ITEM 1. BUSINESS
General The Columbia Gas System, Inc. (the Corporation) 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 18 direct subsidiaries. On July 31, 1991, the Corporation and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions for protection under Chapter 11 of the Federal Bankruptcy Code. Both the Corporation and Columbia Transmission are debtors-in-possession under the Bankruptcy Code and continue to operate their businesses in the normal course subject to the jurisdiction of the United States Bankruptcy Court for the District of Delaware. The Corporation owns all of the securities of its subsidiaries except for approximately 8 percent of the stock in Columbia LNG Corporation. The Corporation's subsidiaries are engaged in natural gas transmission, natural gas distribution, exploration for and production of oil and natural gas, and other energy operations. The Corporation and its subsidiaries are sometimes referred to herein as the System.
Transmission Operations The Corporation's two interstate pipeline transmission companies, Columbia Transmission and Columbia Gulf Transmission Company (Columbia Gulf), operate a 23,300-mile pipeline network that extends from offshore in the Gulf of Mexico to New York State and the eastern seaboard. In addition, Columbia Transmission operates one of the nation's largest underground storage systems.
Historically, Columbia Transmission offered both a wholesale sales service and a transportation service to local distribution companies. However, when a new federally mandated business restructuring of the industry took effect in late 1993, Columbia Transmission expanded its transportation and storage services for local distribution companies and industrial and commercial customers and now provides only a minimal sales service. Columbia Gulf's pipeline system, which extends from offshore Louisiana to West Virginia, carries 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. Columbia Gulf owns interests in the Overthrust, Ozark and Trailblazer pipelines, which extend into major midcontinent and western gas-producing areas. Combined, Columbia Transmission and Columbia Gulf serve customers in 15 northeastern, middle Atlantic, midwestern, and southern states and the District of Columbia.
Distribution Operations The Corporation's five distribution subsidiaries provide natural gas service to more than 1.9 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. These subsidiaries purchase gas supplies to serve their high-priority customers and transport gas for industrial and commercial customers who purchase gas from other sources. More than 29,700 miles of distribution pipelines serve such major markets as Columbus, Lorain, Parma, Springfield, and Toledo in Ohio; Gettysburg, York and a part of Pittsburgh in Pennsylvania; Lynchburg, Staunton, Portsmouth and Richmond suburbs in Virginia; Ashland, Frankfort and Lexington in Kentucky; and Cumberland and Hagerstown in Maryland.
Oil and Gas Operations The Corporation's oil and gas subsidiaries, Columbia Gas Development Corporation and Columbia Natural Resources, Inc., explore for, develop, produce, and market oil and natural gas in the United States. These companies hold interests in more than two million net acres of gas and oil leases and have proved oil and gas reserves in excess of 757 billion cubic feet of gas equivalent.
Operations are focused in the Appalachian, Arkoma, Michigan, Permian, Powder River and Williston basins; both onshore and offshore in the Gulf Coast areas of Texas and Louisiana, and in Utah and California.
ITEM 1. BUSINESS (Continued)
Offshore holdings include interests in federal blocks, most of which are located in the West Cameron, Vermilion, Eugene Island, and Ship Shoal areas of the Gulf of Mexico.
Other Energy Operations The Corporation's TriStar Ventures Corporation participates in natural gas-fueled cogeneration projects that produce both electricity and useful thermal energy.
Columbia Propane Corporation and Commonwealth Propane, Inc., sell propane at wholesale and retail to approximately 68,200 customers in eight states.
Columbia Coal Gasification Corporation owns over 500 million tons of coal reserves in the Appalachian area, much of which contains less than one percent sulfur. Approximately 50 percent of the total reserves are leased to other companies for development.
Columbia LNG Corporation is a participant in a partnership that has received the necessary regulatory approvals and anticipates having a gas peaking service operational by the end of 1995 from the Cove Point LNG facility.
Columbia Energy Services oversees the System's nonregulated natural gas marketing efforts and provides an array of supply and fuel management services to distribution companies, independent power producers and other large end users both on and off the transmission and distribution subsidiaries' pipeline systems.
Columbia Gas System Service Corporation provides centralized, cost-efficient data processing, financial, accounting, legal, and other services for the Corporation and other subsidiaries.
For additional discussion of the System's business segments, including financial information for the last three fiscal years, see Item 7, page 19 through 49 and Note 14 on page 87 of Item 8.
Other Relevant Business Information The System's customer base is broadly diversified, with no single customer accounting for a significant portion of revenues.
The Corporation's operating subsidiaries are subject to competitive pressures from other pipeline systems and producers that sell and/or transport natural gas as well as from competition from alternative fuels, primarily oil and electricity. The transmission subsidiaries compete in the highly competitive northeast and midwest energy markets. The distribution subsidiaries compete with alternative fuels and to a limited extent with other gas companies. The oil and gas subsidiaries compete in the marketplace for sales of their oil and gas production through a combination of long-term contracts and spot sales.
Certain subsidiaries file reports with various federal agencies containing estimates of company-owned oil and gas reserves. These estimates are generally consistent, but not always comparable, to those reported in the 1994 Annual Report to Shareholders.
At January 31, 1995, the System had 9,935 full-time employees of which 2,086 are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages 32 through 33, page 40 and page 48 and in Item 8, Note 11G on pages 83 through 85.
For a listing of the subsidiaries of the Corporation and their lines of business refer to Exhibit 21.
Public Utility Holding Company Act of 1935 The Corporation and its subsidiaries are subject, in certain matters, to the jurisdiction of the Securities and Exchange Commission (SEC) under the 1935 Act. In 1944, the SEC held that the major portions of the System complied with
ITEM 1. BUSINESS (Continued)
the requirements of Section 11 of the 1935 Act relating to a "single integrated public-utility system" and businesses reasonably incidental thereto, but the SEC reserved jurisdiction over the retainability of certain subsidiaries. Included were two companies owning pipelines in West Virginia and Northern Virginia extending into Maryland and New York (the reserved pipelines are now part of Columbia Transmission) and Virginia Gas Distribution Corporation (now a part of Commonwealth Gas Services, Inc.). Since that time, the reservation of jurisdiction has been expanded to include the subsequently acquired properties of Blue Ridge Gas Company (a Virginia retail company which is now part of Commonwealth Gas Services, Inc.), Commonwealth Gas Pipeline Corporation (now a part of Columbia Transmission) and a retail subsidiary (Commonwealth Gas Services, Inc.) acquired as a result of the merger of the Corporation with Commonwealth Natural Resources, Inc. and Lynchburg Gas Company, (now a part of Commonwealth Gas Services, Inc.).
The Corporation filed a motion with the SEC in June 1955 requesting the termination of such reserved jurisdiction. After hearings, no further action has been taken and the Corporation is unable to predict whether or when the SEC will finally dispose of the Corporation's 1955 motion and resolve the retainability issue.
The Gas Related Activities Act (GRAA), enacted in 1990, provides that gas transmission is deemed to be reasonably incidental or economically necessary or appropriate to the operation of the gas utility system under Section 11 of the 1935 Act. Since the basis for questioning the retainability of the gas transmission pipelines was compliance with this Section 11 criteria, the passage of the GRAA supports, and should resolve, the retainability of the gas transmission pipelines.
If however, any of these properties were ultimately to be held not retainable, management believes that the SEC would permit the Corporation to adopt a plan for orderly disposition which would permit full realization of their intrinsic values.
ITEM 2.
ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed on pages 6 through 7 herein and pages 90 through 93 of Item 8 under Note 16. The System also owns coal interests in the Appalachian area. Assets under lien and other guarantees are described on page 82 in Note 11D of Item 8.
Neither the Corporation nor any subsidiary knows of material defects in the title to any real properties of the subsidiaries of the Corporation or of any material adverse claim of any right, title, or interest therein, pending or contemplated except the Official Committee of Unsecured Creditors of Columbia Transmission has filed a complaint which challenges the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. as an alleged fraudulent transfer. Substantially all of Columbia Transmission's property has been pledged to the Corporation as security for First Mortgage Bonds issued by Columbia Transmission to the Corporation which has also been challenged by the Official Committee of Unsecured Creditors of Columbia Transmission.
ITEM 2. PROPERTIES (Continued)
OIL AND GAS DATA
Acreage - At December 31, 1994
Net Wells Completed - 12 Months Ended December 31
Productive and Drilling Wells - At December 31, 1994
(a) Includes 17 net horizontal wells in 1994, 17 net horizontal wells in 1993 and 13 net horizontal wells in 1992.
(b) Includes 807 multiple completion gas wells and 16 multiple completion oil wells, all of which are included as single wells in the table. Also includes 42 gross productive horizontal wells.
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1994
NOTE: This table excludes minor gas properties and all construction work in progress. The titles to the real properties of the subsidiaries of the Corporation have not been examined for the purpose of this document. Neither the Corporation nor any subsidiary knows of material defects in the title to any of the real properties of the subsidiaries of the Corporation or of any material adverse claim of any right, title, or interest therein, pending or contemplated except the Official Committee of Unsecured Creditors of Columbia Transmission has filed a complaint which challenges the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. as an alleged fraudulent transfer. Substantially all of Columbia Transmission's property has been pledged to the Corporation as security for First Mortgage Bonds issued by Columbia Transmission to the Corporation which has also been challenged by the Official Committee of Unsecured Creditors of Columbia Transmission
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
I. Shareholder Class Actions and Derivative Suits (Unless otherwise noted, all matters are stayed pursuant to Section 362 of the Bankruptcy Code)
After the June 19, 1991 announcement of the Corporation's proposed charge to second quarter earnings and suspension of its dividend, seventeen complaints including suits purporting to be class actions, or alleging claims common to the purported class actions, were filed in the U.S. District Court for the District of Delaware. These actions have been consolidated under the style In re Columbia Gas Securities Litigation, Consol. C.A. No. 91-357. The complaints named as defendants, the Corporation, members of the Corporation's Board of Directors as of June 1991, certain officers, the Corporation's independent public accountants, and the Corporation's underwriters for its 1990 common stock offering (the Defendants).
The complaints alleged violations of Sections 11, 12(2) and 15 of the Securities Act of 1933, Sections 10(b), 20(a) and Rule 10b-5 of the Securities Exchange Act of 1934, negligent misrepresentations, and common law fraud and deceit. They generally asserted that the Defendants publicly made material misleading statements during the relevant class periods (from February 28, 1990 to June 19, 1991) concerning the Corporation's financial condition, and failed to disclose material facts which rendered other statements misleading, thereby artificially inflating the market price of the Corporation's common stock and publicly traded debt securities, causing the various plaintiffs and other class members to purchase such publicly-traded securities at artificially inflated prices.
On October 31, 1994, the class action plaintiffs filed an amended and consolidated complaint against the non-debtor defendants in the District Court alleging the same causes of action as the previously filed complaints. On October 31, 1994, plaintiffs filed motions with both the District Court and the Bankruptcy Court for certification of classes and for withdrawal of reference to the U. S. District Court of the actions against individual defendants.
On November 1, 1994, the Corporation filed a motion in the U.S. Bankruptcy Court for the District of Delaware seeking to require individual class action plaintiffs to file information to supplement the class proofs of claim filed in this litigation. If this procedure is approved, those plaintiffs failing to respond will be barred from asserting their claims. The motions filed by plaintiffs on October 31, 1994 and by the Corporation on November 1, 1994 have been stayed by order of the U. S. District Court until further order of the Court. On February 13, 1995, the Corporation, in order to promptly address the securities claims in its plan of reorganization, requested the District Court to modify the stay order to allow the District Court to consider the Corporation's motion to supplement class proofs of claims. It also advised the District Court that it was prepared to consent to a withdrawal of the reference requested by the plaintiffs. The plaintiffs have objected to a modification of the stay order which would limit the District Court's hearing to the proofs of claim motion.
Also in 1991, three derivative actions were filed in the Court of Chancery in and for New Castle County (Delaware) alleging that the Corporation's directors breached their fiduciary duties at that time. These suits have been stayed by either the Bankruptcy Court filing or by stipulation of the parties.
While the Corporation and its officers and directors believe that they have meritorious defenses to these actions, the outcome is uncertain at this time.
II. Bankruptcy Matters
A. Matters in the United States Bankruptcy Court for the District of Delaware
1. Motion to Fix Procedures to Establish Columbia Transmission's Liability to Third Party Beneficiary Investor Complaints. On February 17, 1993, movants, who are investors in production companies and claim to be third party beneficiaries of the contracts between Columbia Transmission and the production companies, filed a motion seeking to have their status as third party beneficiaries recognized and seeking to have their claims against Columbia Transmission liquidated separate from the Estimation Procedure established to deal with producer claims. By order dated April 5, 1993, the Bankruptcy Court lifted the stay in order to allow the New Jersey State Court
ITEM 3. LEGAL PROCEEDINGS (Continued)
to determine whether plaintiffs enjoyed third party beneficiary status in the pending State Court action. However, the Bankruptcy Court held that movants' claim would be subject to the estimation procedure. Oral argument was held September 16, 1994. On November 9, 1994, the New Jersey State Court denied cross-motions for summary judgment on the question of third party beneficiary liability. On February 7, 1995, an order was entered finding that the plaintiffs were not entitled to third party beneficiary status and dismissing all claims with prejudice.
2. First National Bank of Boston, Trustee v. The Columbia Gas System, Inc. On March 2, 1993, the Trustee for the Indenture under which debentures were issued by the Employees' Thrift Plan of Columbia Gas System (Plan) filed a complaint against the Corporation alleging tortious interference with contract and breach of duty. The Indenture Trustee alleges that the Corporation is not acting in accordance with the Plan when it directs the Plan Trustee to use sums paid by participating employers to match employee contributions and not to pay debt service on the outstanding debentures. The Corporation's answer to the complaint alleging tortious interference with contract for failure to pay installments due holders of debentures issued by the Leveraged Employee Stock Ownership Plan Trust was filed on April 2, 1993. The Indenture Trustee filed an amended adversary complaint on June 30, 1993.
On May 14, 1993, the Corporation filed a motion for summary judgment challenging the Indenture Trustee's standing to bring the action. This motion was denied by the Bankruptcy Court on March 24, 1994. Columbia filed a motion for leave to appeal and a notice of appeal on April 22, 1994. On May 4, 1994, the Indenture Trustee filed a motion for preliminary injunction which was denied. The right to appeal was granted and oral argument before the U.S. District Court for the District of Delaware was held on October 27, 1994.
B. Appeals to or actions in the United States District Court for the District of Delaware
1. Columbia Gas System v. First National Bank of Boston, C.A. No. 94-230. See Item II.A.2 above.
2. Columbia Gas Transmission Corporation v. The Columbia Gas System, Inc. and Columbia Natural Resources, Inc., C.A. No. 92-453. The Official Committee of Unsecured Creditors of Columbia Transmission filed a complaint (the Intercompany Complaint) challenging among other things the status of approximately $1.7 billion of debt owed by Columbia Transmission to the Corporation and the transfer of natural resource properties representing 450 billion cubic feet of natural gas reserves and one million barrels of oil reserves to Columbia Natural Resources, Inc. (Columbia Natural Resources) as well as other intercompany transactions. Trial began September 12, 1994 and concluded on October 25, 1994. Post trial briefing concluded on December 20, 1994 and a decision is expected in the first quarter of 1995.
C. Appeals to the United States Court of Appeals for the Third Circuit
1. Enterprise Energy Corporation, et al., v. United States of America, on behalf of its Internal Revenue Service, No. 93-7409. On June 18, 1991, the U.S. District Court for the Southern District of Ohio approved a settlement of this class action suit by Appalachian oil and gas producers. The settlement required Columbia Transmission to make two $15 million payments into escrow, for distribution to class members as formal contract amendments were finalized. The first $15 million was paid into escrow in March 1991.
Columbia Transmission filed an application with the Bankruptcy Court which would permit it to honor the settlement (including authority to make the second $15 million payment into escrow in March 1992) but to reject the amended contracts. On December 12, 1991, the Bankruptcy Court ruled that distribution from escrow of the first $15 million payment could be effected pursuant to the settlement; however, the Bankruptcy Court denied Columbia Transmission's request for approval to make the second $15 million payment scheduled to be made in March 1992. Further, the Bankruptcy Court granted the motion to reject the contracts, as amended, pursuant to the Enterprise settlement.
On October 6, 1992, the District Court affirmed the Bankruptcy Court's order denying Columbia Transmission's motion to assume the executory settlement contract. Enterprise Energy Corp.'s request for
ITEM 3. LEGAL PROCEEDINGS (Continued)
rehearing, reargument and reconsideration of the order denying Columbia Transmission's motion to assume the executory settlement contract was denied on April 27, 1993. On May 25, 1993, Enterprise Energy filed a notice of appeal to the United States Court of Appeals for the Third Circuit from the Bankruptcy Court order denying Columbia Transmission's motion to require assumption or rejection of the executory settlement contract. Briefing is complete. Oral argument was held January 18, 1994. A report regarding the status of the Bankruptcy proceedings was filed December 1, 1994.
2. In re The Columbia Gas System, Inc. et al.; West Virginia Tax and Revenue v. U.S., Nos. 93-7531 and 93-7532. This is the appeal of the District Court's Memorandum Opinion and Order affirming the Bankruptcy Court's ruling that the property taxes centrally assessed by West Virginia as public service business taxes for the "1992 tax year" were incurred by Columbia Transmission prepetition and denying Columbia Transmission's motion for authorization to pay the taxes. Briefing has been completed and oral argument was heard on March 2, 1994, before the U.S. Court of Appeals for the Third Circuit. An order affirming the District Court's order was issued on October 5, 1994. West Virginia Tax and Revenue filed a petition for rehearing in banc on October 18, 1994. On October 28, 1994 rehearing was denied. The West Virginia State Department of Taxation filed a Writ of Certiorari with the United States Supreme Court on January 25, 1995.
3. The Columbia Gas System, Inc. and Columbia Gas Transmission v. U.S. Trustee, No. 93-7609. On August 30, 1993, the Corporation and Columbia Transmission filed an Appeal of the District Court's order adopting the Magistrate's Report and Recommendation and granting the U.S. Trustee's appeal of the Bankruptcy Court's July 31, 1993 order approving certain investment guidelines and the Bankruptcy Court's order denying the U.S. Trustee's Motion for Reconsideration of the Bankruptcy Court's July 31, 1993 order. On August 29, 1994, the U.S. Court of Appeals for the Third Circuit affirmed in part, and remanded for further proceedings. The Third Circuit's decision limits investments of cash by the debtors to securities issued or backed by the U.S. Government in strict compliance with Section 345(b) of the U.S. Bankruptcy Code.
III. Purchase and Production Matters (Unless otherwise noted, all matters are stayed pursuant to Section 362 of the Bankruptcy Code)
A. Appalachian Producer Litigation
1. Enterprise Energy Corp. et al. v. Columbia Gas Transmission Corp., C. A. No. C2-85-1209, (U. S. Dist. Ct., S. D. Ohio, filed July 26, 1985). See II.C.1. below
2. Phillips Production Co. v. Columbia Gas Transmission Corp., C.A. No. 89-0269, (U.S. Dist. Ct., W.D. Pa. filed February 7, 1989). The complaint as filed contained six separate counts involving ten gas purchase contracts with Columbia Transmission. All claims except those relating to Columbia Transmission's invocation of the cost recovery clause were settled and dismissed December 18, 1989, pursuant to agreement of the parties. Phillips cost recovery claim was stayed by Columbia Transmission's bankruptcy filing.
3. Columbia Gas Transmission Corp. v. Alamco, Inc. et al., C.A. No. 88-C-38-2 (Harrison (W.Va) Cir. Ct. filed January 15, 1988). Under a 1983 release agreement, Columbia Transmission filed suit against Alamco, Inc. (Alamco) contending that Alamco was obligated to sell gas to Columbia Transmission at prices and under terms and conditions being generally offered by Columbia Transmission at the time purchases were resumed as opposed to the conditions of the original contract. Trial of the state court action was interrupted and stayed by Columbia Transmission's Bankruptcy petition filed July 31, 1991. A parallel suit was filed by Alamco, naming the Corporation, Columbia Transmission, Columbia Gas System Service Corporation and Commonwealth Gas Pipeline Corporation, alleging antitrust violations. In the opinion of counsel, the antitrust claim was barred by the statute of limitations; however on March 13, 1991, Columbia Transmission's and Commonwealth Gas Pipeline's motions to dismiss were denied without prejudice to Columbia Transmission's right to assert, by summary judgment or otherwise, that Alamco's claims are time barred, or that Alamco cannot prove the allegations in its complaint.
ITEM 3. LEGAL PROCEEDINGS (Continued)
In late May 1992, a settlement agreement in principle was reached which was approved by the Bankruptcy Court on July 28, 1992. As a result, after the order becomes final, these actions will be dismissed upon the earlier of confirmation of a Columbia Transmission plan of reorganization or closing of the Columbia Transmission bankruptcy proceeding.
B. Southwest Producer Litigation (Suits naming Columbia Transmission are stayed as to Columbia Transmission; indemnification agreements will be effective if the contract providing indemnification is not rejected)
1. Royalty Owners Litigation: The agreements between Columbia Transmission and certain southwest producers effective in 1985 which reformed gas purchase contracts have resulted in a number of lawsuits against the producers. Under the agreements, Columbia Transmission has a qualified obligation to indemnify the producers in certain instances against claims by their royalty owners.
Certain suits were pending against Amoco Production Company (Amoco) for which it was seeking indemnification from Columbia Transmission as of the commencement of Columbia Transmission's proceeding in bankruptcy. In November 1993, Columbia Transmission and Amoco entered an agreement, terminating the contracts and providing that Amoco shall have an allowed unsecured claim for $4.1 million for all royalty indemnification and excess royalty claims. On November 7, 1994, the Bankruptcy court approved the Amoco agreement.
2. New Ulm and Fox v. Mobil Oil Corporation, Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia Transmission incorrectly paid for gas on the basis of Columbia Transmission's market-out price rather than the higher price New Ulm claimed was available to it under the contracts.
