) (10.0) (0.2) -- -- (19.2) (35.8) (10.0) Extensions, discoveries and other additions, net of related costs 448.2 107.5 77.5 1.2 0.6 -- 449.4 108.1 77.5 Revisions of previous estimates, net of related costs 314.9 33.7 (18.0) (0.1) 0.1 -- 314.8 33.8 (18.0) Sales of reserves-in-place (5.9) (2.9) (12.0) -- -- -- (5.9) (2.9) (12.0) Purchases of reserves-in- place 16.3 54.6 -- -- -- 1.7 16.3 54.6 1.7 Accretion of discount 82.0 60.0 70.1 0.2 0.1 -- 82.2 60.1 70.1 Net change in income taxes (1,233.5) (91.3) 21.1 (0.7) (0.2) (0.5) (1,234.2) (91.5) 20.6 Timing of production and other changes (501.6) 28.2 (8.4) (0.7) (0.1) -- (502.3) 28.1 (8.4) ---------------------------------------------------------------------------------------------------------------------------------- END OF YEAR 2,305.6 509.2 380.6 5.3 1.5 0.8 2,310.9 510.7 381.4 ----------------------------------------------------------------------------------------------------------------------------------
56 57 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued) Schedule II VALUATION AND QUALIFYING ACCOUNTS Columbia Energy Group and Subsidiaries Year Ended December 31, ($ in millions)
Additions - Charged to ---------------------- Beginning Other Ending Description Balance Income Accounts Deductions Balance =============================================================================================================== Allowance for doubtful accounts(a) 2000 11.3 19.7 28.3 43.5 15.8 1999 13.4 17.4 30.6 50.1 11.3 1998 16.3 18.6 26.8 48.3 13.4 Restructuring Activities(b) 2000 - 66.9 - 5.2 61.7 Environmental 2000 123.6 0.5 - 17.7 106.4 1999 140.9 0.2 - 17.5 123.6 1998 129.1 29.2 - 17.4 140.9 ===============================================================================================================
(a) Other Accounts primarily reflect reclassifications to a regulatory asset of the uncollectible accounts related to the Percent of Income Plan (PIP) of Columbia Gas of Ohio, Inc. and Deductions principally reflect amounts charged off as uncollectible less amounts recovered. (b) Deductions primarily reflect payments of severance and related termination benefits. 57 58 ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There has not been a change of accountants nor any disagreements concerning accounting and financial disclosure within the past two years. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Omitted pursuant to General Instruction I. (2) (c). ITEM 11. EXECUTIVE COMPENSATION Omitted pursuant to General Instruction I. (2) (c). ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Omitted pursuant to General Instruction I. (2) (c). ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Omitted pursuant to General Instruction I. (2) (c). PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K Exhibits Reference is made to pages 61 through 63 for the list of exhibits filed as part of this Annual Report on Form 10-K. Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of Columbia or its subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of Columbia and its subsidiaries on a consolidated basis. Columbia agrees to furnish a copy of any such instrument to the U.S. Securities and Exchange Commission upon request. Financial Statement Schedules All of the financial statements and financial statement schedules filed as a part of this Annual Report on Form 10-K are included in Item 8. Reports on Form 8-K
Financial Item Statements Reported Included Date of Event Date Filed -------- -------- ------------- ---------- 5 No October 2, 2000 October 2, 2000 5 No October 11, 2000 October 12, 2000 5 No October 16, 2000 October 16, 2000 5 No November 1, 2000 November 1, 2000
58 59 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. COLUMBIA ENERGY GROUP -------------------------- (Registrant) Dated: March 28, 2001 By: /s/ Michael W. O'Donnell ------------------------------ Michael W. O'Donnell President and Treasurer (Principal Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. March 28, 2001 /s/ Michael W. O'Donnell March 28, 2001 /s/ Jeffrey W. Grossman ----------------------------- -------------------------- Michael W. O'Donnell Jeffrey W. Grossman President and Treasurer Vice President (Director, Principal Executive Officer (Principal Accounting Officer) and Principal Financial Officer) March 28, 2001 /s/ Stephen P. Adik ----------------------------- Stephen P. Adik Director
59 60 EXHIBIT INDEX Reference is made in the two right-hand columns below to those exhibits which have heretofore been filed with the U.S. Securities and Exchange Commission. Exhibits so referred to are incorporated herein by reference.