After the Bankruptcy Court entered an order modifying the automatic stay provisions of the Bankruptcy Code, jury trial began on June 22, 1992, and concluded with a verdict against Columbia Transmission on July 2, 1992, in the amount of approximately $5.6 million, including interest. On July 30, 1992, the Court denied Columbia Transmission's motion for judgment notwithstanding the jury's verdict and entered judgment against Columbia Transmission in such amount for actual damages, prejudgment interest and attorneys' fees. Columbia Transmission's motion for new trial was denied on October 12, 1992. Columbia Transmission has perfected an appeal to the First Court of Appeals at Houston, Texas. Briefing is complete and oral argument was held on December 7, 1993. On July 28, 1994, the Court of Appeals reversed the lower court's judgment and remanded the matter to the trial court for proceedings not inconsistent with the Court of Appeals opinion. Motion for rehearing by Columbia Transmission and New Ulm motions were denied in October, 1994. On December 5, 1994, both parties filed applications for writ of error with the Supreme Court of Texas.
3. Wagner & Brown v. Columbia Gas Transmission Corp., C.A. No. 83-15091 (Orleans Parish (La.) Civ. Dist. Ct.). This suit involves Columbia Transmission's alleged breach of a gas purchase and sales agreement. The claims of Wagner & Brown have been settled, and the case was dismissed as to Wagner & Brown on March 6, 1986. The claims of El Paso Exploration Co. (now Meridian Oil Production, Inc. (Meridian)), which intervened as a plaintiff and asserted all the claims and allegations made by Wagner & Brown, including take-or-pay, price differential and specific performance, have not been settled. In September 1990, Meridian served a Second Amended Petition in which it alleged damages in excess of $60 million (and an additional $40 million of interest) as a result of Columbia Transmission's failure to meet its take-or-pay and minimum take obligations. The issue of price differential has been settled. A status conference was held May 28, 1991, and a hearing on the plaintiff's motion for partial summary judgment on Columbia Transmission's legal defenses was held June 14, 1991.
A motion by Meridian for a Bankruptcy Court order lifting the automatic stay so as to permit it to prosecute its claims against Columbia Transmission was denied.
4. Koch Industries Inc. v. Columbia Gas Transmission Corp. C.A. No. 89-2156 (U.S. Dist. Ct., E.D. La., filed May 12, 1989). On January 11, 1991, Columbia Transmission filed an action, Columbia Gas
ITEM 3. LEGAL PROCEEDINGS (Continued)
Transmission Corp. v. Koch Industries, Inc., C.A. No. 91-0174, (U.S. Dist. Ct., E.D. La). This lawsuit was related to the settlement of an earlier lawsuit between the parties. Columbia Transmission sought an order declaring that it is under no obligation to increase its purchase nominations under the contracts because of Koch Industries, Inc. (Koch) unasserted right to correct imbalances between it and other working interests owners in the acreage dedicated under the contract. Koch filed a complaint seeking a contrary determination. Koch Industries, Inc. v. Columbia Gas Transmission Corp., C.A. No. 91-0177 (U.S. Dist. Ct. E.D. La). The two cases were consolidated. Judgment in favor of Koch Industries, Inc. and against Columbia Transmission was issued on April 29, 1991. Columbia Transmission's motion to alter or amend the judgment was denied on June 5, 1991. On June 19, 1991, Columbia Transmission filed a Notice of Appeal to the Fifth Circuit. On August 20, 1991, the Clerk of the Court advised Columbia Transmission that the case was stayed during the Chapter 11 Bankruptcy proceedings.
5. Energy Development Corp. v. Columbia Gas Transmission Corp., C.A. No. CV91-0960, (U.S. Dist. Ct., W. D., La., division Lafayette/Opelousas, filed May 13, 1991). Energy Development Corporation alleges that Columbia Transmission breached the take-or-pay, minimum daily quantity and inequitable withdrawal provisions of the gas purchase contract between Energy Development Corporation and Columbia Transmission.
IV. Regulatory Matters
A. Take-or-Pay and Contract Reformation Costs Billed by Pipeline Suppliers
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-41, reversed and remanded Baltimore Gas & Electric Co. v. FERC, 26 F.3d 1129 (D.C. Cir 1994). On June 24, 1994, the Court of Appeals reversed the Federal Energy Regulatory Commission's (FERC) finding that the 1985 PGA Settlement did not bar Columbia Transmission's recovery of any of the upstream pipeline Order Nos. 500/528 costs. The case was remanded to the FERC for a determination of whether any of such charges relate to Columbia Transmission's purchasing decisions prior to April 1, 1987. On September 16, 1994, Columbia Transmission filed with the FERC a motion for an order governing proceedings on remand.
On October 11, 1994, the Joint Intervenors filed a response to the September 16, 1994 motion and moved for entry of an order requiring immediate refund of all the disputed amounts and for summary disposition of the issues remanded by the Court of Appeals. On October 26, 1994, Columbia Transmission filed its response to the Joint Intervenors.
On December 1, 1994, the FERC denied the Joint Intervenors' motion for summary disposition and immediate refunds. The FERC established procedures for Columbia Transmission to make a prima facie factual submission within 60 days of the order identifying amounts it is entitled to recover.
On December 23, 1994, Columbia Transmission filed a motion requesting a 45-day extension of the procedural dates for the prima facie submission and responses. By notice issued January 11, 1995, the FERC extended Columbia Transmission's submission deadline to March 16, 1995.
On January 26, 1995, FERC denied rehearing of its December 1, 1994, order.
On February 16, 1995, Columbia Transmission filed a motion for an additional 60-day extension of the procedural dates.
B. Direct Billing of Past Period Production and Production-Related Costs
1. Columbia Gas Transmission Corp. v. FERC., C.A. No. 88-1701 (U.S. Ct. of App., D.C. Circuit). On February 9, 1990, the Court issued its opinion finding that the FERC's orders authorizing five of Columbia Transmission's upstream pipeline suppliers to directly bill past period production related costs (Order Nos. 94 and 473) to customers allocated based upon past period purchases violates the filed rate doctrine and the rule against
ITEM 3. LEGAL PROCEEDINGS (Continued)
retroactive ratemaking. Therefore, the Court struck the orders authorizing direct billing and remanded the issue to the FERC for further proceedings. On October 9, 1990, the U.S. Supreme Court denied certiorari.
Columbia Transmission agreed to settlements with four of its pipeline suppliers, which were initially approved by FERC orders issued February 11, 1993. However, by orders issued January 12, 1994, the FERC granted requests for rehearing by Columbia Transmission's customers and rejected the settlements because they provided for rate recovery of the settlement payments to its pipeline suppliers. The FERC held that such rate recovery was barred by Columbia Transmission's 1985 PGA Settlement. The same orders directed the pipeline suppliers to refund all principal Order Nos. 94/473 direct billed amounts collected from Columbia Transmission, but provided that no interest would be required on such refunds.
Columbia Transmission and its four pipeline suppliers filed requests for rehearing of such orders. On October 18, 1994, the FERC for the most part denied rehearing, although it did require interest on refunds from February 11, 1994. Columbia Transmission and its pipeline suppliers filed petitions for review of the FERC's orders with the United States Court of Appeals for the District of Columbia Circuit.
Agreements have been reached with Panhandle Eastern Pipe Line Company (Panhandle), Trunkline Gas Company (Trunkline), Texas Eastern Pipe Line Corporation and Texas Gas Transmission Corp. to postpone refunds to Columbia Transmission until after the appeals are resolved. In the interim, refunds would accrue interest at FERC rates. The pipeline suppliers or Columbia Transmission may move for accelerated payment of refunds. Columbia Transmission is not repaying Panhandle the amounts they have already refunded.
In the interim, on October 28, 1993, Transcontinental Gas Pipe Line Corporation (Transco) and Columbia Transmission filed a letter with the FERC indicating that the remaining issues had been resolved, and that they agreed on a refund to Columbia Transmission of $1.4 million. The FERC treated this as a settlement offer subject to its approval.
By order issued on February 13, 1995, the FERC rejected Transco's offer of settlement on Order No. 94 costs with Columbia Transmission. Transco was ordered to refund the Order 94 costs collected from Columbia Transmission, without interest. This result is the same the FERC reached with respect to Panhandle and Trunkline. The order has not yet been issued.
On February 7, 1995, Columbia Transmission filed a motion for clarification with the FERC regarding whether the pipelines must also refund carrying charges paid by Columbia Transmission.
C. Pipeline Exit Fees
1. Columbia Gas Transmission Corporation, et al., Docket No. RP94-113. On June 30, 1994, FERC approved an agreement between Columbia Transmission and Tennessee Gas Pipeline Company (Tennessee) which provided for a reduction and early termination of contracts in consideration for Columbia Transmission's payment of an exit fee of approximately $40 million. FERC rejected objections of several customers and permitted Columbia Transmission full recovery of the exit fee from its customers. The Bankruptcy Court had approved this settlement on November 15, 1993.
On September 28, 1994, FERC denied requests for rehearing of its June 30 order. Several parties have filed petitions for review of these orders with the United States Court of Appeals for the District of Columbia Circuit.
2. Columbia Gas Transmission Corporation, Docket Nos. RP94-315, 316, 317 and 318. In these dockets, Columbia Transmission filed petitions to approve exit fee settlements terminating contracts with certain pipelines that are no longer needed by Columbia Transmission and to resolve outstanding bankruptcy issues by, inter alia, the payment by Columbia Transmission of exit fees to Wyoming Interstate Company Ltd. (WIC), Trailblazer Pipeline Company (Trailblazer), Natural Gas Pipeline Co. of America (NGPL) and Transcontinental Gas Pipe Line
ITEM 3. LEGAL PROCEEDINGS (Continued)
Corporation (Transco), and to collect such exit fee payments through its Account No. 858 cost tracker. All four settlements have been approved by the Bankruptcy Court. On January 27, 1995, the FERC issued an order approving the exit fee settlement between Columbia Transmission and Transco. On February 10, 1995, the FERC approved the separate exit fee settlements between WIC, Trailblazer and NGPL to terminate the contracts with those pipelines. Both orders permit recovery of the exit fees.
3. Columbia Gas Transmission Corporation, Docket No. RP95-98. On December 30, 1994, Columbia Transmission filed its exit fee settlement with Ozark Gas Pipeline. Comments were filed on January 30, 1995, opposing the settlement and reply comments were filed on February 9, 1995. The settlement is pending before the FERC.
V. Other
A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of Canada Ltd. et al., (C.A. No. 9001-03466, Court of Queen's Bench, Alberta, Canada, filed March 7, 1990). The plaintiff asserts, 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 plaintiff seeks, among other remedies, the return of the defendants' interests in the Kotaneelee field to the plaintiff, a declaration that such interests are held in trust for the plaintiff, and an order requiring the defendants to promptly market Kotaneelee gas or assessing damages.
The judge granted the application of Allied Signal, Inc., Home Oil Company and Kern County Land Company to relieve them of the requirement to participate in the proceedings. An appeal of the order by Amoco is pending.
In early 1993, Canada Southern filed a motion to amend its statement of claim to seek an accounting of the amount of operation costs properly recoverable by the working interest holders including Columbia Canada. Columbia has not consented to the amendment and contends that any amounts accrued since the initial statement of claim in 1988 should be barred and more basically, that litigation is inappropriate prior to an audit.
Examination for discovery is still proceeding in the referenced actions. None of the defendants has yet conducted any discovery of Canada Southern Petroleum, Ltd. (Canada Southern) nor of one another. On the present schedule, it is likely that this discovery process will continue well into 1995. A six month trial is scheduled to commence in September 1996 by the Court of Queens Bench.
Note: Columbia Canada was sold to Anderson Exploration Ltd. effective December 31, 1991, and the company name subsequently changed to Anderson Oil & Gas, Inc. Pursuant to an Indemnification Agreement re Kotaneelee Litigation, Columbia agreed to indemnify and hold Anderson harmless from losses due to this litigation. An escrow account in the amount of approximately $30,000,000 (Cdn) was established as partial security for the indemnification obligation. Upon emerging from bankruptcy, an additional deposit to the Escrow Account of $25,000,000 (Cdn) will be required in cash or by letter of credit.
VI. Environmental
A. Commonwealth of Kentucky Natural Resources and Environmental Protection Cabinet, Department for Environmental Protection. On January 22, 1992, Columbia Transmission received Notices of Violation (NOV) from the Commonwealth of Kentucky, Natural Resources and Environmental Protection Cabinet, Department for Environmental Protection (KYDEP), apparently to establish the Cabinet's prepetition claims against Columbia Transmission, with respect to ten compressor station sites in the Commonwealth of Kentucky. These notices generally cite the release or disposal of waste materials or hazardous substances, including but not limited to polychlorinated biphenyls (PCBs).
ITEM 3. LEGAL PROCEEDINGS (Continued)
On October 24, 1994, Columbia Transmission entered into two agreed orders with KYDEP. Under one order, Columbia Transmission agreed to pay a civil penalty of $50,000 to resolve all outstanding NOVs issued by KYDEP. Under a second order, Columbia Transmission agreed to continue the ongoing remediation program which Columbia Transmission began in Kentucky in the late 1980. Both orders were approved by the Bankruptcy Court on November 16, 1994 and are now effective.
B. In the Matter of Columbia Gas Transmission Corp., [United States Environmental Protection Agency Region III (EPA Region III)]. On January 20, 1992, Columbia Transmission received a Subpoena under the Toxic Substance Control Act (TSCA) and Information Requests under both the Comprehensive Environmental Response Compensation and Liability Act of 1980 (CERCLA) and the Resource Conservation and Recovery Act (RCRA). The Subpoena and Information Requests sought information relating to Columbia Transmission's compliance with TSCA, CERCLA and RCRA at and around the facilities it owns, operates, leases or otherwise used in its pipeline business.
On September 22, 1994, Columbia Transmission entered into Consent Orders with the EPA Region III resolving the issues covered by the Subpoena and Information Requests. Under the Administrative Order by Consent under Section 106 of CERCLA, Columbia Transmission agreed to continue its ongoing remediation program with the EPA Region III oversight. Under the TSCA Order, Columbia Transmission agreed to pay a civil penalty of approximately $4.9 million to resolve EPA Region III allegations of violations regarding the use and disposal of PCBs. Although Columbia Transmission believes it had meritorious defenses to EPA Region III's allegations, Columbia Transmission determined that the cost was reasonable when compared to the litigation costs involved in contesting EPA's factual claims. Bankruptcy Court approval of the Consent Orders was obtained on November 16, 1994, and no appeals were filed within the appeal period. The Order became effective on February 23, 1995.
C. Portsmouth Redevelopment and Housing Authority and Commonwealth Gas Services, Inc. (Commonwealth) v. BMI Apartment Associates, C.A. No. 2:93CV242, (U.S. Dist. Ct. E.D. Va., filed March 25, 1993.) A gas manufacturing plant had been operated in Portsmouth, Virginia by Portsmouth Gas Co. on a site that was subsequently sold by Portsmouth Gas Co. to the Portsmouth Redevelopment and Housing Authority (PRHA), which removed equipment and sold the property to developers of apartment complexes and single-family homes. Portsmouth Gas Co. was later acquired by Commonwealth. On July 22, 1994, a settlement among Commonwealth, the PRHA and the present and former landowners of the site resolving all previously filed litigation was approved by the District Court. The settlement allows Commonwealth and PRHA to perform remedial work at the site. Commonwealth and PRHA have an agreement whereby costs are shared. In addition, Commonwealth has met with the owners of an adjacent property, Gates Apartments, to obtain access to that property for environmental assessment and remediation purposes. Commonwealth is working with the Virginia Department of Environmental Quality (VADEQ) to develop remedial plans for the site.
D. Commonwealth Gas Services/Virginia Department of Environmental Quality (Petersburg, VA. Service Center). On February 9, 1993, Commonwealth reported to the VADEQ State Water Control Board that an oily substance was seeping through a retaining wall at a former manufactured gas plant site at Petersburg, Virginia. A site assessment submitted to the VADEQ on July 20, 1993 recommended the removal of contents of a tank behind the retaining wall and disclosed an additional seep of materials from another source into the creek. In July 1993, VADEQ accepted Commonwealth's recommendations and the tank was subsequently emptied and secured. A supplemental report identifying the source of the additional seep was sent to VADEQ in November which noted fairly widespread groundwater and soil contamination. Commonwealth's consultants are developing a work plan to address the contamination noted in the supplemental report and are in the process of negotiating a Memorandum of Agreement delineating the voluntary remediation of the site to be undertaken. Once that agreement is completed and approved by the VADEQ remediation can begin.
E. In re Columbia Gas Transmission [United States Environmental Protection Agency Region V] (EPA Region V). On January 28, 1994, Columbia Transmission received from the EPA Region V an Information Request pursuant to the RCRA. It has requested that Columbia Transmission submit information and knowledge
ITEM 3. LEGAL PROCEEDINGS (Continued)
relating to its generation and management of natural gas pipeline condensate, used engine oil and similar liquids in the state of Ohio since the early 1980's. Columbia Transmission submitted a written response to the request to the EPA Region V on May 24, 1994.
F. Columbia Gas Transmission Corp. v. Aetna Casualty & Surety Co., et al., C.A. No. 94-C-454 (Kanawha (W.Va) Cir. Ct. filed March 14, 1994). Columbia Transmission filed a complaint in West Virginia State Court seeking coverage from various insurers and under various insurance policies for environmental cleanup costs. All insurers have either executed a standstill agreement or responded to the complaint. Columbia Transmission is preparing responses to discovery requests to be submitted to insurers in February 1995.
G. Columbia Gulf Transmission Company v. Aetna Casualty & Surety Co., et al., C.A. No. 95-C-177 (Kanawha (W.Va) Cir. Ct. filed January 19, 1995). On January 19, 1995, Columbia Gulf Transmission filed a complaint in West Virginia State Court seeking coverage from various insurers and under various insurance policies for environmental remediation costs and related costs.
H. In re Marcor Environmental, Inc. v. Columbia Gas Transmission Corporation. On September 30, 1994, EPA Region III issued a complaint and notice of opportunity for hearing against Marcor Environmental, Inc. (Marcor) and Columbia Transmission for alleged violations of the Clean Air Act Amendments of 1990 arising from Macor's removal of asbestos at Lanham Compressor Station at Lanham, West Virginia in 1993. The complaint which seeks a penalty of $162,500 alleges failure by Marcor and Columbia Transmission, as owner of the facility, to adequately wet the asbestos material and to ensure it remained wet pending disposal. On November 4, 1994, Columbia Transmission filed an answer and a motion to dismiss. A settlement conference among EPA Region III, Marcor and Columbia Transmission was held on January 12, 1995.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable. PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Corporation is traded on the New York Stock Exchange under the ticker symbol CG and abbreviated as either ColumGas or ColGs in trading reports. The number of shareholders of record on February 28, 1995, was approximately 60,000 and the stock closed at $26. On June 19, 1991, the Corporation suspended the dividend on its common stock. Management cannot determine at this time when dividends will again be paid.
See Item 7 on page 27 for additional information regarding the Corporation's common stock prices and dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA The Columbia Gas System, Inc. and Subsidiaries
N/M - Not meaningful * Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements. Due to the bankruptcy filings, estimated pre-tax interest expense of approximately $222 million, $207 million, $203 million and $84 million has not been recorded for 1994, 1993, 1992 and 1991, respectively. ** Prior to its Chapter 11 filing, the Corporation made extensive use of variable rate debt since the associated cost was normally less than senior long-term debt. Inclusion of the short-term debt in years prior to 1991 makes those historical ratios more meaningful.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BANKRUPTCY MATTERS
On July 31, 1991, The Columbia Gas System, Inc. (Corporation) and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. Both the Corporation and Columbia Transmission were granted debtor-in-possession status under the Bankruptcy Code, allowing them to continue normal business operations subject to the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court).
Events Leading to Bankruptcy Filings Columbia Transmission's Chapter 11 filing was precipitated by a combination of events that adversely affected its physical operations and financial viability. Most notable were federal legislative and regulatory actions, instituted years after Columbia Transmission's gas purchase contracts were signed, that significantly impacted Columbia Transmission's ability to sell the gas it had contracted to buy and to recover its costs from its customers. These problems were exacerbated by record-setting warm weather in 1990 and 1991, which caused spot market prices for gas to plunge and created excess transportation capacity, thus making an unexpected and persistent oversupply of bargain-priced gas available to Columbia Transmission's customers. As a result, Columbia Transmission's ability to market its gas was severely undercut, substantially reducing both sales volumes and revenues.
As of July 31, 1991, the Corporation was in default on $83.5 million of short-term obligations and negotiations with banks and producers had met with only limited success. Therefore, on July 31, 1991, the Corporation and Columbia Transmission filed for protection under Chapter 11 of the Federal Bankruptcy Code in the Bankruptcy Court. A discussion of the proceedings under Chapter 11 protection as well as additional information on bankruptcy issues discussed in this section and related matters is included in Note 2 of Notes to Consolidated Financial Statements.
In contrast to the situation of many other Chapter 11 debtors, reorganization of Columbia Transmission has not been hampered by unprofitable or marginal business operations. Rather, the achievement of the Chapter 11 objective of reorganization has been impacted by the enormity and complexity of the disputed and contingent claims filed against it by unaffiliated creditors and by attempts on behalf of those creditors to obtain recoveries on such claims from the assets of the Corporation's estate. In addition, Columbia Transmission's status as a regulated gas transmission company under the Natural Gas Act (NGA) and its resulting obligations has brought into the bankruptcy forum creditors' rights issues which are complicated by public law issues arising under the NGA.
Bankruptcy Issues Intercompany Complaint On March 19, 1992, the Official Committee of Unsecured Creditors of Columbia Transmission (Columbia Transmission Creditors' Committee) filed a complaint (Intercompany Complaint) with the Bankruptcy Court alleging that the $1.7 billion of Columbia Transmission's secured and unsecured debt securities held by the Corporation
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
should be recharacterized as capital contributions (rather than loans) and equitably subordinated to the claims of Columbia Transmission's other creditors. The Intercompany Complaint also challenges interest and dividend payments made by Columbia Transmission to the Corporation of approximately $500 million for the period from 1988 to the petition date and the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an alleged fraudulent transfer. Based on the SEC standardized measurement procedures, CNR's properties had a reserve value of approximately $250 million as of December 31, 1994, a significant portion of which is attributable to the transfer from Columbia Transmission. At the Bankruptcy Court's request, the trial proceedings for the Intercompany Complaint were transferred to the U. S. District Court for the District of Delaware (the District Court) and were concluded on October 25, 1994. Post trial submissions were completed in December 1994, and the District Court is expected to render a decision in the first quarter of 1995. Management believes that the Intercompany Complaint is without merit; however, the ultimate outcome of these issues is uncertain at this stage of the proceedings.
Little progress has been made with Columbia Transmission's creditors in an attempt to establish the value of the estate and to resolve the matters raised in the Intercompany Complaint. Since the validity of the Corporation's debt investment in Columbia Transmission is crucial to the determination of the value of the Corporation's estate, the Corporation's reorganization will be affected by the ultimate outcome of the Intercompany Complaint.
Prepetition Obligations of Debtor Companies The accompanying consolidated balance sheet as of December 31, 1994, includes approximately $4 billion of liabilities subject to the Chapter 11 proceedings of the Corporation and Columbia Transmission as follows:
Columbia Transmission's prepetition obligations include secured and unsecured debt payable to the Corporation, secured debt interest, estimated supplier obligations, estimated rate refunds, accrued taxes and other trade payables and liabilities. Prepetition obligations of the Corporation primarily represent debentures, bank loans and commercial paper outstanding on the filing date together with accrued interest to that date. A substantial amount of Columbia Transmission's liabilities subject to Chapter 11 proceedings relate to amounts owed to the Corporation. Columbia Transmission's borrowings have been funded by the Corporation on a secured basis since June 1985 and are secured by mortgages and a cash collateral order approved by the Bankruptcy Court. On the petition date, the principal amount of the secured debt outstanding was $1,340.4 million. Prepetition and postpetition interest on secured debt owed by Columbia Transmission to the Corporation was $488.3 million at December 31, 1994. In addition to these secured claims, the Corporation has an unsecured claim against Columbia Transmission of $351 million in installment notes issued prior to 1985 and accrued interest to the petition date.
Producer Claims Estimation Process As a result of Columbia Transmission's bankruptcy petition filing in July 1991 and its rejection of more than 4,800 above-market gas purchase contracts with producers, Columbia Transmission had recorded liabilities of approximately one billion dollars for estimated contract rejection costs. In addition, approximately $200 million of take-or-pay and other miscellaneous producer claims had also been recorded.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
In 1992, the Bankruptcy Court approved the appointment of a claims mediator to implement a claims estimation procedure related to the rejected above-market producer contracts and other producer claims. On October 13, 1994, the claims mediator issued his Initial Report and Recommendation of the Claims Mediator on Generic Issues for Natural Gas Contract Claims (Report). The Report, which is subject to Bankruptcy Court review and approval, establishes the parameters within which producers must initially recalculate their contract rejection and take-or- pay claims. The recalculated claims will then be subject to challenge and audit and adjustment based upon claim specific issues. The Report generally validates the assumptions Columbia Transmission used earlier to estimate the total value of contract rejection claims filed by producers in the bankruptcy proceedings and clearly rules out most of the methods the producers utilized to derive grossly excessive and legally improper amounts in their original claims which amounted to $13 billion. The claims mediator has indicated that unaudited claims recalculations should be filed by April 21, 1995.
While the Report uses a lower discount rate than that used by Columbia Transmission and recognizes certain proved undeveloped reserves, it directs that calculations of damages be based only on the amount by which a contract price exceeds a mitigation price and be discounted to a present value as of the petition date. Not addressed in the report are numerous contract specific issues that ultimately will be used in the estimation procedure to determine the allowable level of producer claims. Columbia Transmission is not able to calculate individual contract rejection claims at this time because it does not have adequate data from the producers on the proved undeveloped reserves or on planned gas development projects. This data will only become available, and subject to challenge and audit, when the individual producers file their recalculations.
The Report does not address an alternative method for calculating contract rejection damages sponsored by Columbia Transmission. This methodology contemplates using the market value of the producers' reserves subject to the contracts rejected by Columbia Transmission as evidence of the economic value to producers of such contracts (Market Value Methodology). The claims mediator is expected to hold a hearing on this alternative methodology in the second quarter of 1995 and has indicated that Columbia Transmission's pursuit of its Market Value Methodology will not delay his completion of the discounted cash flow methodology contained in the Report.
In management's opinion, the $1.3 billion estimate previously reported represents the worst plausible case for allowed contract rejection claims, although it is anticipated that the producers' initial recalculations of these claims may exceed that total. Further, Columbia Transmission does not believe the Report produces any basis which would cause it to change the amount it previously recorded for contract rejection (approximately one billion dollars) given the information currently available to it. However, following the review of the Report by Columbia Transmission and its counsel, Columbia Transmission increased the $200 million reserve for take-or-pay and other miscellaneous producer claims by approximately $55 million in the third quarter of 1994.
The resolution of bankruptcy related issues could significantly influence future reported financial results. Accounting standards require that as claim amounts are allowed by the Bankruptcy Court, the full amount of the allowed claim must be recorded. This could result in liabilities being recorded which bear little relationship to the amounts ultimately required to be paid in settlement of those claims and could conceivably exceed the Corporation's total investment in Columbia Transmission. Any such distortion would not be corrected until final plans of reorganization are approved for the Corporation and Columbia Transmission.
Proposed Plans of Reorganization The Corporation's and Columbia Transmission's discussions with the Columbia Transmission Creditors' Committee to negotiate a reorganization plan for Columbia Transmission and expedite emergence from Chapter 11 proceedings had been largely unsuccessful. Therefore, on January 18, 1994, Columbia Transmission, with the Corporation as cosponsor, filed a reorganization plan (plan) and a disclosure statement, for consideration by its creditors and other interested parties. The plan provides that Columbia Transmission would remain a wholly-owned subsidiary of the Corporation, will continue to offer an array of competitive transportation and storage services, and will retain ownership of its 19,000-mile pipeline network and related facilities. Subsequent to the filing of the plan, Columbia Transmission had discussions directly with gas producers who have substantial claims against it. Despite months
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
of negotiations and numerous offers of settlement, Columbia Transmission has been unable to reach agreement on a consensual reorganization plan with the Columbia Transmission Creditors' Committee. However, Columbia Transmission has had recent discussions, on an individual basis, with a significant number of its largest producer claimants, but it is impossible to determine at this time if these discussions will lead to agreements on the claims.
The Corporation's and Columbia Transmission's exclusive rights to file plans of reorganization expire April 18, 1995. Prior to that date, the Corporation intends to file its reorganization plan with the Bankruptcy Court and to cosponsor amendments to the reorganization plan that Columbia Transmission filed in January 1994.
Both plans will be subject to review and approval requirements (including authorizations from the SEC) which may require several months to complete.
Implementation of reorganization plans for Columbia Transmission and the Corporation, and the levels and timing of distributions to their creditors, are subject to a number of risk factors which could materially impact their outcome. Both companies anticipate emerging from bankruptcy at the same time. The provisions of the reorganization plans of either Columbia Transmission or the Corporation that are ultimately implemented could be materially different from the filed plans.
Customer Refunds Total customer claims in Columbia Transmission's bankruptcy proceedings relating to, or arising from, contracts with its customers for sales, transportation, gas storage and similar services and other miscellaneous claims represent about 450 claims for a total filed amount of approximately $550 million, plus a potentially substantial sum filed as undetermined. While a significant portion of these claims has been resolved, as a result of a Third Circuit Court decision directing the pass-through of certain refunds, claims filed as "undetermined" still remain to be resolved.
The refund issues underlying customer claims include Federal Energy Regulatory Commission (FERC) Orders Nos. 500 and 528 (Order 500/528) direct charges that were billed to Columbia Transmission by upstream pipeline companies, prepetition revenues collected subject to refund in general rate filings, purchased gas adjustment filings, and other upstream pipeline flowthrough filings. Appropriate reserves for rate refund liabilities have been recorded for these matters to reflect management's judgment of the ultimate outcome of the proceedings. (See Note 2H in Notes to Consolidated Financial Statements for additional information.)
Customer Recoupment Motion Various customers of Columbia Transmission filed motions with the Bankruptcy Court during 1993, seeking authority to exercise alleged recoupment and setoff rights, whereby they would be permitted to reduce amounts owed to Columbia Transmission for current services against refunds owed to the customers by Columbia Transmission. These would include amounts which were not otherwise payable in full under a July 1993 Third Circuit Court decision, all customer refunds under a 1990 rate case settlement, and miscellaneous refunds not otherwise payable in full.
The Bankruptcy Court approved an interim settlement in 1993 under which customers continued to pay Columbia Transmission for services authorized by the FERC at approved rates, and Columbia Transmission has agreed to grant these customers a priority claim to the extent the Bankruptcy Court finds them entitled to recoupment rights. In January 1994, the Bankruptcy Court issued a procedural order whereby other customers were permitted to file recoupment and setoff motions by February 18, 1994. Customers, Columbia Transmission and other interested parties have filed summary judgment motions and responses on these issues.
Discussions continued in 1994 with Columbia Transmission's former wholesale customers and others to resolve a number of FERC proceedings and bankruptcy claims, including the customer recoupment motion, which remains pending before the Bankruptcy Court.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Upstream Pipeline Contracts Columbia Transmission has transportation contracts with certain pipeline companies that historically have been used to deliver gas to Columbia Transmission. Some of these pipelines filed claims in the bankruptcy proceedings which have subsequently been settled. The settlements provide for the assumption of certain contracts, the termination of certain other contracts that are no longer necessary for Columbia Transmission's operations, or the substantial reduction of the transportation contracts. As a result, approximately $463 million of claims filed by the pipelines against Columbia Transmission will be withdrawn when all settlements receive Bankruptcy Court and regulatory approvals. Columbia Transmission retains the option of rejecting such contracts through the bankruptcy process in the event that settlements do not receive the Bankruptcy Court and FERC approvals. (See Note 2B in Notes to Consolidated Financial Statements for additional information.)
Other Related Issues Interest Expense Interest expense of the Corporation is not being accrued during bankruptcy, but a calculation of interest is included in a footnote on the statements of consolidated income and consolidated balance sheets. Such interest has been calculated based on an interpretation of the contractual arrangements which govern the various debt instruments the Corporation has outstanding exclusive of any redemption premiums. In 1993, the Official Committee of Unsecured Creditors of the Corporation (Committee) asserted claims for interest which exceed disclosed amounts by approximately $40 million. There are several factors to be considered in making these calculations that are subject to uncertainty as to their ultimate outcome in the bankruptcy proceeding, including the interest rates and method of calculation to be applied to overdue payments of principal and interest. In addition, the Committee has asserted that approximately $110 million of redemption premiums should be paid on high cost debt instruments to compensate investors for anticipated lower interest rates when the debt is refinanced. These amounts reflect, in part, interest rate markets in late 1993. Resolution of these issues will be dependent upon, among other items, interest rates and market conditions at the time of emergence from bankruptcy.
Security Holder Litigation After the announcement on June 19, 1991, regarding the Corporation's probable charge to second quarter earnings and the suspension of its dividend, 17 complaints including purported class actions were filed against the Corporation and its directors and certain officers of the debtor companies in the District Court. The actions, which generally allege violations of certain anti-fraud provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934, have been consolidated. On October 31, 1994, the class action plaintiffs filed an amended and consolidated complaint against the non-debtor defendants in the District Court essentially alleging the same causes of action as the previously filed complaints. In addition, these plaintiffs filed a motion for class certification in both the Bankruptcy Court and the District Court. The plaintiffs also filed a motion seeking to withdraw the litigation against the Corporation from the Bankruptcy Court to the District Court. On November 1, 1994, the Corporation filed a motion with the Bankruptcy Court that seeks to require the individual class action plaintiffs to file supplementary information with respect to their previously-filed proofs of claims. Any person not responding would be barred from asserting their claims pursuant to such procedures. In an order dated November 30, 1994, the District Court stayed both the District Court and Bankruptcy Court litigation until a final judgment is entered in the Intercompany Complaint litigation.
On February 13, 1995, the Corporation, in order to promptly address the securities claims in its plan of reorganization, requested the District Court to modify the stay order by considering the Corporation's motion to supplement class proofs of claims. The plaintiffs have objected to this modification.
Also in 1991, three derivative actions were filed in the Court of Chancery in and for New Castle County (Delaware) alleging that directors breached their fiduciary duties. These suits have been stayed by either the bankruptcy filing or by stipulation of the parties.
While the Corporation and its officers and directors believe that they have meritorious defenses to these actions, the outcome is uncertain at this time.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Internal Revenue Service Matters During 1994, a settlement was negotiated with Internal Revenue Service (IRS) representatives on all of the issues included in the duplicate claims of $553.7 million which the IRS had filed against both debtor companies and the consolidated Columbia Gas System for tax deficiencies, interest and penalties for the years 1983-1990. The settlement was approved by the Joint Committee on Taxation of the U. S. Congress on June 30, 1994, and the Bankruptcy Court on October 12, 1994. The settlement reduced the original claim to approximately $112 million. The final cost of the settlement is expected to be about $46 million after taking into consideration certain tax deductions that become available in subsequent years. The after-tax impact of the settlement had been previously recorded.
The IRS is currently conducting an audit of the 1991-1992 tax years. As part of this audit the Corporation has received a proposed notice of disallowance for its tax deduction of interest expense during this period. The issue concerns only the timing of the interest deduction and not the deductibility of interest expense. Over the next several months the Corporation will present evidence to IRS representatives supporting this deduction. If necessary, the Corporation will pursue this issue through the IRS appeals process or the Bankruptcy Court. If the Corporation cannot sustain the deduction in the years taken, interest expense on the tax deficiency could be due to the IRS, with an after-tax impact of approximately $10 million at December 31, 1994.
Leveraged Employee Stock Ownership Plan (LESOP) On March 2, 1993, the Trustee for the Indenture, under which debentures were issued by the Employees Thrift Plan of Columbia Gas System (Thrift Plan), filed a complaint against the Corporation in the Bankruptcy Court. The Trustee alleges that matching payments made by the Corporation to the Thrift Plan should have been allocated to pay debt service on the outstanding debentures instead of credited to the employees' accounts.
On March 24, 1994, the Bankruptcy Court denied the Corporation's motion for summary judgment and on April 22, 1994, the Corporation filed a motion for leave to appeal the ruling of the Bankruptcy Court which was granted May 18, 1994. Oral argument in the Corporation's appeal was held before the U.S. District Court for the District of Delaware on October 27, 1994, but the court has not yet issued its decision. If the Corporation's appeal is denied, the matter will proceed to trial. The Corporation believes that it has meritorious defenses to the Indenture Trustee's claims and that the nonpayment of LESOP debt will not affect the participants' benefits under the plan.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
CONSOLIDATED REVIEW
Net Income The Corporation's net income for 1994 was $240.6 million, or $4.76 per share, an increase of $88.4 million, or $1.75 per share over the previous year. After adjusting both periods for the effect of bankruptcy and unusual items, 1994's net income was approximately $157.9 million, essentially unchanged from adjusted 1993 net income of $160.4 million. The impact of lower oil and gas prices, warmer weather and higher operating costs for the distribution segment were offset by interest earned on cash accumulated during bankruptcy and improved results for the transmission segment due in part to the full year effect of FERC Order No. 636 (Order 636).
Unusual and Bankruptcy Related Items After-Tax Effect on Net Income
Revenues For 1994 operating revenues decreased $557.8 million, to $2,833.4 million primarily reflecting the elimination of Columbia Transmission's merchant function in November 1993. Under Order 636, wholesale customers are now purchasing their gas requirements from third parties and using Columbia Transmission's transportation services for delivery. Also reducing revenues were pipeline exit fees of $130 million recorded last year that were offset in products purchased expense and had no effect on income. Lower revenues in 1994, compared to last year, were also attributable to Columbia Transmission establishing a $35 million reserve in the current year for customer settlements, warmer weather for the distribution segment and the effect of lower prices and reduced gas production.
Operating revenues for 1993 increased more than 16 percent from 1992 to $3,391.2 million due largely to the effect of Columbia Transmission's new rate design, pipeline exit fees of $130 million for Columbia Transmission, higher retail sales resulting from colder weather and higher distribution rates. Revenues from the pipeline exit fees were offset in products purchased expense and had no effect on income.
Expenses Operating expenses of $2,460.2 million for 1994, decreased $557.6 million from 1993. The largest portion of this decrease was attributable to a $597.8 million reduction for products purchased reflecting the elimination of Columbia Transmission's merchant function and 1993 expense associated with pipeline exit fees, mentioned above. The current period total expense was also lower by comparison due to the effect of certain 1993 items; namely a $57.5 million writedown for the Corporation's investment in Columbia LNG and environmental accruals of $66.8 million. The favorable effect of these items was offset by generally increasing operating costs, depreciation and depletion expense and other taxes.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
In 1993, higher sales necessitated an increase in volumes of gas purchased resulting in an increase in products purchased expense of $337.6 million over 1992. Also contributing to the increase were higher average rates for gas purchased and pipeline exit fees. Higher operation and maintenance expense in 1993 of $26.5 million reflected higher labor and benefits costs, including $14.8 million for severance costs associated with reengineering, and a $66.8 million addition to the environmental reserve as well as rising operating costs. The 1992 recording of a writedown of $126.4 million in the carrying value of oil and gas properties due to depressed energy prices was the principal reason for the $128.3 million decrease in depreciation and depletion expense in 1993.
Other Income (Deductions) Other Income (Deductions) in 1994 resulted in income of $19 million compared to a loss of $85.3 million in the prior year. This improvement primarily reflected the effect of $74.5 million of interest expense recorded in 1993 for the IRS settlement and a subsequent $15.8 million reduction in this reserve in 1994. The current period also includes prepetition interest expense of $14.9 million for estimated producer claims against Columbia Transmission based on an initial interpretation of the claims mediator's report (see Note 2 in Notes to Consolidated Financial Statements for additional information). Interest income and other, net was $38.8 million higher in 1994 due primarily to a $21 million reserve adjustment for carrying charges related to prior period exchange activity as well as establishing a reserve in 1993 for pipeline partnerships. Income benefited from not accruing interest expense for prepetition obligations in 1994 and 1993 by approximately $222 million and $207 million, respectively. (Since the July 31, 1991 bankruptcy filing, the estimated effect of not accruing interest expense on these prepetition obligations totals approximately $716 million. However, the actual interest that will ultimately be paid pursuant to the final plans of reorganization could differ significantly and cannot be determined at this time). Reorganization items, net reflects bankruptcy issues that decreased income in 1994 by $12.3 million and improved income $8.9 million in 1993. In 1994, a $40 million reserve for producer claims was recorded, and professional fees and related expenses increased $4.7 million from last year to $35.4 million. These higher expenses were partially offset by a $23.5 million increase in interest earned on accumulated cash.
Other Income (Deductions) reduced income in 1993 by $85.3 million versus $1.5 million in 1992. Interest expense increased $87.8 million in 1993 due largely to recording interest on prior years' taxes of $74.5 million primarily as a result of the IRS settlement. The decrease of $13.2 million in Interest income and other, net reflected $19.5 million for a FERC order eliminating interest payments from certain upstream pipeline suppliers and a reserve for pipeline partnership investments partially offset by increased interest income on prior years' taxes and other issues. The change between 1993 and 1992 for Reorganization items, net increased income $17.2 million. Professional fees and related expenses, combined with other miscellaneous reorganization items decreased $4.2 million while interest earned on accumulated cash increased income $13 million.
Income Taxes Increased income led to higher income tax expense of $146 million for 1994, an increase of $10.1 million over 1993. For the period between 1993 and 1992, income tax expense increased to $135.9 million, up $65.4 million. This increase was due to higher income, adjustments for the IRS settlement and an increased tax rate. See Note 6 in Notes to Consolidated Financial Statements for additional information.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF COMMON STOCK PRICES AND DIVIDENDS
LIQUIDITY AND CAPITAL RESOURCES
Cash from Operations Net cash from operations of $572.8 million for 1994, was a decrease of $277.6 million, largely due to Order 500/528 refunds made by Columbia Transmission in early 1994, exit fee payments made in the current period, together with the effect of lower oil and gas prices and gas production as well as warmer weather in the fourth quarter. In addition, in the prior period cash from operations was higher due to refunds received from certain pipelines and the sale of Columbia Transmission's gas in underground storage, resulting from the elimination of its merchant function.
In 1993, cash from operations of $850.4 million was up $85 million over the year earlier. This improvement primarily was due to the full year effect of Columbia Transmission's new rate design, refunds received in 1993 from certain suppliers and higher rates for Distribution and colder weather than 1992. Higher oil and gas production and gas prices also contributed to the improvement.
Financing Activities The Corporation maintained a debtor-in-possession facility (DIP Facility) through September 1994 for up to $100 million, including the availability of letters of credit of up to $50 million. On September 15, 1994, the Corporation amended the DIP facility to discontinue the borrowing option and allow solely for the issuance of letters of credit of up to $25 million. As of January 31, 1995, $13.7 million of letters of credit were outstanding under the DIP Facility. The Corporation's liquidity needs are being satisfied by internally generated funds. As of January 31, 1995, the Corporation and its subsidiaries, excluding Columbia Transmission, had $263.8 million invested in money market instruments.
The liquidity needs of Columbia Transmission are being satisfied by internally generated funds. As of January 31, 1995, Columbia Transmission had $1,279 million invested in money market instruments. Columbia Transmission also maintains a DIP Facility solely for the issuance of letters of credit of up to $25 million. As of January 31, 1995, the balance of outstanding letters of credit under Columbia Transmission's DIP Facility was $1.8 million.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Derivatives Used For Canadian Escrow Investment The sale of Columbia Gas Development of Canada Ltd. (Columbia Canada), a wholly-owned Canadian oil and gas exploration and production subsidiary, to Anderson Exploration Ltd. was effective as of December 31, 1991. The sales price for Columbia Canada was $94.8 million. Of this amount, $27.7 million was placed in escrow as security for certain post-closing obligations of the Corporation including indemnification for potential losses arising from litigation involving Columbia Canada. The Corporation expects to receive all or substantially all of the escrow account when the litigation is concluded.
The Corporation uses financial instruments to protect its exposure to fluctuations in the exchange rates for the Canadian escrow investment. The funds are invested in short-term Canadian government securities. To insure that the Corporation's U.S. dollar proceeds are not affected by changes in the exchange rate between the Canadian dollar-denominated securities and the U.S. dollar, hedging is undertaken at a very nominal cost. The hedging is accomplished by the Corporation selling forward the amount of Canadian dollars expected to be received at the next maturity date of an individual investment. Upon such maturity date, that Canadian dollar "short" position is offset with a like purchase (or "long" position) of Canadian dollars and a new short position for the next investment is created simultaneously. Since the value of the Canadian dollar has fallen vis-a-vis the U.S. dollar, this hedge prevents any loss in the value of the investment.