Reference --------- File No. Exhibit -------- ------- 3-A - Restated Certificate of Incorporation of The Columbia 1-1098 3-A Gas System, Inc., as amended dated as of November 28, 1995. 3-B - By-Laws of The Columbia Gas System, Inc., as amended dated 1-1098 3-B November 18, 1987. 3-C - Certificate of Ownership and Merger, Merging Columbia 1-1098 3-C Energy Group, Inc. into The Columbia Gas System, Inc. 3-D - Amended and Restated By-Laws of Columbia Energy Group as of February 22, 2000. 4-A - Indenture between The Columbia Gas System, Inc. 33-64555 4-S and Marine Midland Bank, N.A. Trustee, dated as of November 28, 1995. 4-B - First Supplemental Indenture, between The Columbia Gas 33-64555 4-T System, Inc. and Marine Midland Bank, N.A. Trustee, dated as of November 28, 1995. 4-C - Second Supplemental Indenture, between The Columbia Gas 33-64555 4-U System, Inc., and Marine Midland Bank, N.A. Trustee, . dated as of November 28, 1995. 4-D - Third Supplemental Indenture, between The Columbia Gas 33-64555 4-V System, Inc. and Marine Midland Bank, N.A. Trustee, . dated as of November 28, 1995. 4-E - Fourth Supplemental Indenture, between The Columbia Gas 33-64555 4-W System, Inc. and Marine Midland Bank, N.A. Trustee, dated as of November 28, 1995. 4-F - Fifth Supplemental Indenture, between The Columbia Gas 33-64555 4-X System, Inc. and Marine Midland Bank, N.A. Trustee, dated as of November 28, 1995. 4-G - Sixth Supplemental Indenture, between The Columbia Gas 33-64555 4-Y System, Inc. and Marine Midland Bank, N.A. Trustee, dated as of November 28, 1995. 4-H - Seventh Supplemental Indenture, between The Columbia 33-64555 4-Z Gas System, Inc. and Marine Midland Bank, N.A., Trustee, dated as of November 28, 1995. 4-I - Instrument of Resignation, Appointment and Acceptance dated as 1-1098 4-I of March 1, 1999, between Columbia Energy Group and Marine Midland Bank, as Resigning Trustee and The First National Bank of Chicago, as Successor Trustee. 10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P System, Inc., amended October 9, 1991. 10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q System, Inc. dated January 1, 1989. 10-T - Agreement and Bridge Agreement dated 1-1098 10-T December 1, 1993, between Columbia Gas Transmission Corporation and Consol Pennsylvania Coal Company. 10-AE - U.S. Environmental Protection Agency Administrative 1-1098 10-AE Order by Consent for Removal Actions for Columbia Gas Transmission Corporation dated September 22,1994.
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. 60 61 EXHIBIT INDEX (continued)
Reference --------- File No. Exhibit -------- ------- 10-AF - Amended and Restated Indenture of Mortgage and Deed of Trust 1-1098 10-AF by Columbia Gas Transmission Corporation to Wilmington Trust Company, dated as of November 28, 1995. 10-BB(a) - Annual Incentive Compensation Plan of The Columbia Gas 1-1098 10-BB System, Inc., as amended, dated as of November 16, 1988. 10-BC(a) - Employment Agreement between Oliver G. Richard III 1-1098 10-BC and The Columbia Gas System, Inc., dated March 15, 1995. 10-BE(a) - Employment Agreement between Peter M. Schwolsky 1-1098 10-BE and The Columbia Gas System, Inc., dated May 30, 1995. 10-BF(a) - Employment Agreement between Catherine Good Abbott and The Columbia Gas System, Inc., dated January 17, 1996. 10-BG - Third amendment to employment agreement by and between the Columbia Energy Group and Oliver G. Richard III, effective July 21, 2000. 10-BH - Second amendment to employment agreement by and between the Columbia Energy Group and Peter M. Schwolsky, effective July 21, 2000. 10-BI - Second amendment to employment agreement by and between the Columbia Energy Group and Catherine Good Abbott, effective July 21, 2000. 10-BU - Share Sale and Purchase Agreement between The 1-1098 10-BU Columbia Gas System, Inc. and Anderson Exploration Ltd. dated November 25, 1991. 