Capital Expenditures
Capital expenditures for 1994 were $447 million, an increase of $86 million over 1993. The largest portion of the investments in the transmission subsidiaries (Transmission) were made to assure the safety and reliability of the pipelines and for compliance with the Clean Air Act Amendments of 1990. In addition to expenditures required to ensure safe and reliable service and improved service where warranted, the distribution subsidiaries' (Distribution) program includes investments to provide deliveries to gas powered electric generating plants and third-party public refueling stations for natural gas vehicles. The capital expenditures for the oil and gas segment increased $7 million from the 1993 level to reflect additional expenditures for the southwest exploration program.
In 1995 capital expenditures will increase $44 million to $491 million. The largest portion will continue to be for the ongoing replacement and upgrading of the distribution and interstate pipeline facilities. Expenditures are also planned for 75 company-owned natural gas vehicle fueling stations. Investment in Transmission and Distribution will remain essentially at the 1994 level. An increase in 1995 expenditures in the oil and gas segment is for renewed exploration drilling in the southwest to prevent reserve declines and for development drilling in Appalachia delayed as a result of an extremely wet spring in 1994.
Public Utility Holding Company Act of 1935 Reform In June 1994, the SEC initiated reform of the Public Utility Holding Company Act of 1935 (Act) with the announced intent of developing recommendations for legislative or regulatory changes by July 1995. The substantive provisions of the Act have not been amended since its enactment. The Corporation is one of only 15 public utility holding
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
companies remaining registered under the Act and one of only three registered gas utility holding companies. A two-day roundtable was held in July 1994 at which representatives of registered companies, exempt companies, state commissions, consumer advocates and rating agencies spoke. There was agreement that reform of the Act is overdue. A Concept Release requesting comments was issued in October 1994. Columbia joined with other registered gas utility holding companies in filing comments suggesting specific regulatory reforms.
At the same time that the SEC study is proceeding, legislation calling for repeal of the Act has been introduced in Congress. Whether the reform ultimately will occur through repeal of the Act, through targeted amendments of specific terms of the Act or through regulatory reforms remains to be seen.
The reporting and approval requirements and restrictions placed on the Corporation by the Act have resulted in delays and lost opportunities and, on occasion, may have caused the Corporation to alter a business plan to comply with restrictions under the Act. Repeal or reform would benefit the Corporation by eliminating or lessening these detrimental effects.
Shareholder Rights Plan The Corporation is seeking to implement a shareholder rights plan (Rights Plan) to protect shareholders' investments in the event of an unsolicited, inadequate offer for the Corporation's common stock.
The Corporation's shareholders are scheduled to vote on amendments to the Corporation's Certificate of Incorporation (Charter) required to allow implementation of the plan at the Corporation's annual meeting on April 28, 1995. The Rights Plan will also require approval of the SEC and the Bankruptcy Court.
In the unlikely event the Rights Plan would be triggered, all shareholders, except the person or group attempting the unsolicited takeover, would be entitled to purchase fractional shares of preferred stock at a discount. These fractional shares would have voting and dividend rights equivalent to the Corporation's common stock. The issuance of the preferred stock is designed to substantially dilute the third party's equity interest in the Corporation and significantly increase the Corporation's capitalization, thereby making its acquisition much more expensive.
The Rights Plan, which will become effective as soon as all necessary approvals are obtained, terminates automatically 18 months after the Corporation emerges from Chapter 11 protection, subject to extension if an offer is pending.
A proxy statement which describes the proposed amendment to the Charter and the proposed Rights Plan has been mailed to all holders of the Corporation's common stock of record as of February 28, 1995. For further information concerning the Rights Plan, please review the Proxy Statement (incorporated herein by reference).
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATIONS
During 1994, Transmission continued to focus on a strategy of providing a portfolio of storage and transportation services to customers at competitive prices. This strategy will continue to be supported by new technologies to improve customer service, modernization and upgrading of pipeline operations to ensure safe and reliable customer service, and reengineering key business processes to improve the companies' competitive position.
Marketing Initiatives Columbia Transmission announced in late 1994 a proposal to expand its pipeline and storage capacity to serve the increasing natural gas requirements of customers in its market area. Preliminary discussions with customers have indicated a need for the increased capacity. The extent of any capacity expansion by Columbia Transmission is dependent upon the ultimate level of customer commitments to be received in the coming months. However, based on preliminary discussions, Columbia Transmission is anticipating expanding its system to serve as much as 250,000-300,000 Mcf per day (Mcf/d) of incremental firm markets. This expanded service will be phased in over a multi-year period beginning in November 1997 and will be comprised of both firm transportation and storage services. An open season for the market expansion project was held from February 15, 1995, to March 16, 1995. Columbia Transmission believes that the rates for these services will be competitive with other pipeline proposals.
Also in early 1995, construction was completed on facilities needed for Columbia Transmission to provide nearly 60,000 Mcf/d of new firm transportation service to the Eagle Point Cogeneration Plant in West Deptford, New Jersey, and to a power plant in Massachusetts. These facilities will also allow Columbia Transmission to provide 9,600 Mcf/d of off peak transportation service to the Vineland Cogeneration Limited Partnership's 46.5 megawatt cogeneration plant in Vineland, New Jersey.
Based on a November 1994 agreement with the City of Richmond, Commonwealth Gas Services, Inc., and Virginia Natural Gas Company, Columbia Transmission will install additional vaporization equipment at its Chesapeake liquefied natural gas (LNG) facilities to provide these customers an incremental 33,650 Mcf/d of peak deliveries, raising the total available sendout from 81,700 Mcf/d to 115,350 Mcf/d. The customers will fund the cost of the vaporization equipment, which is estimated to be approximately $2.4 million. This expanded LNG service is expected to commence in December 1995.
Columbia Transmission has reached a 25-year agreement to deliver 23,300 Mcf/d of firm transportation to a Maryland cogeneration facility beginning in June 1996. The agreement requires $11 million of new construction, which will be jointly funded by Columbia Transmission and the owner of the cogeneration facility.
Capital Expenditure Program Transmission's 1994 capital expenditure program of approximately $179 million, and anticipated capital expenditures over the next five years, reflect the segment's continued commitment to maintaining its competitive position by modernizing and upgrading existing facilities. The commitment will ensure a safe, reliable and efficient pipeline system, which conforms to all pipeline safety regulations. Total expenditures in this area are expected to approximate $130 million per year over the next five years. Other significant future capital expenditures include the new market development programs previously discussed and compliance with the Clean Air Act Amendments of 1990.
Regulatory Matters
1990 Rate Case Settlement In 1992, the FERC approved a 1990 rate case settlement wherein Columbia Transmission and Columbia Gulf proposed to pay pre- and postpetition refunds with interest at FERC prescribed rates. In August 1994, the Bankruptcy Court declined to approve this settlement, ruling that the refund is a prepetition unsecured claim and payment of such claims must be addressed in a plan of reorganization. Various state agencies appealed the Bankruptcy Court's order to the District Court for the District of Delaware and filed a motion with the FERC to order an immediate and full refund of the settlement amounts. The District Court has held all procedural dates in abeyance pending the FERC's final ruling on the state agencies' motion. On January 11, 1995, FERC denied the state agencies' motion to direct Columbia
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Transmission to make all such refunds to its customers on the grounds that the necessary regulatory approvals have been granted, and that the unresolved issues relate solely to the interpretation of the Bankruptcy Code. In February 1995, the FERC denied rehearing on the order.
FERC Order on the Recovery of Carrying Charges In June 1994, the FERC granted rehearing of a prior order and determined that Columbia Transmission could recover approximately $20 million in carrying charges related to prior period exchange activity. In July 1994, certain parties filed a request for rehearing of this decision, which is still pending. The beneficial effect on income of the FERC's decision was recorded in 1994.
Columbia Gulf's Rate Case On October 31, 1994, Columbia Transmission terminated its long-standing contract with Columbia Gulf, under which Columbia Gulf transported gas supply acquired by Columbia Transmission in the southwest, on a cost-of-service basis that assured recovery of Columbia Gulf's operating costs. This action was taken because Columbia Transmission's merchant function was essentially eliminated under Order 636. Columbia Gulf submitted a general rate filing in order to reflect the elimination of this contract and recover higher costs since the last rate adjustment. On November 1, 1994, it placed its new rates into effect, subject to refund. The new rates provide additional annual revenue of approximately $23 million over previously approved rates. Various parties have challenged proposals by Columbia Gulf in this proceeding, including the requested revenue increase, proposed changes in depreciation rates, and the projected levels of service upon which the rates would be developed. Settlement discussions with the FERC and interested parties are ongoing. A hearing on this rate filing is currently scheduled to begin in September 1995.
Customer Refunds Approximately 450 claims in Columbia Transmission's bankruptcy proceedings relating to, or arising from, contracts with its customers for sales, transportation, gas storage and similar services and other miscellaneous claims total approximately $550 million, plus a potentially substantial sum filed as undetermined claims. Columbia Transmission believes that a significant portion of these claims has been resolved. The claims filed as "undetermined" still remain to be resolved.
In April 1994, Columbia Transmission refunded approximately $139 million to its customers to settle a portion of their claims. The majority of these refunds were for overpayments Columbia Transmission and its customers previously made to upstream suppliers under Order 500/528 for take-or-pay and related charges.
A significant unresolved portion of the customer claims is attributable to the Baltimore Gas & Electric v. FERC litigation in which various customers have challenged Columbia Transmission's right to recover Order 500/528 direct charges upstream pipeline companies billed Columbia Transmission. For this issue, the accompanying financial statements reflect a $35 million reserve. Settlement discussions are underway with the customers on this and other significant issues related to the bankruptcy claims, as well as transition costs recoverable from the customers under Order 636. (See Note 2H in Notes to Consolidated Financial Statements for additional information.)
Other refund issues underlying customer claims include prepetition revenues collected subject to refund in general rate filings, purchased gas adjustment filings, transportation cost recovery adjustment filings, and other upstream pipeline flowthrough filings. Reserves that reflect management's judgment of the ultimate outcome of the proceedings have been recorded for these matters.
At a December 1993 hearing, the Bankruptcy Court observed that the FERC should determine whether customers are entitled to the actual interest earned on refunds being held by Columbia Transmission in a restricted investment account (RIA) or the higher FERC-prescribed interest rate. The FERC determined that Columbia Transmission must disburse the RIA funds with interest actually earned while in the RIA account (which was established in March 1993) and with interest at the FERC prescribed rate for the period prior to the date the RIA was created. On October 5, 1994, the FERC denied a request by Columbia Transmission's customers for rehearing of its order. The FERC's order has been appealed.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Upstream Pipeline Contracts Columbia Transmission has transportation contracts with certain pipeline companies that historically have been used to deliver gas to Columbia Transmission. Columbia Transmission has settled claims filed by some of these pipelines in the bankruptcy proceedings. These settlements provide for the assumption of certain contracts, the termination of certain other contracts that are no longer necessary for Columbia Transmission's operations, or the substantial reduction of the transportation contracts. As a result, approximately $463 million of claims filed by the pipelines against Columbia Transmission will be withdrawn when all settlements receive Bankruptcy Court and regulatory approvals. These settlements include projected exit fee payments of approximately $105 million, including amounts already paid to certain pipelines through December 1994, and are conditioned upon Columbia Transmission's recovery of the exit fees through rates. (See Note 2 in Notes to Consolidated Financial Statements for additional information.)
Order 94 Costs In January 1994, the FERC rejected on rehearing prior orders approving settlements between Columbia Transmission and four of its upstream pipeline suppliers. These settlements permitted the pipelines to direct bill Columbia Transmission for production-related costs authorized under FERC Order No. 94 (Order 94), provided Columbia Transmission could recover the costs from its customers. After reversing a previous ruling and determining that Columbia Transmission's 1985 Purchase Gas Adjustment Settlement bars such recovery, the FERC held that the pipelines are not entitled to bill any Order 94 charges to Columbia Transmission. It ordered the upstream pipelines to refund the principal amounts of all Order 94 collections received from Columbia Transmission, but waived any requirement that these pipelines pay interest on the refunds. Since Columbia Transmission had been accruing interest income on these refunds since 1990, these orders led to a $19.5 million reduction to pre-tax income in 1993. In October 1994, the FERC denied all requests for rehearing but ordered the upstream pipeline suppliers to pay Columbia Transmission interest on the refunds from the date the stays were issued in February 1994. As a result, in September 1994, Columbia Transmission recorded approximately $1 million of interest income. Although the orders required that refunds be made by November 17, 1994, Columbia Transmission and the pipelines agreed to an extension to allow judicial review, subject to certain conditions, one being that any refunds will accrue interest at FERC rates while the issues are litigated. Columbia Transmission, its upstream pipelines, and two other customers of one upstream pipeline have filed petitions for review of the subject orders with the U. S. Court of Appeals for the District of Columbia.
Production Area Facilities Columbia Transmission owns and operates natural gas gathering and processing facilities in production areas. In its orders addressing the company's restructuring proposals under Order 636, the FERC allowed Columbia Transmission to maintain its existing rate structure and recover costs associated with these facilities until it files its next general rate case. Management continues to evaluate the long-term plans for the gathering and processing facilities, which have a net book value of approximately $59.7 million at December 31, 1994. Management believes that substantially all of these costs will be recovered through rates or sale of the facilities; however, the ultimate outcome of this issue is uncertain at this time, and future charges to income may be required.
Columbia Gulf Show Cause Order In its September 1993 order on Columbia Transmission's and Columbia Gulf's Order 636 compliance filings, the FERC initiated a proceeding concerning Columbia Gulf's transportation service to Columbia Transmission. It directed Columbia Gulf to show cause as to why it had not filed for FERC abandonment authorization to reduce capacity on its mainline facilities. Columbia Gulf responded in December 1993, asserting that no abandonment filing was required. During 1994 and early 1995, Columbia Transmission and Columbia Gulf responded to information requests from the FERC's staff. Management continues to believe that an abandonment filing was not necessary; however, the ultimate outcome of this issue is uncertain at this time.
Environmental Matters Columbia Transmission reached an agreement during 1994 with the U.S. Environmental Protection Agency (EPA) that will give the agency oversight responsibility for an ongoing environmental self-assessment and remediation program Columbia Transmission started in 1990. The agreement calls for the cleanup to be done under the guidelines of the
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Comprehensive Environmental Response Compensation and Liability Act. This agreement was approved by the Bankruptcy Court in November 1994 with a February 23, 1995, effective date.
Agreements have also been reached with two state environmental agencies concerning Columbia Transmission's environmental remediation programs. In Kentucky, Columbia Transmission settled all notices of violation issued prior to January 1, 1994, and will reimburse the state for its costs to oversee the remediation work under an EPA order. In Pennsylvania, Columbia Transmission agreed to reimburse the state for its oversight costs. Both agreements have received Bankruptcy Court approval.
All of Columbia Transmission's future remediation work will be performed under the EPA order which details specific approvals and procedures that must be followed. A study previously undertaken for Columbia Transmission which quantified the scope of remediation activities to be undertaken in future years is being reviewed by an independent consultant in light of the order and additional information accumulated during 1994. The results of this study are not expected to be available until early to mid-1995. Until the new study results are available, management has no basis to change its previously disclosed estimated level of environmental expenditures of up to $20 million per year over a 10 to 12 year period. Earnings are charged as costs become probable and reasonably estimable, regardless of when expenditures are made. Columbia Transmission's recorded net liability for environmental matters was approximately $135 million at December 31, 1994. This amount represents the lower end of a range of reasonable outcomes with the upper end estimated to total approximately $280 million based on previous studies.
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 unable at this time to determine if it will become liable for any characterization or remediation costs at such sites.
During 1994, Columbia Gulf continued its remediation program. Additional site characterization studies at various locations were completed which resulted in additional accruals of approximately $19.3 million for environmental matters of which a portion was recovered in current period revenues. The additional accruals were to remediate newly discovered PCB and hydrocarbon contamination at certain compressor station sites, pipeline drip sites, and measurement sites. During the fourth quarter of 1994, Columbia Gulf made significant progress on completing remediation work identified to date. Additional remediation work remains to be completed in 1995. Columbia Gulf's environmental liabilities recorded as of December 31, 1994, are $5.8 million which includes the estimate for 1995 work. Should future screenings identify additional exposure, the remediation costs will be quantified and additional accruals may become necessary.
The eventual total cost of full future environmental compliance for Transmission 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 new environmental agency rules; (3) the possibility of future litigation; (4) the possibility of future designations as a potentially responsible party by the EPA and the difficulty of determining liability, if any, in proportion to other responsible parties; (5) possible insurance recoveries; and (6) the effect of possible technological changes relating to future remediation.
Management expects most environmental assessment and remediation costs will be recoverable through rates or insurance. Court suits have been filed by both Columbia Transmission and Columbia Gulf against several of their insurance carriers for recovery of environmental remediation costs. Although significant charges to earnings could be required prior to rate recovery, management does not believe that environmental expenditures will have a material adverse effect on the Corporation's financial position based on known facts, existing laws and regulations and the period over which expenditures are required.
Clean Air Act Amendments of 1990 Transmission previously disclosed that, based upon preliminary studies to determine the impact of the Clean Air Act Amendment of 1990 (CAA- 90), estimated capital expenditures necessary to comply with the first phase could be in
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
excess of $30 million over the next few years. As a result of certain areas being reclassified from non-attainment to attainment, it is now estimated that the capital expenditures necessary to comply with the first phase will be approximately $15 million over the next few years. Until regulations are finalized, the capital expenditures necessary to comply fully with CAA-90 cannot be estimated. Management anticipates that capital expenditures made in compliance with CAA-90 will be recoverable through the ratemaking process.
Partnership Issues Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark pipeline partnerships. Since the partnerships are nonrecourse, project-financed pipelines, the partnerships' firm shipper contracts were assigned as collateral for loans to various banks (or in the case of Ozark, to the Indenture Trustee).
During 1994, various pipeline shippers, including Columbia Transmission, entered into negotiations with the partnerships for exit fees to substantially reduce the cost of or provide for the release from transportation contracts. Agreements have been reached on certain contracts and are currently pending approval by the FERC. Columbia Gulf's investment in the partnerships as of December 31, 1994, amounted to $34.7 million, net of valuation reserves and before related deferred taxes.
In February 1995, an agreement was reached which provides for the sale of Columbia Gulf's Ozark partnership investment. The agreement contains usual closing conditions and is subject to certain governmental approvals. Closing is expected to occur on May 1, 1995. The impact of the sale of Columbia Gulf's interest in the partnership is not expected to have a material impact on the financial condition of the company.
Reengineering Activities As previously reported, the Corporation initiated a reengineering program in which the subsidiaries were to evaluate and streamline organizational structures to improve efficiencies. This continuous improvement process will extend into 1995 and beyond. In 1993, Transmission established reserves of approximately $4 million for the projected cost of its Reengineering Retention and Release program for employees whose positions were being eliminated. During 1994, this reserve was increased by $3.9 million. The total reserve balance for Transmission for the Reengineering Release and Retention program as of December 31, 1994, was approximately $3.4 million.
Volumes Throughput for Columbia Transmission is now primarily composed of a transportation service, while prior periods included tariff sales to local distribution companies (LDCs) and other customers in its market area. Columbia Gulf throughput includes main line transportation service from Louisiana to West Virginia and short-haul transportation service primarily from the Gulf of Mexico to Rayne, Louisiana. Transmission's 1994 throughput was 1,272 Bcf, a decrease of 83.9 Bcf from 1993. This decrease reflects a timing change for the recognition of transportation for storage activity and reduced short-haul transportation needed by customers for spot purchases. In 1993, throughput decreased 18.4 Bcf from 1992 to 1,355.9 Bcf. The reduction was largely attributable to a small decrease in sales resulting from implementing Order 636 in November 1993, and lower transportation reflecting the effect of a one-time arrangement in 1992 whereby customers used transportation to repay certain gas delivered to them in an earlier period. Under Order 636, a large portion of Transmission's fixed costs are being recovered through a monthly demand charge. As a result, variations in total throughput have less impact on income.
An increase of 142.7 Bcf in market area transportation over 1993 was primarily due to customers switching from sales to transportation services, resulting from the implementation of Order 636, partially offset by a timing change in the recognition of market area transportation for storage activity. Absent these changes, total volumes delivered to market reflected a small decrease of 8 Bcf from 1993 due primarily to slightly warmer weather.
Market area transportation decreased 13.1 Bcf from 1992 to 1993 due primarily to the one-time arrangement in 1992 in which customers used transportation to repay certain gas Columbia Transmission delivered to them during the 1990-1991 winter. This was partially offset by a throughput improvement resulting from customers using storage transportation services to deliver gas withdrawn from storage in 1993.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Columbia Gulf's mainline transportation service in 1994 increased 10.4 Bcf over 1993 and 5.6 Bcf between 1992 and 1993. This increase primarily reflected additional transportation services for customers to move gas to Columbia Transmission's storage and to meet their supply requirements.
In 1994, short-haul transportation, which is primarily used by marketers and customers for delivery of spot market gas, decreased from 1993 by 29.2 Bcf while 1993 was essentially unchanged from the prior year.
With the implementation of Order 636 on November 1, 1993, sales volumes were virtually eliminated, except for small volume customers. The 1994 decrease from the prior year was largely offset by increased transportation services as virtually all former sales customers converted their pre-Order 636 sales requirements to firm transportation services.
The 12.3 Bcf decrease in sales between 1992 and 1993 was due primarily to the implementation of Order 636, partially offset by colder weather during 1993 and the timing of prepaid gas sales.
Net Revenues Net revenues for 1994 were $872.9 million, an increase of $31.4 million over the prior year. Due to the substantial reduction of the merchant function, certain costs previously included as a cost of gas sold and transportation expense are now included in operating expense rather than net revenues. This change increased both net revenues and operating expense by $155.8 million, but had no effect on operating income. After adjusting for this reclassification, net revenues decreased $124.4 million. This decrease included the effect of a $35 million reserve established in 1994 for various customer and regulatory settlements discussed previously and a lower cost-of-service recovery level of $26.4 million reflecting Columbia Transmission's restructuring under Order 636, which required that costs related to its merchant function be eliminated from rates. Reduced net revenues attributable to the lower cost-of-service is largely offset by elimination of merchant-related costs in operating expenses. The timing of recovery of storage service transportation costs also reduced net revenues. In addition, 1993 benefited from higher revenue of $20.8 million associated with the recovery of certain gas costs in that period allowed under the terms of a 1989 customer settlement and a $21.6 million improvement for a reserve adjustment.
Net revenues in 1993 were $841.5 million, an increase of $80.1 million over 1992. Included in 1993's net revenues was the beneficial effect of several unusual items, including the recovery of prior period gas costs, a rate refund reserve adjustment and the favorable effect of colder weather in 1993.
Operating Income For 1994, operating income of $205.4 million increased $26.7 million over 1993. Operating expense decreased $151.1 million after adjusting for certain costs mentioned above. In 1994, operating expense was lower largely due to a writedown of $57.5 million in the investment in the Cove Point LNG facility as well as a $66.8 million environmental reserve addition in 1993 and lower other taxes in the current period. This improvement was tempered by an increase in depreciation expense of $6.1 million, largely due to a higher plant balance in service and new depreciation rates, and increased labor and benefits expense due in part to higher employee relocation costs.
Operating income for 1993 of $178.7 million increased $48.8 million over 1992. The combined effect of higher net revenues and a 1992 provision for gas supply costs more than offset the impact of the writedown for the investment in the Cove Point LNG facility. Additional reserves for environmental costs of $66.8 million and $65.3 million were recorded in 1993 and 1992, respectively. After adjusting for these and other unusual items, operating income would have increased $37.8 million. These improvements more than offset higher operating expenses, including increased labor and benefits costs due in part to employee severance costs.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
TRANSMISSION OPERATING HIGHLIGHTS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Distribution launched a number of marketing, regulatory, service and operational initiatives in 1994 to overcome the challenges and take advantage of opportunities that are present in the new, highly-competitive energy marketplace. They include: reengineering key business processes, enhancing market research capabilities, targeting nontraditional markets, providing cost-effective customer services, maintaining a flexible, reliable, competitive gas supply, and pursuing needed regulatory reforms.
Marketing Initiatives Both electric and gas-on-gas competition continue to threaten Distribution's traditional markets. Electric's aggressive marketing programs have made inroads into Distribution's space and water heating markets over the past several years. Deregulation within the electric industry and more open access to the electric grid is another competitive factor that could be significant, particularly in the industrial segment. There is also competition with other gas companies and with pipeline companies who seek to connect existing customers directly, bypassing Distribution.
Another challenge facing Distribution is the mature nature of its traditional residential, commercial and industrial markets. Despite a 1.6 percent net increase of 30,400 residential and commercial customers during 1994, average usage by customers in these market segments continues to trend downward due to conservation and more efficient appliances. Just to stay even, Distribution must add three customers for every two it loses. As a result, only nominal increases in deliveries to these core markets are projected over the next few years.
To overcome these competitive challenges and improve profitability, Distribution is initiating marketing strategies based on analyses of its core residential, commercial and industrial market segments. Through these studies, Distribution will be better able to evaluate current and potential marketing programs and the profitability of each segment in relation to the resources needed to serve it, determine how to improve sales to existing customers and define customers' energy and service needs.
To ensure it is situated to effectively compete in growth areas, Distribution is planning strategic line extensions. This proactive approach is supported by Distribution's competitive rate structure and the quality, flexibility and responsiveness of its customer services.
Although approximately 60 percent of Distribution's industrial and large commercial throughput is susceptible to bypass, it has avoided any substantial inroads by pipelines into these markets through rate and capacity release strategies and the negotiation of unique customer service arrangements. As a result, estimated exposure is only 20 percent of total industrial and commercial throughput that accounts for only $10 to $15 million in annual net revenue. Efforts by the electric industry to make additional inroads into Distribution's traditional residential and commercial markets are being countered through aggressive marketing plans and innovative financing programs that encourage customers to choose natural gas fueled replacement appliances. Since 1987, approximately 1.5 Bcf, less than one percent of Distribution's annual residential load, was lost to electric add-on heat pumps and electric water heaters. Distribution plans to reverse this trend by aggressively marketing and promoting new technologies such as the new "Triathlon" gas heat pump, the first commercial natural gas fueled year-round climate control system. While net volume gains may not be significant, existing volumes will be retained.
To enhance opportunities for future growth, Distribution is targeting several nontraditional markets, including natural gas vehicles (NGVs), cooling and electric power generation. These offer significant growth opportunities but each will require time to develop.
In 1994, Distribution initiated a five year, $38 million program that will help provide the infrastructure needed to encourage the purchase and use of NGVs. It will establish up to 160 publicly accessible natural gas fueling stations throughout its service territory. A total of 20 new fueling stations were completed in 1994, and an additional 75 fueling stations are planned in 1995. During the five-year period, Distribution expects to increase the number of NGVs in its own fleet from 600 to 2,000.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The Clean Air Act Amendments of 1990 (CAA-90), which require many electric power generating facilities to reduce emissions by installing expensive exhaust scrubbers or using cleaner burning fuels, is creating new marketing opportunities for natural gas, the cleanest burning of all hydrocarbons. Distribution now serves 15 large generating plants that use 25 to 30 Bcf a year, including a facility in Virginia that was added in 1994. Additional growth in this market is expected toward the end of the decade when Phase II of CAA-90, which contains more stringent standards, is implemented. Distribution anticipates current deliveries for power generation could double by the year 2000.
Distribution is also promoting the use of new, environmentally friendly and cost-efficient natural gas cooling equipment by commercial and industrial customers. It currently serves only about two percent of this market. In 1994, new sales of gas cooling equipment in Distribution's territory totaled 3,000 refrigerant tons and added 54 million cubic feet of annual gas load. The new "Triathlon" heat pump is also expected to increase residential use of natural gas for cooling.
Capital Expenditures In addition to maintaining and upgrading facilities to assure safe, reliable and efficient operation, Distribution's 1994 capital expenditure program of $151 million (an increase of $33 million over 1993) was directed at extending service to new areas and developing future markets including NGVs and power generation.
The 1995 capital expenditure program amounts to approximately $158 million, including $56 million for new business development and $69 million for replacement and betterment projects.
Gas Supply In 1994, for the first time in its history, Distribution purchased all of its natural gas supply directly from producers and marketers and contracted for capacity on several different pipelines to transport this gas from various producing areas to its customers. Its contracts for gas supply not only consider the lowest price, but also the reliability, flexibility and performance capabilities of the suppliers and the pipelines involved.
To meet its customers' needs during the heating season, Distribution's gas supply portfolio consists of storage services (50 percent), firm capacity on interstate pipelines (48 percent) and peaking service for the coldest winter days (2 percent). This favorable mix of storage and transportation permits high annual utilization of Distribution's firm transportation capacity.
FERC Order 636 allows Distribution and other pipeline capacity holders to release unneeded capacity to third parties. During 1994, Distribution released about 190 Bcf in pipeline capacity resulting in revenues of approximately $10.5 million to reduce costs to firm customers. In return for the risks associated with aggressively managing the release of capacity and thereby reducing customer costs, Distribution is proposing capacity release incentive plans in some states that would permit retention of a portion of the resulting revenues.
Reengineering A reengineering program addressing corporate center support activities evaluated various key processes and streamlined the organizational structure to improve operating efficiencies. Accordingly, a liability and associated expense of approximately $2.5 million were recorded in third quarter 1993 for projected severance costs to compensate employees whose positions were eliminated in 1994 or are scheduled for elimination in 1995. The liability as of December 31, 1994 is approximately $2 million.
In 1994, Distribution began implementation of a comprehensive initiative termed "Project Customer" to reshape, streamline and enhance field processes involved in delivering customer service. As a result of consolidating certain functions and implementating new practices, Distribution recorded a liability of $5.1 million and associated expense of approximately $4.1 million in December 1994 representing salary and related severance benefit costs for 240 employees. Commonwealth Gas Services, Inc. (Commonwealth Services) recorded approximately $1 million as a regulatory asset pending recovery in a future general rate case. The actual termination of employees and related cash payments are expected to begin in the second quarter of 1995 and continue over several years. As further improvement measures are identified, additional reserves will be required.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Regulatory Matters Regulatory activity in Distribution's operating jurisdictions during 1994 resulted in a series of unprecedented settlements. These arrangements provided over $70 million in annual revenue increases, recovery of postretirement benefits in all states and significant regulatory reform initiatives, including pilot weather normalization adjustments in Ohio and Kentucky, and a gas supply management incentive mechanism in Pennsylvania.
In Ohio, the Public Utilities Commission approved a settlement agreement that resolved a number of service and rate incentive issues and provided for an annual revenue increase of $47.5 million, effective November 1994. This comprehensive settlement was developed through a unique collaborative effort by key stakeholders who reached an agreement for an increase in rates prior to formal rate proceedings. The agreement provided for recovery of operating costs based on a partially projected period, a possible revenue adjustment effective in May 1996, and a recovery mechanism for Order 636 transition costs. Under the agreement, Columbia Gas of Ohio, Inc. (Columbia of Ohio) is not permitted to file a general rate case that would become effective prior to January 1998. Additionally, the settlement included a one-year experimental weather normalization adjustment to alleviate the impact of unusual weather on customers' bills and Columbia of Ohio's revenues. This provision required a $6.6 million reserve to be recorded in the second quarter of 1994 for a customer refund of revenues resulting from unusually cold weather in early 1994. As a result of recent customer concerns with this program, Columbia of Ohio agreed to several modifications in February 1995. The modifications include an agreement between parties to continue the program through the trial period to appropriately evaluate potential benefits of the program but to discontinue any further upward adjustment to customer bills associated with the program.
In Pennsylvania, the Public Utility Commission approved a settlement agreement that increased annual revenues by $16.6 million, effective August 1, 1994. To mitigate regulatory lag, operating costs were projected through September 1994, and rates went into effect three months earlier than they would have had the case been fully litigated. The commission order approved, with modifications, Columbia Gas of Pennsylvania, Inc.'s (Columbia of Pennsylvania) annual gas cost recovery filing and an incentive program for gas supply management. Subsequently, the Pennsylvania Office of Consumer Advocate (OCA) challenged the legality of the commission's adoption of a gas supply management incentive mechanism. The commission granted the OCA's request for reconsideration of the issue but has not ruled on the merits of the request.
In Kentucky, the Public Service Commission approved Columbia Gas of Kentucky, Inc.'s (Columbia of Kentucky) comprehensive settlement that provides for a $9.75 million increase in annualized revenues in three steps: $6 million in November 1994, $2.25 million in October 1995, and $1.5 million in October 1996. The settlement precludes Columbia of Kentucky from filing a new rate case for three years but provides for a weather normalization adjustment over this same period.
In Virginia, Commonwealth Services received approval from the State Corporation Commission of the 1993 regulatory settlement that provided for a $3.5 million increase in annual revenue, effective in mid-1993.
In Maryland, Columbia Gas of Maryland, Inc. (Columbia of Maryland) implemented the second phase of a two-step increase in rates, effective March 1, 1994, as provided in its 1993 general rate settlement. The $600,000 increase covered the costs of constructing, operating and maintaining a propane peak-shaving plant in Hagerstown, Maryland. The Public Service Commission (PSC) recently approved a settlement of Columbia of Maryland's expedited rate case that was filed in mid-1994. The new rate levels that became effective November 1, 1994 are designed to generate an additional $800,000 in annual revenue.
In 1995, rate case filings are tentatively scheduled in Maryland, Virginia and Pennsylvania seeking increased annual revenues totalling approximately $30 million. The majority of these revenues will not be realized until 1996.
There is ongoing interest in extending unbundled service, or open transportation, to residential/human needs customers. The staff of the Maryland PSC has recommended that utilities be required to offer a full range of unbundled services by 1996, and the PSC has requested that utilities respond to the staff's recommendation. In Ohio, Columbia of Ohio
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
will work with the Collaborative to study the feasibility of residential transportation and performance-based rate incentives. Through regulatory, political and other forums, Distribution will continue to actively participate in shaping the definition of the LDC's merchant role in the evolving energy market.
Full recovery of Distribution's accrued costs for other postretirement benefits has been approved in all of its five states. In addition, Columbia of Ohio and Columbia of Kentucky are permitted to recover the transition obligation over 18 years, Columbia of Pennsylvania over 18 years and five months, Columbia of Maryland over 20 years, and Commonwealth Services over 40 years. Columbia of Kentucky, as part of a comprehensive rate settlement, absorbed the 1993 incremental other postretirement benefit costs that had been previously deferred. Accordingly, a pre-tax charge of approximately $875,500 was recorded in the fourth quarter of 1994.
Although Columbia of Pennsylvania has been authorized to recover its other postretirement benefit costs, recent intermediate appellate court rulings involving two other Pennsylvania utilities could impact the future recoverability of these costs. Both cases may be appealed to the Pennsylvania Supreme Court. Depending upon the final disposition of the cases, Columbia of Pennsylvania's recovery of these incremental other postretirement benefit costs might be subject to question. It is management's opinion, however, that Columbia of Pennsylvania will be allowed continued recovery of other postretirement benefit costs on an accrual basis including the transition obligation.
Environmental Matters During 1994, Distribution made significant progress in implementing its comprehensive environmental program, which is designed to ensure compliance with all state and federal environmental requirements.
During the year, Distribution continued its inventory of sites as well as a review of current procedures. The initial inventory and assessment process is expected to continue over the next two years, after which Distribution expects to implement an ongoing site assessment process designed to monitor continuing compliance.
Distribution's environmental emphasis continues to focus on former manufactured gas plant sites. Thirteen such sites have been identified, and environmental investigations are being conducted at five of these sites where remedial action may be required. Investigations will be conducted at the other sites in the future. To the extent site investigations have been completed, remediation plans developed, and any Distribution responsibility for remedial action established, the appropriate liability has been recorded. As additional investigations are completed and remediation costs can be determined, the appropriate liabilities will be recorded. Distribution also recorded corresponding regulatory assets in anticipation of the recovery of remediation costs through normal rate proceedings. As of December 31, 1994, Distribution's recorded net liability was $5.6 million.
Integrated Resource Planning The 1992 Federal Energy Policy Act required that state utility commissions consider the benefits of adopting the Act's integrated resource planning (IRP) and demand-side management (DSM) provisions for natural gas by October 1994. Generally speaking, the state regulatory commissions in Distribution's market area concluded that the additional federal regulations were unwarranted and that existing state rules and regulations are sufficient to allow LDCs a flexible approach to resource planning and the pursuit of cost-effective DSM programs.
Electric DSM programs continue to be a significant concern to Distribution. While most electric DSM programs are proceeding on a pilot basis, there is a large potential competitive impact if these ratepayer-funded marketing programs continue and expand on a large-scale basis. Distribution is developing and implementing cost-effective DSM programs on a selected basis that should enable it to continue to effectively compete for new load and replacement appliances and equipment to improve system load factors and operating economics. However, because the DSM economic justification of capacity avoidance generally supports higher incentives for certain electric end-use equipment, competitive concerns remain.
Distribution continues to encourage state regulators to deal with utility IRP programs on a comprehensive basis. It believes that under such an approach, commissions are more likely to recognize the many significant resource
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
efficiency and environmental advantages of using natural gas rather than electricity for most residential and commercial and many industrial end uses. Most commissions, however, have been reluctant to deal with the relative environmental and resource conservation impacts of using natural gas versus coal, oil or nuclear generated electric power for residential and commercial end uses because of the complexity and political sensitivity of the issue in states with major coal production.
Volumes Throughput of 513 Bcf for 1994 reflects an increase of 3.2 Bcf over 1993. Transportation deliveries were 15 Bcf higher due largely to increased industrial demand in Ohio, Virginia and Kentucky as well as industrial customers shifting from tariff sales to transportation services in order to reduce their overall energy costs. The transportation improvement was tempered by a sales decline of 11.8 Bcf that included the effect of nearly 3 percent warmer weather. Also reducing sales was lower customer usage due to conservation measures and more efficient appliances.
Distribution's 1993 throughput of 509.8 Bcf reflected a 23.1 Bcf increase over 1992. Transportation deliveries were 13.8 Bcf higher due largely to increased usage by power generating facilities while the sales increase of 9.3 Bcf reflected colder weather in 1993 and additional customers being served.
Net Revenues The beneficial impact from new rates put into effect during 1994, resulting from recent regulatory settlements, and increased transportation deliveries were the principal reasons for higher net revenues of $735.9 million, up $9.9 million over last year. Partially offsetting these improvements was a $21.4 million effect for reduced sales volumes. Revenues would have been reduced by an additional $5 million had it not been for the pilot weather normalization adjustment that is allowed in some of Distribution's service areas. Columbia of Ohio's payment plan for low income customers, which was suspended for much of 1994, resulted in a $6.6 million reduction in both revenues and operating expenses; and therefore, had no effect on operating income.
Net revenues of $726 million for 1993 were $29.5 million higher then the prior year. Higher throughput and new rates in effect during 1993 represented the largest portion of this increase.
Operating Income Operating income for 1994 of $128.3 million, decreased $18.1 million from 1993, due to $28.0 million of higher operating expenses that were only partially offset by improved net revenues. Other taxes increased $12.2 million due principally to higher gross receipts and property taxes while the $2.2 million increase in depreciation expense primarily reflected plant additions. The increase in operation and maintenance expense of $13.6 million included higher labor and benefits expense as well as the effect of employee severance accruals associated with implementing productivity and customer service initiatives. Reducing the effect of these higher expenses was the $6.6 million of lower expense for the customer low income payment plan. Also tempering the effect of higher operating expenses was a unique regulatory arrangement that permits Columbia of Ohio to capitalize certain interest charges that improved net income but not operating income. (The beneficial effect of this issue is eliminated on the consolidated financial statements because the Corporation, while in Chapter 11, is not recording interest expense.)
The effect of $29.5 million higher net revenues for 1993 compared to 1992, was partially offset by increased operating expenses of $20.8 million, which resulted in improved operating income of $8.7 million. Higher operation and maintenance expense was due primarily to changes attributable to implementing Order 636 as well as higher other expenses resulting from the initial costs incurred from the streamlining of the corporate service function. Plant additions led to higher depreciation expense while increased gross receipts taxes and property taxes were due to higher taxable revenues and plant additions.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
* Includes Columbia Gas of New York, Inc. through March 31, 1991. ** Reflects volumes under purchase contracts of less than one year.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
Lower energy prices, particularly in the second half of 1994, adversely impacted operations of the oil and gas segment. Overall, natural gas prices averaged $2.18 per Mcf in 1994 compared to $2.28 in 1993. Oil prices also declined, averaging $15.09 per barrel in 1994 as compared to $16.17 per barrel in 1993. If the depressed level of natural gas prices experienced early in 1995 continues, a writedown of the oil and gas properties may be required for the first quarter of 1995.
Fluctuations in oil and gas prices can cause significant variations in revenues for the oil and gas segment. To dampen the impact of these price swings and help stabilize revenues, the oil and gas segment uses options contracts and price swap agreements to lessen the price risk for a portion of its production.
Capital Expenditures The 1994 capital expenditures program increased to $102 million from the $95 million level in 1993. While a large portion of these expenditures is for development drilling and the installation of an offshore production platform in the Gulf of Mexico, expenditures for the exploration program in the Southwest increased approximately $9 million. In 1995, the capital expenditure program of $118 million will continue to focus on development drilling while maintaining a significant level of expenditures for exploration.
Columbia Gas Development Corporation (Columbia Development) drilled 64 gross (32 net) wells in 1994, with an 86 percent success rate. Of these, 39 were drilled in the Austin Chalk located in Texas, all of which were successful. Productivity and economics in the Austin Chalk were enhanced by continued emphasis on drilling multiple horizontal laterals from a single vertical well bore. This type of well increases production and reduces the overall cost per lateral, since more productive reservoirs can be accessed and the costs of the vertical portion of each well are shared by more than one lateral.
Horizontal wells drilled in the Austin Chalk formation in 1994 tested at daily rates ranging from 250 to 1,750 barrels of oil with up to 3.5 million cubic feet of associated gas. Columbia Development holds varying interests in these wells.
Columbia Development participated in nine wells drilled offshore in the Gulf of Mexico during 1994. It has a 100 percent working interest in two of these wells, each of which tested at rates in excess of 6 million cubic feet of gas per day. Columbia Development has varying working interests in the remaining wells.
In the Appalachian area, Columbia Natural Resources, Inc. (CNR), completed 121 gross (69 net) development wells in 1994, with a success rate of 83 percent. Approximately 44 percent of these wells were in the Rose Run formation in southeast Ohio, with a success rate of 65 percent which is more than double the industry average. Favorable reservoir characteristics allow Rose Run prospects to quickly generate a return on invested capital. CNR's 1995 development program has been increased to a level sufficient to commence drilling on previously identified Rose Run prospects.
Gathering Facilities Under Order 636, the natural gas pipeline industry is required to eventually unbundle gathering services from other transportation services. Columbia Transmission provides transportation services, including gathering services, for a significant portion of gas produced by CNR. If there is a significant increase in gathering rates as a result of unbundling, certain reserves could be uneconomical to produce which could have a material adverse effect on CNR's operating strategies and financial results beginning in 1996. The extent of any potential asset impairment or increase in operating costs cannot be quantified at this time.
Reserves Net proved gas reserves at the end of 1994 totalled 684 Bcf, compared to 697 Bcf at the end of 1993. The decline in gas prices and a slight increase in lifting costs are primarily responsible for a 36 Bcf downward revision in
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
recoverable gas reserves in the Appalachian area. Without this reduction, newly discovered Appalachian reserves and extensions of 54 Bcf exceeded production by approximately 21 Bcf. In the Southwest new discoveries and extensions of 31 Bcf and an upward revision of 5 Bcf in recoverable gas reserves exceeded production during 1994 by approximately 2 Bcf.
Proved reserves for oil, condensate and natural gas liquids decreased slightly from 12.8 million barrels at the end of 1993 to 12.3 million barrels for 1994 as production of 3.6 million barrels was largely replaced through extensions and discoveries of 1.4 million barrels and net upward reserves revisions of 1.6 million barrels.
Royalty Dispute Columbia Development resolved a royalty dispute with the U.S. Minerals Management Service (MMS) in 1994 for which a $5.4 million reserve had been established. Under the terms of a settlement, Columbia Development agreed to remit approximately $500,000 in additional royalties and interest to the MMS and the remainder of the reserve was reversed.