10-BV - Security Agreement dated as of January 15, 1992, 1-1098 10-BV between The Columbia Gas System, Inc. and Anderson Exploration Ltd. and Montreal Trust Company of Canada. 10-BW - Kotaneelee Litigation Indemnity Agreement dated 1-1098 10-BW as of December 31, 1991, among The Columbia Gas System, Inc. and Columbia Gas Development of Canada Ltd. and Anderson Exploration Ltd. 10-BX - Specified Litigation Indemnity Agreement made 1-1098 10-BX as of December 31, 1991, among The Columbia Gas System, Inc. and Columbia Gas Development of Canada Ltd. and Anderson Exploration Ltd. 10-BY(a) - Columbia Gas Restoration Security Trust 1-1098 10-BY Agreement dated June 1, 1991, with Dauphin Deposit Bank and Trust Company. 10-BZ* - Natural Gas Advance Sale Contract dated August 24, 2000, between Columbia Natural Resources, Inc. and Mahania II Limited. 10-CA(a) - The Columbia Gas System, Inc. Retirement Plan 1-1098 10-CA for Outside Directors, as amended, August 21, 1991. 10-CB - Credit Agreement, dated as of November 28, 1995, 1-1098 10-CB among The Columbia Gas System, Inc., certain banks party thereto and Citibank, N.A. 10-CC - First Amendment and Supplement to Credit 1-1098 10-CC Agreement, dated December 6, 1995. 10-CD - Credit Agreement for $450,000,000, dated March 11, 1998, 1-1098 10-CD among Columbia Energy Group and certain banks party thereto and Citibank, N.A. as Administrative and Syndication Agent. 10-CE - Credit Agreement for $900,000,000, dated March 11, 1998, 1-1098 10-CE among Columbia Energy Group and certain banks party thereto and Citibank, N.A. as Administrative and Syndication Agent. 10-CF - Memorandum of Understanding among the Millennium Pipeline 1-1098 10-CF Project partners (Columbia Transmission, West Coast Energy, MCN Investment Corp. and TransCanada Pipelines Limited) dated December 1, 1997. 10-CG - Agreement of Limited Partnership of Millennium Pipeline 1-1098 10-CG Company, L.P. dated May 31, 1998.
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. * Filed herewith. 61 62 EXHIBIT INDEX (continued)
Reference --------- File No. Exhibit -------- ------- 10-CH - Contribution Agreement Between Columbia Gas Transmission 1-1098 10-CH Corporation and Millennium Pipeline Company, L.P. dated July 31, 1998. 10-CI - Regulations of Millennium Pipeline Management Company, L.L.C. 1-1098 10-CI dated May 31, 1998. 10-CJ - Amended and Restated Agreement of Cove Point 1-1098 10-CJ LNG Limited Partnership between Columbia LNG and PEPCO Energy Company, Inc. dated January 27, 1994. 10-CK - Amended and Restated 364-Day Credit Agreement among Columbia 1-1098 10-CK Energy Group and certain banks party thereto and Citibank, N. A. as Administrative and Syndication Agent dated as of March 10, 1999. 1-1098 10-CM 10-CM - Plan of Reorganization for Columbia Gas Transmission Corporation as filed with the United States Bankruptcy Court for the District of Delaware on January 18, 1994. 10-CQ - $50,000,000 Amended and Restated Credit Agreement dated 1-1098 10-CQ October 11, 2000, among Columbia Energy Group and certain banks party thereto and Citibank, N.A. as Administrative and Syndication Agent. 10-CR - $850,000,000 Amended and Restated Credit Agreement dated 1-1098 10-CR October 11, 2000, among Columbia Energy Group and certain banks party thereto and Citibank, N.A. as Administrative and Syndication Agent. 12* - Statements of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends. 23-A* - Written consent, dated March 12, 2001, to the filing and use of information contained in such letter report, in Reports and Registration Statements filed during 2000, of Ryder Scott Company Petroleum Engineers, independent petroleum and natural gas consultants. 23-B* - Written consent, dated January 22, 2001, to the filing and use of information contained in such letter report, in Reports and Registration Statements filed during 2000, of Sproule Associates Limited, independent petroleum and natural gas consultants.
* Filed herewith. 62