Volumes Gas production decreased 6.7 percent in 1994 to 66.7 Bcf as production declined in both the Southwest and Appalachian areas. The decrease in Southwest production was due to normal production declines, production problems on an offshore well and wells shut-in due to workovers. In the Appalachian area, the decline was attributable to normal declines from older wells combined with production curtailments resulting from replacement and repair of Columbia Transmission's lines and compressor facilities. In 1993, gas production increased 3 percent to 71.5 Bcf over 1992, largely due to new Southwest offshore production and new onshore production in Texas, south Louisiana and New Mexico.
Oil and liquids production in 1994 of approximately 3.6 million barrels was essentially unchanged from 1993. An increase in Appalachian oil production due to the increased activity in the eastern Ohio area was offset by a decrease in natural gas liquids produced in the Southwest program due to the above-mentioned offshore well experiencing production problems. In 1993, oil and liquids production increased nearly 18 percent due to the success of the Southwest program.
Operating Revenues In 1994, operating revenues were $205.3 million, a decline of $16.9 million or 8 percent from 1993. The impact of lower oil and gas prices and the decrease in gas production was only partially offset by the combined effect of recording of a reserve of $5.4 million in 1993 for a royalty dispute and the subsequent reversal of most of this reserve in 1994. Lower energy prices and gas production in 1994 more than offset a $7.5 million improvement from hedging results compared to 1993.
In 1993, higher gas prices along with increased oil and gas production resulted in operating revenues of $222.2 million, a 12 percent increase over 1992.
Operating Income (Loss) Operating income for 1994 declined by $23 million to $30.6 million due to the lower operating revenues and an increase in depletion expense of $12.4 million as a result of the depressed energy prices.
Operating income was $53.6 million in 1993 compared to an operating loss of $101.2 million in 1992. The 1992 operating loss was due to a $126.4 million writedown in the carrying value of oil and gas properties. The improvement in operating income in 1993 also reflected higher operating revenues and lower depletion expense.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
STATEMENTS OF OPERATING INCOME FROM OIL AND GAS OPERATIONS (UNAUDITED)
OIL AND GAS OPERATING HIGHLIGHTS*
* Years 1991 and 1990 include results from Canadian operations that were sold effective December 31, 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
OTHER ENERGY OPERATIONS
Market Center
In October 1994, the Corporation opened a natural gas market center in Pittsburgh, Pennsylvania. Managed by Columbia Energy Services Corporation (CES), the market center offers a variety of natural gas supply services for third parties as well as the Corporation's distribution and transmission subsidiaries. These services respond to the changing needs of local utilities, industrial consumers and others managing gas supply in the new environment generated by Order 636.
In order to offer an additional energy service to its customers, the Corporation intends to seek the necessary regulatory approvals in 1995 to market electric power. This would allow the purchase of electric power from electric utilities and cogeneration facilities which would then be sold to other electric utilities as well as other customers.
Propane During 1994, propane sales by Columbia Propane Corporation and Commonwealth Propane, Inc., totaled 68.5 million gallons, an increase of 18 percent from the previous year. The propane companies serve approximately 68,200 customers in parts of Kentucky, Maryland, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. The companies are focusing their sales efforts on the higher-margin residential segment.
Cogeneration The Corporation is involved in several cogeneration projects through TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary. With the opening of a 47-megawatt cogeneration facility in June 1994 in Vineland, New Jersey, TriStar now holds various interests in four operating facilities with a total capacity of nearly 300 megawatts. TriStar and its partners have other projects in various stages of development. Value for the Corporation is also created from the projects by increased throughput for the transmission subsidiaries and for the oil and gas segment through additional sales opportunities.
Cove Point Facility A partnership between Columbia LNG Corporation (Columbia LNG) and a wholly-owned subsidiary of Potomac Electric Power Company was formed in October 1993. The partnership is pursuing a business plan to offer a peaking service and to reactivate the Cove Point Terminal. On November 3, 1993, the partnership filed an application with FERC to acquire all of the existing plant and pipeline facilities owned by Columbia LNG, for authorization to recommission the plant and construct liquefaction facilities and to charge customers based upon negotiated market rates for the services.
By orders issued July 27, 1994, and September 28, 1994, the FERC determined that the proposed peaking operation is in the public interest; however, the proposal to charge customers market based rates was denied. The September 28, 1994 order, which directed the partnership to use cost of service based rates, also contained certain rate base determinations which allowed only a portion of Columbia LNG's current rate base to be used in the calculation of the cost based rates. On December 5, 1994, the partnership's request for reconsideration of the rate base issues was denied by the FERC.
On December 12, 1994, the FERC certificate to recommission the facility and offer a peaking service was accepted by the partnership, and the Cove Point Terminal and pipeline facilities were contributed by Columbia LNG to the partnership as its initial capital contribution. It is anticipated that the peaking service will be operational in the fall of 1995.
Derivatives The Corporation's other energy operations minimize the risk of market fluctuations by using commodity futures from time to time to hedge prices on propane inventories and commitments for natural gas purchases and sales. These agreements are not used for purposes of speculation.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
CES uses commodity futures contracts to assure acceptable margins on the purchase and resale of natural gas when it makes commitments for the purchase or sale of natural gas in future months. When CES makes a sale for future delivery without having natural gas committed to that sale, it purchases commodity futures to reduce the risk of increasing prices prior to purchasing the natural gas to fulfill the sales obligation.
Commonwealth Propane, Inc. (CPI) purchases propane and places it in inventory for future sale. CPI sells commodity futures on a portion of its inventory at the time of purchase to protect it from decreasing prices and to assure an acceptable margin.
Environmental Matters The Columbia Gas System Service Corporation (Service Corporation) received a "General Notice of Potential Liability and Section 104(2) Request for Information" from the EPA concerning a process site to which the Service Corporation sent certain solvents. Service Corporation has joined a group for the purpose of sharing the costs of the clean-up. Management does not believe this Superfund matter will have a material adverse effect on future income or on the Corporation's financial position.
Net Revenues An increase in demand for services in the new environment generated by Order 636 resulted in $3.8 million higher net revenues for gas marketing activities in 1994 and an increase of $1.7 million for 1993 over the year earlier. The cold weather in the first quarter of 1994, which resulted in higher sales volumes and margins, was primarily responsible for the $3 million increase in 1994 net revenues from propane operations. In 1993, these revenues increased $0.8 million due to increased sales to higher-margin residential customers.
Other revenues decreased $3.8 million in 1994 as the Corporation's reengineering program resulted in a decline in revenues for professional services provided to affiliated companies. In 1993, other revenues increased $3.1 million from the prior year to $73.4 million as revenues from affiliated companies and coal royalties increased.
Operating Income The $15.8 million increase in operating income in 1994 is primarily due to the $12.8 million decrease in operating expenses reflecting the impact of the reserve recorded in 1993 for employee severance costs and the related efficiencies achieved in 1994. The 1993 operating income decline of $5.1 million was primarily due to the recording of the severance reserve.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM OTHER ENERGY OPERATIONS (UNAUDITED)
OTHER ENERGY OPERATING HIGHLIGHTS
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
COMPARATIVE GAS OPERATIONS DATA The Columbia Gas System, Inc. and Subsidiaries
*Certain amounts in prior periods have been reclassified to conform with the current presentation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of The Columbia Gas System, Inc.:
We have audited the accompanying consolidated balance sheets of The Columbia Gas System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries as of December 31, 1994 and 1993, 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, 1994. 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 generally accepted auditing standards. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
On July 31, 1991, the Corporation and Columbia Gas Transmission Corporation ("Columbia Transmission"), a wholly-owned subsidiary, filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. Note 2 discusses, among other matters, uncertainties associated with the Chapter 11 proceedings, including the status of the Corporation's loans to Columbia Transmission, certain prepetition intercompany asset transfers and the measurement of certain liabilities. This note also discusses purported class action and other complaints which have been filed against the Corporation generally alleging violations of certain securities laws. The accompanying financial statements do not reflect any liability associated with these complaints as the Corporation believes it has meritorious defenses to these actions; however, the ultimate outcome is uncertain. As a result of these matters, the Corporation may take, or be required to take, actions which may cause assets to be realized or liabilities to be liquidated for amounts other than those reflected in the financial statements. These factors create substantial doubt about the Corporation's ability to continue as a going concern. The accompanying financial statements have been prepared assuming that the Corporation and Columbia Transmission will continue as going concerns which contemplate the realization of assets and payment of liabilities in the ordinary course of business. The appropriateness of the Corporation continuing to present financial statements on a going concern basis is dependent upon, among other items, the terms of the ultimate plan of reorganization and the ability to generate sufficient cash from operations and financing sources to meet obligations.
As discussed in Note 5, effective January 1, 1994, the Corporation changed its method of accounting for postemployment benefits pursuant to standards promulgated by the Financial Accounting Standards Board.
The schedule listed in the Index to Item 8, Financial Statements and Supplementary Data, is the responsibility of the Corporation's management and 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 February 9, 1995
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME The Columbia Gas System, Inc. and Subsidiaries
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements.
**Due to the bankruptcy filings, estimated interest expense of approximately $222 million, $207 million and $203 million has not been recorded for 1994, 1993 and 1992, respectively (see Note 2E of Notes to Consolidated Financial Statements).
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS The Columbia Gas System, Inc. and Subsidiaries
* Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements.
** The Corporation has 10,000,000 shares of preferred stock, $50 par value, authorized but unissued.
*** Due to the bankruptcy filings, estimated accrued interest of approximately $716 million and $494 million has not been recorded as of December 31, 1994 and December 31, 1993, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS The Columbia Gas System, Inc. and Subsidiaries
* Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements.
** Includes amounts transferred from cash paid to employees and for other employee benefits and other operating cash payments.
*** The Corporation considers all highly liquid debt instruments to be cash equivalents.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY The Columbia Gas System, Inc. and Subsidiaries
*100 million shares authorized at December 31, 1994, 1993 and 1992 - $10 par value.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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 Corporation and all subsidiaries. All intercompany accounts and transactions have been eliminated, except for the Corporation's investment in Columbia LNG Corporation which was presented as a one line equity investment in 1993(see Note 11E).
On July 31, 1991, the Corporation and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. The debtor companies are operating their businesses as debtors-in-possession (DIP) under the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). As such, the debtor companies cannot engage in transactions outside the ordinary course of business without obtaining Bankruptcy Court approval (see Note 2).
The accompanying financial statements reflect all adjustments necessary in the opinion of management to present fairly the results of operations in accordance with generally accepted accounting principles applicable to a going concern. Such presentation contemplates the realization of assets and payment of liabilities in the ordinary course of business. As a result of the reorganization proceedings under Chapter 11, the debtor companies may take, or be required to take, actions which may cause assets to be realized, or liabilities to be liquidated, for amounts other than those reflected in the financial statements. The appropriateness of continuing to present consolidated financial statemetns on a going concern basis is dependent upon, among other things, the terms of the plan of reorganization, future profitable operations and the ability to generate sufficient cash from operations and financing sources to meet obligations. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or the amounts and classification of liabilities that might be necessary as a result of the outcome of the uncertainties discussed herein.
Certain reclassifications have been made to the 1993 and 1992 financial statements to conform to the 1994 presentation.
B. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," 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 reasonable to assume that such rates can be charged and collected. The Corporation's interstate transmission companies and Columbia LNG Corporation (Columbia LNG) did not meet these criteria, and consequently are not applying the provisions of SFAS No. 71. The Corporation's gas distribution subsidiaries continue to 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. Condensed information for assets and liabilities subject to utility regulation and rate determination are as follows:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
C. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant and equipment (principally utility plant) are stated at original cost. The cost of gas utility and other plant of the distribution companies includes an allowance for funds used during construction (AFUDC).
In addition, Columbia Gas of Ohio, Inc. is permitted to include in its plant investment post-in-service carrying charges on those eligible plant investments which are placed in service between December 31, 1990, and December 31, 1994. Columbia Gas of Ohio, Inc., is currently recovering plant investment post-in-service carrying charges for 1991, 1992 and 1993 in rates. Subject to commission approval, the carrying charges are also authorized to be included in base rates in subsequent rate filings. These carrying charges are subject to a net income limitation, as determined by the commission. Property, plant and equipment of other subsidiaries includes interest during construction (IDC).
The 1994, 1993 and 1992 before-tax rates for AFUDC and IDC were 8.0 percent and 9.6 percent, respectively. They represent the rates in effect prior to Chapter 11 filings. The portion of interest capitalized by subsidiaries during the period the Corporation is in bankruptcy is eliminated in the consolidated financial statements.
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. The Corporation's subsidiaries provide for annual depreciation on a composite straight-line basis.
The average annual depreciation rate for Transmission property was 2.7 percent in 1994 and 2.6 percent in 1993 and 1992. The average annual depreciation rate for Distribution property was 3.3 percent in 1994, 1993 and 1992.
D. OIL AND GAS PRODUCING PROPERTIES. The Corporation's subsidiaries engaged in exploring for and developing oil and gas 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 in a countrywide cost center. If costs exceed the sum of the estimated present value of the cost center's net future oil and gas 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 oil and gas properties are normally recorded as adjustments to capitalized costs.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Depletion for subsidiaries is based upon the ratio of current-year revenues to expected total revenues, utilizing current prices, over the life of production.
E. COMMODITY HEDGING. Premiums paid for option and swap agreements are included as current assets in the consolidated balance sheet until they are exercised or expire as unexercised. Margin requirements for natural gas, crude oil and propane futures are also recorded as current assets. Unrealized gains and losses on all futures contracts are deferred on the consolidated balance sheet as either current assets or other deferred credits. Realized gains and losses from the settlement of natural gas and crude oil futures, options and swaps are included in revenues or products purchased. Realized gains and losses from the settlement of propane futures contracts are included in products purchased.
F. GAS INVENTORY. Gas inventory is carried at cost on a last-in, first-out (LIFO) basis. The current replacement cost of gas inventory at December 31, 1994, was approximately $212 million for the distribution companies. Liquidation of LIFO layers related to gas delivered by the distribution companies does not affect income since the effect is passed through to customers as part of purchased gas adjustment tariffs.
G. INCOME TAXES AND INVESTMENT TAX CREDITS. The Corporation 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 gas distribution subsidiaries were deferred and are being amortized over the life of the related properties to conform with regulatory policy.
H. 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.
I. DEFERRED GAS PURCHASE COSTS. The Corporation'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.
J. REVENUE RECOGNITION. The Corporation's gas distribution subsidiaries bill customers on a monthly cycle billing basis. Revenues are recorded on the accrual basis including an estimate for gas delivered but unbilled at the end of each accounting period. Columbia Transmission also records the impact on revenues of the future recovery or refund of differences between current transportation costs and amounts currently included in the billed rates. In addition, Columbia Transmission and Columbia Gulf record the effect on revenues to reflect the recovery or refund of differences between current fuel usage and amounts retained.
2. REORGANIZATION PROCEEDINGS UNDER CHAPTER 11 OF THE BANKRUPTCY CODE
A. GENERAL. Under the Bankruptcy Code, actions by creditors to collect prepetition indebtedness are stayed and other contractual obligations may not be enforced against either the Corporation or Columbia Transmission. As debtors-in-possession, both the Corporation and Columbia Transmission have the right, subject to Bankruptcy Court approval and certain other limitations, to assume or reject executory contracts and unexpired leases. In this context, "rejection" means that the debtor companies are relieved of their obligations to perform further under the contract or lease but are subject to a claim for damages for the breach thereof. Any claims for damages resulting from rejection are treated as general unsecured claims in the reorganization. The parties affected by these rejections may file claims with the Bankruptcy Court
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
in accordance with bankruptcy procedures. Prepetition claims which were contingent or unliquidated at the commencement of the Chapter 11 proceeding are generally allowable against the debtor-in-possession in amounts fixed by the Bankruptcy Court. Substantially all liabilities as of the petition date are subject to resolution under plans of reorganization to be approved by the Bankruptcy Court after submission to any required vote by affected parties. The Corporation's reorganization plan will also require approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935.
B. PREPETITION OBLIGATIONS. Columbia Transmission's prepetition obligations include secured and unsecured debt payable to the Corporation, estimated supplier obligations, estimated rate refunds, accrued taxes and other trade payables and liabilities. Prepetition obligations of the Corporation primarily represent debentures, bank loans and commercial paper outstanding on the filing date together with accrued interest to that date. A substantial amount of Columbia Transmission's liabilities subject to Chapter 11 proceedings relate to amounts owed to the Corporation. Columbia Transmission's borrowings have been funded by the Corporation on a secured basis since June 1985 and are secured by mortgages and a cash collateral order approved by the Bankruptcy Court. On the petition date, the principal amount of the First Mortgage Bonds outstanding was $930.4 million. A secured inventory financing agreement of $410 million was also outstanding on the petition date. Prepetition and postpetition interest on secured debt owed by Columbia Transmission to the Corporation is $488.3 million at December 31, 1994. In addition to these secured claims, the Corporation has an unsecured claim against Columbia Transmission of $351 million in installment notes issued prior to 1985 and accrued interest to the petition date.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The accompanying Consolidated Balance Sheets include approximately $4 billion of liabilities subject to the Chapter 11 proceedings of the Corporation and Columbia Transmission as follows:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
INTERCOMPANY COMPLAINT On March 19, 1992, the Official Committee of Unsecured Creditors of Columbia Transmission (Columbia Transmission Creditors' Committee) filed a complaint (Intercompany Complaint) with the Bankruptcy Court alleging that the $1.7 billion of Columbia Transmission's secured and unsecured debt securities held by the Corporation should be recharacterized as capital contributions (rather than loans) and equitably subordinated to the claims of Columbia Transmission's other creditors. The Intercompany Complaint also challenges interest and dividend payments made by Columbia Transmission to the Corporation of approximately $500 million for the period from 1988 to the petition date and the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an alleged fraudulent transfer. Based on the SEC standardized measurement procedures, CNR's properties had a reserve value of approximately $250 million as of December 31, 1994, a significant portion of which is attributable to the transfer from Columbia Transmission. At the Bankruptcy Court's request, the trial proceedings for the Intercompany Complaint were transferred to the U. S. District Court for the District of Delaware (the District Court). On September 12, 1994, the trial for the Intercompany Complaint began in the District Court and concluded on October 25, 1994. Post trial briefs were filed in December 1994, and the District Court is expected to render a decision in the first quarter of 1995. Management believes that the Intercompany Complaint is without merit; however, the ultimate outcome of these issues is uncertain at this stage of the proceedings.
Little progress has been made with Columbia Transmission's creditors in an attempt to establish the value of the estate and to resolve the matters raised in the Intercompany Complaint. Since the validity of the Corporation's debt investment in Columbia Transmission is crucial to the determination of the value of the Corporation's estate, the Corporation's reorganization could be affected by the ultimate outcome of the Intercompany Complaint.
PRODUCER CLAIMS ESTIMATION PROCESS Columbia Transmission has recorded liabilities of approximately $1.3 billion to reflect the estimated effects of rejecting its above- market producer contracts and estimated producer obligations associated with pricing disputes and take-or-pay obligations for historical periods. With Bankruptcy Court approval, Columbia Transmission rejected more than 4,800 above-market gas purchase contracts with producers. The producers whose gas purchase contracts were rejected filed claims for damages that, after being adjusted for duplicative and other erroneous claims, are in excess of $13 billion. The Bankruptcy Court approved the appointment of a claims mediator in 1992 to implement a claims estimation procedure related to the rejected above-market producer contracts and other producer claims. On October 13, 1994, the claims mediator issued his Initial Report and Recommendation of the Claims Mediator on Generic Issues for Natural Gas Contract Claims (Report). The Report, which is subject to Bankruptcy Court review and approval, establishes the parameters within which producers must initially recalculate their contract rejection and take-or-pay claims. The recalculated claims will then be subject to challenge and audit and adjustment based upon claim specific issues. The Report generally validates the assumptions Columbia Transmission used earlier to estimate the total value of contract rejection claims filed by producers in the bankruptcy proceedings and clearly rules out most of the methods the producers utilized to derive grossly excessive, and legally improper amounts in their original claims.
While the Report uses a lower discount rate than that used by Columbia Transmission and recognizes certain proved undeveloped reserves, it directs that calculations of damages be based only on the amount by which a contract price exceeds a mitigation price and be discounted to a present value as of the petition date. Not addressed in the Report are numerous contract specific issues that ultimately will be used in the estimation procedure to determine the allowable level of producer claims. Columbia Transmission is not able to calculate individual contract rejection claims at this time because it does not have adequate data from the producers on the proved undeveloped reserves or on planned gas development projects. This data will not become available, and subject to challenge and audit, until the individual producers file their recalculations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The Report does not address an alternative method for calculating contract rejection damages sponsored by Columbia Transmission. This methodology contemplates using the market value of the producers' reserves subject to the contracts rejected by Columbia Transmission as evidence of the economic value to producers of such contracts (Market Value Methodology). The claims mediator is expected to hold a hearing on this alternative methodology in the second quarter of 1995 and has indicated that Columbia Transmission's pursuit of its Market Value Methodology will not delay his completion of the discounted cash flow methodology contained in the Report.
In management's opinion the $1.3 billion estimate previously reported represents the worst plausible case for allowed contract rejection claims, although it is anticipated that the producers' initial recalculations of these claims may exceed that total. Further, Columbia Transmission does not believe the Report produces any basis which would cause it to change the amount it previously recorded for contract rejection costs (approximately one billion dollars) given the information currently available to it. However, following the review of the Report by Columbia Transmission and its counsel, Columbia Transmission increased the $200 million reserve for take-or-pay and other miscellaneous producer claims by approximately $55 million in the third quarter of 1994. The $55 million reserve addition is composed of approximately $40 million for disallowance of recovery of recoupable take-or-pay proposed by the Report and approximately $15 million of additional prepetition interest on certain claims.
The resolution of bankruptcy related issues could significantly influence future reported financial results. Accounting standards require that as claim amounts are allowed by the Bankruptcy Court, the full amount of the allowed claim must be recorded. This could result in liabilities being recorded which bear little relationship to the amounts ultimately required to be paid in settlement of those claims and could conceivably exceed the Corporation's total investment in Columbia Transmission. Any such distortion would not be corrected until final plans of reorganization are approved for the Corporation and Columbia Transmission.
UPSTREAM PIPELINE CLAIMS FOR TRANSPORTATION CONTRACTS Columbia Transmission has transportation contracts with certain pipeline companies that historically have been used to deliver gas to Columbia Transmission. With regard to claims made against Columbia Transmission by some of these pipelines in the bankruptcy proceedings, Columbia Transmission has reached settlements that will provide for the assumption of certain contracts, the termination of certain other contracts that are no longer necessary for Columbia Transmission's operations, or the substantial reduction of the transportation contracts. As a result, approximately $463 million of claims filed by pipelines against Columbia Transmission will be withdrawn when the settlements receive Bankruptcy Court and regulatory approvals. The estimated cost of settlements include projected exit fee payments of $105 million including amounts already paid to certain pipelines through December 1994. Those settlements with exit fees are conditioned upon Columbia Transmission's recovery of the exit fees through rates.
INTERNAL REVENUE SERVICE MATTERS The Internal Revenue Service (IRS) filed identical claims of $553.7 million against both debtor companies and the consolidated Columbia Gas System for tax deficiencies, interest and penalties for the years 1983-1990. Negotiations with IRS representatives have resulted in a settlement on all of the issues included in the IRS claims. The settlement was approved by the Joint Committee on Taxation of the U. S. Congress on June 30, 1994, and the Bankruptcy Court on October 12, 1994. The settlement reduced the original claim to approximately $112 million. The final cost of the settlement is expected to be about $46 million after taking into consideration certain tax deductions that become available in subsequent years. The impact of the settlement was recorded in 1993.
The IRS is currently conducting an audit of the 1991-1992 tax years. As part of this audit the Corporation has received a proposed notice of disallowance for its tax deduction of interest expense during this period. The issue concerns only the timing of the interest deduction and not the deductibility of interest expense. Over the next several months the Corporation will present evidence to IRS representatives supporting this
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
deduction. If necessary, the Corporation will pursue this issue through the IRS appeals process or the Bankruptcy Court. If the Corporation cannot sustain the deduction in the years taken, interest expense on the tax deficiency could be due to the IRS with an after-tax impact of approximately $10 million at December 31, 1994.
RETIREMENT PLAN CLAIM The Pension Benefit Guaranty Corporation (PBGC) filed claims of $150 million against both the Corporation and Columbia Transmission alleging that if the retirement plan had been terminated by March 31, 1992, it would have been underfunded. Management believes that the claims made by the PBGC are inappropriate and in error since the Bankruptcy Court has approved continued operation of the retirement plan, required annual contributions are being made, there is no intention to terminate the plan and the plan is not underfunded. Management further believes that the PBGC's claim can be resolved without any financial consequences to the Corporation or Columbia Transmission. On January 29, 1993, the PBGC confirmed that while it remains confident that issues regarding its claims can be resolved by mutual agreement, the PBGC has decided not to proceed further with settlement negotiations regarding withdrawal of its claims at the present time due to the uncertainties associated with the bankruptcy proceedings. At December 31, 1994, the date of the latest actuarial valuation, plan assets exceeded the accumulated benefit obligations by $219.4 million.
C. PLANS OF REORGANIZATION. On January 18, 1994, Columbia Transmission with the Corporation as co-sponsor, filed a reorganization plan (plan) and a disclosure statement for consideration by its creditors and other interested parties. The plan provided that Columbia Transmission would remain a wholly-owned subsidiary of the Corporation, continue to offer an array of competitive transportation and storage services, and retain ownership of its 19,000-mile pipeline network and related facilities. Subsequent to the filing of the plan, Columbia Transmission had discussions directly with gas producers who have substantial claims against it. Despite months of negotiations and numerous offers of settlement, Columbia Transmission has been unable to reach agreement on a consensual reorganization plan with the Columbia Transmission Creditors' Committee. However, Columbia Transmission has had recent discussions, on an individual basis, with a significant number of its largest producer claimants, but it is impossible to determine at this time if these discussions will lead to agreements on the claims.
The Corporation's and Columbia Transmission's exclusive rights to file plans of reorganization expire April 18, 1995. Prior to that date, the Corporation intends to file its reorganization plan with the Bankruptcy Court and to cosponsor amendments to the reorganization plan that Columbia Transmission filed in January 1994.
Both plans will be subject to review and approval requirements (including authorizations from the SEC) which may require several months to complete.
Implementation of reorganization plans for Columbia Transmission and the Corporation, and the levels and timing of distributions to their creditors, are subject to a number of risk factors which could materially impact their outcome. Both companies anticipate emerging from bankruptcy at the same time. The provisions of the reorganization plans of either Columbia Transmission or the Corporation that are ultimately implemented could be materially different from the filed plans.
D. PAYMENT OF DIVIDENDS AND DEBT SERVICE. The Corporation's Board of Directors suspended the payment of dividends on the Corporation's common stock on June 19, 1991. The Corporation also discontinued payments related to debt service. Columbia Transmission suspended dividend, interest and debt payments to the Corporation. The Corporation and Columbia Transmission have also suspended the payment of most other prepetition obligations. Management cannot predict at this time when or whether any financial restructuring plans will be approved or what provisions, if any, such plans would contain as related to the resumption of dividends, debt service and other payments.
E. INTEREST EXPENSE. Interest expense of the Corporation has not been accrued since the bankruptcy filing, but a calculation of interest is included in a footnote on the Statements of Consolidated Income and Consolidated Balance Sheets. Such interest has been calculated based on an interpretation of the contractual
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
arrangements which govern the various debt instruments the Corporation has outstanding exclusive of any redemption premiums. In 1993, the Official Committee of Unsecured Creditors of the Corporation asserted claims for interest which exceed disclosed amounts by approximately $40 million. There are several factors to be considered in making these calculations that are subject to uncertainty as to their ultimate outcome in the bankruptcy proceeding, including the interest rates and method of calculation to be applied to overdue payments of principal and interest. In addition, the committee has asserted that approximately $110 million of redemption premiums should be paid on the high cost debt instruments to compensate investors for anticipated lower interest rates when the debt is refinanced. Amounts disclosed as committee assertions reflect, in part, interest rate markets in late 1993. Resolution of these issues will be dependent upon, among other items, interest rates and market conditions at the time of emergence from bankruptcy.
A favorable District Court decision in the Intercompany Complaint litigation could result in interest expense being recorded for parent company prepetition debt obligations prior to emergence from Chapter 11.
F. SECURITY HOLDER LITIGATION. After the announcement on June 19, 1991, regarding the Corporation's probable charge to second quarter earnings and the suspension of its dividend, 17 complaints including purported class actions were filed against the Corporation and its directors and certain officers of the debtor companies in the District Court. The actions, which generally allege violations of certain anti-fraud provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934, have been consolidated. On October 31, 1994, the class action plaintiffs filed an amended and consolidated complaint against the non-debtor defendants in the District Court essentially alleging the same causes of action as the previously filed complaints. In addition, these plaintiffs filed a motion for class certification in both the Bankruptcy Court and the District Court. The plaintiffs also filed a motion seeking to withdraw the litigation against the Corporation from the Bankruptcy Court to the District Court. On November 1, 1994, the Corporation filed a motion that seeks to require the individual class action plaintiffs to file supplementary information with respect to their previously-filed proofs of claims. Any person not responding would be barred from asserting their claims pursuant to such procedures. In an order dated November 30, 1994, the District Court stayed both the District Court and Bankruptcy Court litigation until a final judgment is entered in the Intercompany Complaint litigation.
On February 13, 1995, the Corporation, in order to promptly address the securities claims in its plan of reorganization, requested the District Court to modify the stay order by considering the Corporation's motion to supplement class proofs of claims. The plaintiffs have objected to this modification.
Also in 1991, three derivative actions were filed in the Court of Chancery in and for New Castle County (Delaware) alleging that directors breached their fiduciary duties. These suits have been stayed by either the Bankruptcy Court filing or by stipulation of the parties.
While the Corporation and its officers and directors believe that they have meritorious defenses to these actions, the outcome is uncertain at this time.
G. CUSTOMER RECOUPMENT RIGHTS. During 1993, several customers of Columbia Transmission filed motions with the Bankruptcy Court, seeking authority to exercise alleged recoupment and setoff rights that are disputed by Columbia Transmission. In their motion the customers seek to be permitted to reduce amounts owed to Columbia Transmission for current services against refunds owed to the customers by Columbia Transmission, including amounts which were not otherwise payable in full under the July 1993 Third Circuit decision discussed below. This would include all customer refunds under the 1990 rate case settlement and miscellaneous refunds not otherwise payable in full to them. Columbia Transmission estimates these refund claims to be approximately $216 million; however, the amount is subject to change as customers quantify their filed claims. The claims associated with the Baltimore Gas & Electric v. FERC litigation (described below) is included in the recoupment and setoff motions filed by the customers.
On October 20, 1993, the Bankruptcy Court approved an interim settlement under which customers continued to pay Columbia Transmission for FERC-authorized services at authorized rates, and Columbia Transmission has agreed to grant these customers a priority claim to the extent the Bankruptcy Court finds
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
them entitled to recoupment rights. In January 1994, the Bankruptcy Court issued a procedural order whereby other customers were permitted to file recoupment and setoff motions by February 18, 1994. Customers, Columbia Transmission and other interested parties have filed summary judgment motions and responses on these issues, and this matter is currently pending before the Bankruptcy Court.
H. CUSTOMER REFUNDS. Total customer claims in Columbia Transmission's bankruptcy proceedings relating to, or arising from, Columbia Transmission's contracts with its customers for sales, transportation, gas storage and similar services and other miscellaneous claims represent about 450 claims for a total filed amount of approximately $550 million, plus a potentially substantial sum filed as undetermined. While a significant portion of these filed claims has been resolved, the claims filed as undetermined still remain to be resolved.
In March 1994, the Bankruptcy Court granted Columbia Transmission's Motion to partially implement the Third Circuit's refund decision directing the pass-through of certain refunds. The decision stated that refunds Columbia Transmission received from upstream pipelines, as well as the Gas Research Institute (GRI) surcharge payments it collected from customers are held in trust by Columbia Transmission, for those customers and the GRI and are not part of Columbia Transmission's estate. Under the Third Circuit ruling, approximately $173 million in refunds that Columbia Transmission has received, or expects to receive postpetition from upstream pipelines and GRI surcharges collected, should be passed through to the customers and to the GRI. However, the Third Circuit determined that $35 million in upstream pipeline refunds and GRI surcharges, which Columbia Transmission collected prior to filing Chapter 11 while received in trust, were subject to the "lowest intermediate cash balance test" (the amount remaining in trust at the time of bankruptcy) and should be distributed on a pro rata basis to the customers and to the GRI to the extent of Columbia Transmission's $3.3 million cash balance on July 31, 1991. The Third Circuit affirmed another part of the U.S. District Court's decision and held that approximately $16 million that Columbia Transmission owes upstream suppliers, for gas purchased and transportation services received prior to its bankruptcy filing, is ordinary unsecured debt which must be discharged in the bankruptcy process.
In April 1994, Columbia Transmission issued refunds of approximately $139 million to its customers, pursuant to the Third Circuit decision, for settlement of a portion of their claims. The majority of these refunds were for pass-through refunds of FERC Order Nos. 500 and 528 (Order 500/528) take-or-pay and related charges received from upstream pipelines that Columbia Transmission had previously paid and then collected from its customers.
A significant portion of the customer claims is attributable to the Baltimore Gas & Electric Co. v. FERC litigation, in which various Columbia Transmission customers and others challenged Columbia Transmission's right to recover Order 500/528 direct charges that were billed to Columbia Transmission by former upstream pipeline suppliers. Such charges are estimated to be approximately $125 million (principal). Interest through the July 31, 1991 petition date would be approximately $40 million. In June 1994, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) ruled that Columbia Transmission's 1985 Purchased Gas Adjustment (PGA) Settlement bars the recovery of some portion of such costs and ordered the FERC to investigate the pipeline charges in question and to disallow the recovery of amounts attributable to Columbia Transmission's gas purchasing practices prior to April 1, 1987. In September 1994, Columbia Transmission filed a motion with the FERC asking that it set procedures and hold a hearing to address issues raised by the court's decision. In December 1994, the FERC issued an order on remand from the court's decision that requires Columbia Transmission to submit a factual filing that identifies the portion of upstream pipeline supplier fixed charges that may be flowed through without violation of the 1985 PGA Settlement, as interpreted by the D. C. Circuit Court. Pending submission of Columbia Transmission's estimate of the charges actually billed to it by the upstream pipelines which are eligible for recovery, the FERC deferred further proceedings. Columbia Transmission's evidentiary filing is due to FERC on March 16, 1995. For this issue the accompanying financial statements reflect a $35 million reserve. Columbia Transmission is continuing settlement discussions with customers on this issue and other significant issues related to the bankruptcy claims, as well as costs recoverable from the customers under FERC Order 636 (Order 636), as transition costs. Any amounts ultimately determined
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
to be due the customers upon conclusion of the required FERC proceedings are prepetition unsecured claims in the bankruptcy proceedings and, therefore, are not entitled to payment of postpetition interest.
Other refund issues underlying customer claims include prepetition revenues collected subject to refund in general rate filings, purchased gas adjustment filings, transportation cost recovery adjustment filings, and other upstream pipeline flowthrough filings. Appropriate reserves for rate refund liabilities have been recorded for these matters to reflect management's judgment of the ultimate outcome of the proceedings.
At a December 1993 hearing, the Bankruptcy Court observed that the FERC should determine whether customers are entitled to the actual interest earned on refunds being held by Columbia Transmission or the higher FERC-prescribed interest rate. The FERC determined that Columbia Transmission must disburse the restricted investment account (RIA) funds with interest actually earned on the RIA funds while in the RIA account, which was established in March 1993, and with interest at the FERC prescribed rate for the period of time before the RIA was created. On October 5, 1994, FERC denied a request by Columbia Transmission's customers for rehearing of its order. One customer filed an appeal of these orders in the D.C. Circuit Court.
I. REORGANIZATION ITEMS. During 1994, 1993 and 1992 the Corporation and Columbia Transmission have earned interest income on cash accumulated from the suspension of payments related to prepetition liabilities, incurred expenses associated with professional fees and other related services and, in 1994, reflected adjustments to producer claim levels based on the claims mediator's report, as detailed below:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
J. FINANCIAL INFORMATION FOR THE DEBTOR COMPANIES. Condensed financial information for the Corporation and Columbia Transmission as of, and for, periods ended December 31, are as follows:
3. REGULATORY MATTERS
A. In April 1992, the FERC issued Order 636, its final rule on Pipeline Service Obligations and Equality of Transportation Services by Pipelines. This order fundamentally changes the role of pipelines from providing a significant merchant function to one in which they perform almost exclusively as transporters and storers of gas that distribution companies and end users purchase directly from producers and other suppliers.
During 1993, the FERC issued a series of orders on the restructuring proposals that included an order that allowed Columbia Transmission and Columbia Gulf to implement restructured services on November 1, 1993. While confirming its initial ruling regarding the ineligibility for recovery of producer contract rejection costs as gas supply realignment or Order 500/528 costs, the FERC did rule that Columbia Transmission could seek to recover a small portion of the contract rejection costs that had earlier been ruled to be unrecoverable. The FERC also agreed to waive a nine-month time limit on Columbia Transmission's ability to seek recovery of unrecovered purchased gas costs to the extent the costs resulted from contracts that are currently in litigation, including bankruptcy litigation. Approximately $13.3 million in unrecovered purchased gas costs were outstanding at December 31, 1994, in addition to approximately $139 million of prepetition unrecovered purchased gas costs that have not been paid due to the bankruptcy filing.
The FERC affirmed that Columbia Transmission could continue recovery of the costs associated with the gathering and processing of natural gas until it files a general rate case. Management continues to evaluate
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
long-term plans for these gathering facilities, which have a net book value of $59.7 million at December 31, 1994. While the ultimate outcome of issues related to realization of its investment in gathering and processing facilities is uncertain at this time, management believes that substantially all of these costs will be recovered through rates or sale of the facilities.
As part of a September 1993 order on Columbia Transmission's and Columbia Gulf's Order 636 compliance filings, the FERC initiated a proceeding concerning Columbia Gulf's transportation service to Columbia Transmission. Columbia Gulf was directed to show cause as to why it did not file for abandonment to reduce capacity on its mainline facilities under Section 7(b) of the Natural Gas Act. Columbia Gulf responded to the show cause order in December 1993, and asserted that no abandonment filing was required. In 1994 and early 1995, Columbia Transmission and Columbia Gulf responded to information requests from the FERC staff. Management continues to believe that an abandonment filing was not necessary; however, the ultimate outcome of this issue is uncertain at this time.
B. In January 1994, the FERC granted requests for rehearing of prior orders approving settlements between Columbia Transmission and four of its upstream pipeline suppliers relating to those suppliers' direct billings to Columbia Transmission in the mid-1980s of production- related costs authorized under FERC's Order No. 94 (Order 94). The rehearing orders reject the settlements because they are expressly contingent upon Columbia Transmission's recovery of the Order 94 settlement payments from its customers, and that Columbia Transmission's 1985 PGA Settlement essentially bars such recovery. However, the orders also hold that these pipelines are not entitled to bill any Order 94 charges to Columbia Transmission, and ordered these upstream pipelines to refund the principal portion of all Order 94 collections from Columbia Transmission, but waived any requirements that these pipelines pay interest on the refunds. Since Columbia Transmission has been reflecting the interest income on these refunds since 1990, the effect of these orders led to a $19.5 million reduction in interest income in 1993. On October 18, 1994, the FERC essentially denied all requests for rehearing but ordered the upstream pipeline suppliers to pay Columbia Transmission interest on the refunds from the date a stay was issued in February 1994. As a result, in September 1994 Columbia Transmission recorded approximately $1 million of interest income. The orders also required that refunds be made by November 17, 1994; however, Columbia Transmission and the pipelines have agreed, subject to certain conditions, to extensions of time to make refunds pending judicial review. Columbia Transmission, its upstream pipelines, and two other customers of one upstream pipeline filed petitions for review of the subject orders with the U. S. Court of Appeals for the District of Columbia Circuit.
C. In June 1994, the FERC granted Columbia Transmission's request for rehearing of a prior order that disallowed the recovery by Columbia Transmission of approximately $20 million in carrying charges related to prior period exchange activity and determined that Columbia Transmission could recover these charges. In July 1994, certain parties filed a request for rehearing of this decision, which is still pending. The beneficial effect on income of the FERC's decision was recorded in 1994.
D. On October 31, 1994, Columbia Transmission terminated its long-standing transportation contract with Columbia Gulf, under which Columbia Gulf transported gas supply acquired by Columbia Transmission in the southwest, and Columbia Gulf's recovery of its actual operating costs was assured. This action was taken because Columbia Transmission no longer required such transportation following the elimination of its merchant function under Order 636.
As a result of the termination of this contract, as well as increases in costs generally since its last rate filing, Columbia Gulf submitted a general rate filing to the FERC. On November 1, 1994, Columbia Gulf placed into effect, subject to refund, its new rates which will provide additional annual revenue of approximately $23 million over Columbia Gulf's previously approved rates. Settlement discussions with the FERC and interested parties are ongoing. A hearing on issues related to this rate filing is currently scheduled to begin in September 1995.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
4. COMMODITY HEDGING ACTIVITIES
Subsidiaries in the Corporation's oil and gas and other energy operations engage in commodity hedging activities to minimize the risk of market fluctuations associated with the price of crude oil and natural gas production, propane inventories and commitments for natural gas purchases and sales. The hedging objectives include assurance of stable and known minimum cash flows, fixing favorable prices and margins when they become available and participation in any long-term increases in value. Under internal guidelines, speculative positions are prohibited.
The Corporation's oil and gas production companies utilize options and swaps on futures as well as commodity price and basis swaps. The options provide a price floor for future production volumes and the opportunity to benefit from any increases in prices. Commodity price swaps provide for the receipt of a differential between a specified strike price and a negotiated term of actual futures prices if the futures prices averaged below the strike price. 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. At December 31, 1994, there were a total of 1,700 open contracts representing a notional quantity amounting to 17 Bcf of natural gas production through September of 1995. A total of $0.5 million in option premium costs as well as $1.7 million of unrealized gains have been deferred on the consolidated balance sheet with respect to these open contracts.
During the year ended December 31, 1994, a total of $3.6 million was recognized in operating income as realized gains on the settlement of crude oil and natural gas option and swap contracts.
The Corporation's propane and gas marketing operations utilize futures contracts and basis swaps to assure adequate margins on the purchase and resale of natural gas as well as protecting the value and margins of its propane inventories. At December 31, 1994, there were a total of 773 open contracts through December 1995, representing a notional quantity amounting to approximately 8 Bcf of natural gas. A total of $3.1 million of unrealized losses have been deferred on the consolidated balance sheet with respect to these open contracts. These unrealized losses are offset by gains which take place when the products are sold.
During the year ended December 31, 1994, $2.7 million of losses were recognized in operating income on the settlement of natural gas futures and basis swaps. In addition, $0.1 million was recognized as losses on the settlement of propane futures contracts.
Gains and losses on propane and gas marketing hedging activities were offset by amounts realized from the sale of the underlying products.
The Corporation and its subsidiaries are exposed to credit losses in the event of nonperformance by the counterparties to its various hedging contracts. Management has evaluated such risk and believes that overall business risk is minimized as a result of these hedging contracts which are primarily with major investment grade financial institutions.
5. ACCOUNTING CHANGE
Effective January 1, 1994, the Corporation adopted the Financial Accounting Standards Board's statement SFAS No. 112, "Employers' Accounting for Postemployment Benefits." This statement requires employers to recognize obligations which exist to provide benefits to former or inactive employees after employment, but before retirement. Such benefits include, but are not limited to, salary continuation, supplemental unemployment, severance, disability, job training, counseling, and continuation of benefits such as health care and life insurance coverage.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The adoption of this statement resulted in an accrual of $14.4 million of which $5.6 million was deferred by certain of the distribution subsidiaries as a regulatory asset pending rate recovery authorization from their respective state commissions. The after-tax effect of the remainder reduced net income by $5.6 million.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
6. INCOME TAXES
The components of income tax expense are as follows:
Total income taxes are different than the amount which 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:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The source of these differences and tax effect of each is as follows:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
7. PENSION AND OTHER POSTRETIREMENT BENEFITS
A. PENSION PLANS
The Corporation has a noncontributory, qualified defined 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. The Corporation's funding policy complies with Federal law and tax regulations.
The Corporation also has a nonqualified pension plan that provides benefits to some employees in excess of the qualified plan's Federal tax limits.
The following table shows the components of net pension expense for the qualified and nonqualified plans and the annual contributions for each of the three years ended December 31, 1994:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The following table reconciles plan assets and liabilities to the funded status of the plan:
The expected long-term rate of return was 9.0%. Plan assets consist of primarily equity and fixed income securities.
As of December 31, 1994, the assumption for the discount rate has been revised upward to 8.5%. The net effect of this change was to decrease the accumulated benefit obligation and the projected benefit obligation by $125.7 million and $188.8 million, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. OTHER POSTRETIREMENT BENEFITS
The Corporation's subsidiaries also provide medical coverage and life insurance to retirees. Essentially all active employees are eligible for 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. The following table shows components of other postretirement costs for each of the three years ended December 31, 1994:
*One of the several established medical trusts is subject to taxation which results in an after-tax asset earnings rate that is less than 9.0%.
The following table provides a reconciliation of other postretirement costs' funded status with amounts reflected on the Corporation's balance sheet at December 31, 1994 and 1993:
The expected long-term, pre-tax rate of return was 9.0%. One of the established retiree medical trusts is subject to tax, resulting in an assumed after-tax rate of return of slightly less than 9.0%. Plan assets consist of shares in various equity and fixed income mutual funds and are attributable to the retiree medical and retiree life insurance plans.
As of December 31, 1994, the assumption for the discount rate has been revised upward to 8.5%. The net effect of the change was a $33.9 million decrease in the accumulated postretirement benefit obligation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The medical accumulated postretirement benefit obligation (APBO) at December 31, 1994 and 1993 is also based on medical inflation trend rates, starting at 9.0% and 11.0% and decreasing to 6.0% and 5.5% after six years and ten years, respectively. A one percent increase in medical inflation trend rates for each future year would have increased the APBO by $16.1 million and other postretirement costs by $3.3 million in 1994.
Most of the Corporation's regulated subsidiaries were prefunding retiree medical costs by year-end 1994 through collective bargaining and noncollective bargaining voluntary employee beneficiary association (VEBA) trusts and a 401(h) account, since they were permitted rate recovery of these costs on an accrual basis consistent with financial reporting herein. Contributions of approximately $20.7 million and $16.9 million were made to these retiree medical trusts in 1994 and 1993, respectively. The Corporation's nonregulated subsidiaries fund retiree medical costs on a pay-as-you-go basis.
All of the Corporation's subsidiaries participate in funding for retiree life insurance benefits, using a noncontributory VEBA trust. The Corporation's funding policy is to make annual contributions to this trust, subject to the statutory maximum tax-deductible limit. Contributions of approximately $3.8 million and $4.4 million were made to the retiree life insurance VEBA trust in 1994 and 1993, respectively.
8. LONG-TERM INCENTIVE PLAN
The Corporation has a Long-Term Incentive Plan (Plan) which provides for the granting of nonqualified stock options, stock appreciation rights and contingent stock awards as determined by the Compensation Committee of the Board of Directors. That committee also has the right to modify any outstanding award. A total of 1,500,000 shares of the Corporation's authorized common stock was initially reserved for issuance under the Plan's provisions. There were 384,070 shares remaining available for awards at December 31, 1994.
Stock appreciation rights, which are granted in connection with certain nonqualified stock options, entitle the holders to receive stock, cash or a combination thereof equal to the excess market value over the grant price.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1994, are as follows:
In addition to the options, a contingent stock award of 4,110 shares was granted to a key executive in 1991 which was issued on September 30, 1994.
9. DEBT OBLIGATIONS
The Corporation's filing for protection under the Bankruptcy Code constituted an event of default under substantially all of its debt agreements. Because payment of debt which existed at the filing date is suspended by the Bankruptcy Code, substantially all of the Corporation's debt, including short-term debt, has been classified as Liabilities Subject to Chapter 11 Proceedings. In addition, payment of interest on prepetition debt is suspended, and no interest expense on such debt has been recorded since commencement of the bankruptcy proceedings (see Note 2E).
Following the Chapter 11 filing, the Corporation received approval from the Bankruptcy Court and the SEC, under the Public Utility Holding Company Act of 1935, for debtor-in-possession financing (the DIP Facility).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
On September 15, 1994, the Corporation converted its remaining $100 million DIP Facility to a $25 million letter of credit DIP Facility with Chemical Bank (Chemical). Columbia Transmission also maintains a DIP Facility with Chemical solely for the issuance of letters of credit for up to $25 million. The DIP Facilities expire on December 31, 1995, unless extended by mutual agreement.
Both the Corporation's and Columbia Transmission's facilities carry a fee of 1% per annum on the issued, but undrawn amount of each letter of credit outstanding under those facilities. The Corporation's facility also carries a commitment fee of 1/2 of 1 percent per annum on the average daily unused amount of the full facility. Other additional fees have been paid under the DIP Facility.
10. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
SFAS No. 107, "Disclosures about Fair Value of Financial Instruments" extends existing fair value disclosure practices by requiring all entities to disclose the fair value of financial instruments, both assets and liabilities, recognized and not recognized in the consolidated balance sheets, for which it is practicable to estimate 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.
The uncertainties related to the outcome of the Corporation's Chapter 11 proceedings and the resulting effect upon the ultimate value of the Corporation's financial assets and liabilities add significantly to the uncertain nature of any estimate of fair value. The estimates of fair value required under SFAS No. 107 require the application of broad assumptions and estimates. Accordingly, any actual exchange of such financial instruments could occur at values significantly different from the amounts disclosed.
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:
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. The estimated fair values of the Corporation's other financial instruments are reflected in the accompanying table.
Long-term investments Long-term investments include escrowed proceeds from the sale of the Canadian subsidiary which consist of Canadian Treasury bills ($25.2 million and $25.4 million for 1994 and 1993, respectively) which are hedged with short-term foreign currency contracts. The carrying amounts of the Canadian Treasury bills and the short-term foreign currency contracts approximate fair value. Long-term investments also include an income tax refund receivable with associated interest ($30.3 million and $31.2 million for 1994 and 1993, respectively) whose carrying amount approximates fair value. Also included are loans receivable ($4.0 million for 1994 and $12.8 million for 1993) whose estimated fair values are based on the present value of estimated future cash flows using an estimated rate for similar loans extended currently. It is not practicable to estimate the fair value of long-term receivables ($146.7 million and $144.4 million for 1994 and 1993, respectively) for the expected recovery by Columbia Transmission of certain gas purchase liabilities for which the timing and amount of payments to be received will be dependent on the outcome of the Chapter 11 proceedings. As discussed in Note 2, the uncertainties related to these proceedings could significantly influence the fair value of this financial instrument. The financial instruments included in long-term investments are primarily reflected in Investments and Other Assets in the consolidated balance sheets.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Liabilities subject to Chapter 11 proceedings
The estimated fair value of the Corporation's debentures and medium-term notes is based on quoted market prices for those issues that are traded on an exchange, and estimates provided by brokers for other issues. However, quoted market prices and broker estimates inherently include judgments concerning the outcome of the Corporation's and Columbia Transmission's Chapter 11 proceedings.
Note 2 discusses the uncertainties related to these proceedings which could significantly influence the fair value of these financial instruments. It was not practicable to estimate the fair value of the remaining long-term debt, which includes the Subordinated Guarantee of the Leveraged Employee Stock Ownership Plan debt ($87.0 million) and miscellaneous debt of Columbia Transmission ($1.4 million for 1994 and 1993), because no reliable measurement methodology exists. Prior to filing its petition for protection under Chapter 11 of the Bankruptcy Code, the Corporation regularly issued commercial paper, bank notes and other short-term debt instruments. The carrying amount of such securities ($892.6 million) is included in Liabilities Subject to Chapter 11 Proceedings. Payment of these obligations and any related interest is subject to approval by the Bankruptcy Court. Although investors from time to time may buy and sell these debt obligations, the terms of any such transactions are private and not disclosed to the Corporation. Because there can be no assurance as to the ultimate timing and amount of principal and interest repayments of these obligations, it is not practicable to determine their fair values.
The carrying amount of other Liabilities Subject to Chapter 11 Proceedings ($1,617.1 million for 1994 and $1,556.0 million for 1993) primarily represents accounts payable, accrued liabilities and other liabilities. As discussed in Note 2, these liabilities are subject to adjustment at the direction of the Bankruptcy Court. In addition, the timing of the ultimate payment of these liabilities, as well as interest, if any, is also subject to determination by the Bankruptcy Court. Accordingly, it is not practicable to determine the fair value of these liabilities.
11. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1995 are currently estimated at $491 million. Of this amount, $191 million is for transmission operations, $158 million for distribution operations, $118 million for oil and gas operations, and $24 million for other energy operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
B. PARTNERSHIP PROJECTS. Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark pipeline partnerships. Since the partnerships are nonrecourse, project-financed pipelines, the partnerships' firm shipper contracts were assigned as collateral for loans to various banks (or in the case of Ozark, to the Indenture Trustee).
During 1994, various pipeline shippers, including Columbia Transmission, entered into negotiations with the partnerships for exit fees to substantially reduce the cost of or provide for the release from transportation contracts. Agreements have been reached on certain contracts, and are currently pending approval by the FERC. Columbia Gulf's investment in the partnerships, as of December 31, 1994, amounted to $34.7 million, net of valuation reserves and before related deferred taxes.
In February 1995, an agreement was reached which provides for the sale of Columbia Gulf's Ozark partnership investment. The agreement contains usual closing conditions and is subject to certain governmental approvals. Closing is expected to occur on May 1, 1995. The impact of the sale of Columbia Gulf's interest in the partnership is not expected to have a material impact on the financial condition of the company.
C. OTHER LEGAL PROCEEDINGS. The Corporation 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 the Corporation's consolidated financial position or results of operations.
The sale of Columbia Gas Development of Canada, Ltd. (Columbia Canada), a wholly-owned Canadian oil and gas exploration and production subsidiary, to Anderson Exploration Ltd., was effective December 31, 1991. The sales price from Columbia Canada was $94.8 million. Of this amount, $27.7 million was placed in escrow as security for certain post-closing obligations of the Corporation including indemnification for potential losses arising from litigation involving Columbia Canada. The Corporation expects to receive all or substantially all of the escrow account when the litigation is concluded. Upon emergence from bankruptcy, the Corporation is obligated to deposit into an escrow account an additional $25 million (Canadian). If after emergence from bankruptcy, the Corporation maintains an investment grade bond rating for a six-month period, the additional deposit would be returned. Also, the Corporation has the right to provide a letter of credit in place of the cash deposit. As of December 31, 1994, $25.2 million, including accrued interest, remains in escrow for potential losses arising from litigation and is included in Accounts Receivable - Noncurrent.
D. ASSETS UNDER LIEN. The letters of credit issued under the debtor-in-possession financing arrangement on behalf of the Corporation are secured by the granting of a first priority senior security interest in collateral consisting of cash and/or cash equivalents in an amount equal to at least 105% of the outstanding letters of credit. The obligations under Columbia Transmission's letter of credit facility are secured by a first priority senior security interest in collateral consisting of cash and/or cash equivalents in an amount equal to at least 105% of the outstanding letters of credit.
Substantially all of Columbia Transmission's properties have been pledged to the Corporation as security for debt owed by Columbia Transmission to the Corporation.
E. COVE POINT LNG TERMINAL. By orders issued July 27, 1994, and September 28, 1994, the FERC determined that the peaking service proposed by the partnership formed by Columbia LNG Corporation (Columbia LNG) and a subsidiary of Potomac Electric Power Company (PEPCO) is in the public interest; however, the proposal to charge market-based rates was denied. Also, only a portion of Columbia LNG's current rate base was allowed in the calculation of the cost-based rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
On December 12, 1994, the FERC certificate to recommission the facility and offer a peaking service was accepted by the partnership, and the Cove Point Terminal and pipeline facilities were contributed by Columbia LNG to the partnership as its initial capital contribution. The PEPCO subsidiary will contribute up to $25 million in equity and loans for their half interest in the partnership. It is anticipated that the peaking service will be operational in the fall of 1995.
Management concluded in 1992 that it was no longer appropriate for Columbia LNG to continue application of SFAS No. 71. This resulted in an extraordinary charge of $39.7 million after-tax.
F. OPERATING LEASES. Payments made in connection with operating leases are charged to operation and maintenance expense as incurred. Such amounts were $56.6 million in 1994, $55.5 million in 1993 and $57.9 million in 1992. Future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year are:
G. ENVIRONMENTAL MATTERS. The Corporation'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.
Certain subsidiaries have received notice from the United States Environmental Protection Agency (EPA) that they are among several parties responsible under federal law for placing wastes at Superfund sites and may be required to share in the cost of remediation for these sites. However, considering known facts, existing laws and possible insurance and rate recoveries, management does not believe the identified Superfund matters will have a material adverse effect on future annual income or on the Corporation's financial position.
As a result of a 1992 Subpoena and Information Request received from the EPA for Region III, Columbia Transmission and the EPA reached agreements in September 1994, that were subsequently approved by the Bankruptcy Court in November 1994. This agreement gives the agency oversight responsibility for Columbia Transmission's ongoing environmental self-assessment and remediation program started in 1990 and has an effective date of February 23, 1995. The agreement calls for the remediation work to be done under the Comprehensive Environmental Response, Compensation and Liability Act. Agreements have also been reached with two state environmental agencies concerning Columbia Transmission's environmental remediation programs. In Kentucky, Columbia Transmission settled all notices of violation issued prior to January 1, 1994, and signed an agreement to reimburse the state for its costs to oversee the remediation
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
work under the EPA Order. In Pennsylvania, Columbia Transmission agreed to reimburse the state for its oversight costs. These agreements have been approved by the Bankruptcy Court. All environmental agencies have been declared exempt from the Bar Date established by the Bankruptcy Court for claims by creditors.
Columbia Transmission initiated a program in 1990 that involved a comprehensive review of compliance with existing environmental standards, including review of past operational activities and identification of potential site problems, through site reviews and the formulation of remediation programs where necessary. While Columbia Transmission has made progress in these self-assessment efforts, because of the thousands of miles of pipeline which it operates, the exceptionally large number of sites at which it conducts or has conducted operations, and the long period over which operations have been conducted, it is expected that the completion of site screenings, characterizations and site-specific remediations will cover a time frame of approximately 10 to 12 years. A study previously undertaken for Columbia Transmission which quantified the scope of future remediation activities is being reviewed by an independent consultant in light of an EPA order and additional information accumulated during 1994. The results of this study are not expected to be available until early to mid-1995. At the present time, management has no basis to change the previously disclosed estimated level of environmental expenditures of up to $20 million per year over a 10 to 12 year period. Earnings are charged as costs become probable and reasonably estimable, regardless of when expenditures are made. Columbia Transmission's recorded net liability for environmental matters was approximately $135 million at December 31, 1994. This amount represents the lower end of a range of reasonable outcomes with the upper end estimated to total approximately $280 million based on previous studies.
Columbia Transmission received from EPA Region V an Information Request pursuant to the Resource Conservation and Recovery Act (RCRA) on January 28, 1994. The agency requested Columbia Transmission submit information and knowledge relating to its generation and management of natural gas pipeline condensate, used engine oil and similar liquids in the state of Ohio. Columbia Transmission has submitted the requested information to EPA Region V and is awaiting a response.
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 unable at this time to determine if it will become liable for any characterization or remediation costs at such sites.
As a result of site characterization studies at various locations during 1993, Columbia Gulf recorded an additional accrual of $6.7 million for environmental remediation. This accrual is for polychlorinated biphenyl (PCB) and petroleum hydrocarbon cleanup at certain compressor station sites and screenings for possible exposure at other locations. Columbia Gulf continued its site evaluations and remediation activities at various locations during 1994, and recorded additional accruals of $19.3 million for environmental matters of which a portion was recovered in current period revenues. The additional accruals were to remediate newly discovered contamination at certain compressor station sites, screening for possible exposure at other locations and for cleanup of various station sites, pipeline drip sites, and measurement sites. In the event future screenings identify additional exposure, the costs of remediation will be quantified, and additional accruals may become necessary.
Distribution's primary environmental issues relate to former manufactured gas plant sites. Currently, Distribution has identified 13 former gas plant sites. Environmental investigations are being conducted at five of these sites which indicate that remedial actions may be required. Investigations will be conducted at a number of the other sites in the future. To the extent site investigations have been completed, remediation plans developed, and any Distribution responsibility for remedial action established, the appropriate liability has been recorded. As additional investigations are completed and remediation costs become probable to which Distribution is determined to be liable, the appropriate liability will be recorded.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Management continues to anticipate recovery of remediation costs through normal rate proceedings. As of December 31, 1994, the distribution subsidiaries' had recorded a net liability of $5.6 million.
The eventual total cost of full future environmental compliance for the Columbia Gas System 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 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 $146.7 million for the Columbia Gas System at December 31, 1994, which includes the low end of a range for certain expenditures for the transmission segment previously discussed. 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. Although significant charges to earnings could be required prior to rate recovery, management does not believe that environmental expenditures will have a material adverse effect on the Corporation's financial position, based on known facts, existing laws and regulations and the period over which expenditures are required.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
12. INTEREST INCOME AND OTHER, NET
13. INTEREST EXPENSE AND RELATED CHARGES
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
14. BUSINESS SEGMENT INFORMATION
The following tables provide information concerning the Corporation'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. Identifiable assets include only those attributable to the operations of each segment.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of the System's business operations due to bankruptcy matters, nonrecurring items and seasonal weather patterns which affect earnings and related components of operating revenues and expenses.
(a) Includes an increase in net income of $10.3 million for an adjustment to the reserve for the IRS settlement and an increase in net income of $8.3 million for surcharge collections of certain prior period gas costs. Net income benefited $34.5 million from not recording estimated interest expense on prepetition debt.
(b) Includes a decrease in net income of $4.3 million for a weather normalization adjustment resulting from a regulatory settlement and a decrease in net income of $2.1 million associated with employee relocation costs, partially offset by an increase in net income of $3.2 million for an adjustment to a reserve for a resolution of a royalty dispute. Net income benefited $35.5 million from not recording estimated interest expense on prepetition debt.
(c) Includes a decrease in net income of $35.4 million resulting from an increase to a reserve for take-or-pay and other miscellaneous producer claims. Net income benefited $36.6 million from not recording estimated interest expense on prepetition debt.
(d) Includes a decrease in net income of $22.8 million for a reserve established for regulatory issues. Net income benefited $37.6 million from not recording estimated interest expense on prepetition debt.
(e) Includes an increase in net income of $13.2 million for the reversal of rate reserves to reflect the outcome of rate cases related to the transmission segment. Net income benefited $32.9 million from not recording estimated interest expense on prepetition debt.
(f) Includes a decrease in net income of $37.9 million to record a writedown in the investment in the Cove Point LNG facility and a decrease in net income of $7.4 million to record the estimated loss on the sale of storage inventory. Net income benefited $33.2 million from not recording estimated interest expense on prepetition debt.
(g) Includes a decrease in net income of $40.4 million to record the effect of a preliminary settlement with the IRS, a decrease in net income of $13.0 million to record a liability for future environmental remediation costs, a decrease in net income of $9.8 million to reflect the effect of the higher federal corporate tax rate and a decrease in net income of $9.8 million for several smaller unusual items. Net income benefited $33.9 million from not recording estimated interest expense on prepetition debt.
(h) Includes an increase in net income of $13.5 million for gas inventory charges collected from customers and an increase in net income of $12.8 million for the WACOG surcharge collected from customers, partially offset by a decrease in net income of $12.6 million for an adjustment to interest income for pipeline direct billings. Net income benefited $34.3 million from not recording estimated interest expense on prepetition debt.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. Reserve information contained in the following tables for the U.S. properties is management's estimate, which was reviewed by the independent consulting firm of Ryder Scott Company Petroleum Engineers. Reserves are reported as net working interest. Gross revenues are reported after deduction of royalty interest payments.
(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 to Consolidated Financial Statements of $6.4 million in 1994, $6.0 million in 1993 and $5.9 million in 1992.
Results of operations for producing activities exclude administrative and general costs, corporate overhead and interest expense. Income tax expense is expressed at statutory rates less Section 29 credits.
(a) Includes writedown of the carrying value of $126.4 million for 1992.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Future cash inflows are computed by applying year-end prices to estimated future production of proved oil and gas 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 percent 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 the Corporation's oil and gas 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.
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 oil and gas reserves for the three years ending December 31, 1994, follows:
The estimated discounted future net cash flows decreased during 1994 primarily due to net changes in prices and production costs and revisions to the economic feasibility of producing certain wells.
Under Order 636, the natural gas pipeline industry is required to eventually unbundle gathering services from other transportation services. Columbia Transmission provides transportation services, including gathering services, for a significant portion of gas produced from CNR's reserves. If there is a significant increase in gathering rates as a result of unbundling, certain reserves could be uneconomical to produce which could have a material adverse effect on CNR's operating strategies and financial results beginning in 1996. The extent of any potential asset impairment or increase in operating costs cannot be quantified at this time.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule II
VALUATION AND QUALIFYING ACCOUNTS The Columbia Gas System, Inc. and Subsidiaries Year Ended December 31, ($ in Millions)
(a) Reflects reclassification to a regulatory asset of the uncollectible accounts related to the Percent of Income Plan (PIP) of Columbia Gas of Ohio, Inc. (b) Principally reflects amounts charged off as uncollectible less amounts recovered.
ITEM 9.
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.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by this item is contained in the Corporation's Proxy Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
Information regarding the System's executive officers, who are elected annually by the directors, is as follows:
JOHN H. CROOM, 62, Chairman of the Board, President and Chief Executive Officer of the Corporation since August 1984.
DANIEL L. BELL, JR., 65, Senior Vice President and Chief Legal Officer of the Corporation since January 1989, Corporate Secretary since January 1988. Senior Vice President of Columbia's Service Corporation since September 1979.
LOGAN W. WALLINGFORD, 62, Senior Vice President of Columbia Gas System Service Corporation since March 1989. Senior Vice President of Planning and Storage for Columbia Transmission from July 1988 to February 1989, Senior Vice President, Gas Acquisition from July 1987 to June 1988, Vice President of Planning from March 1985 to June 1987.
RICHARD E. LOWE, 54, Vice President of the Corporation and Columbia Gas System Service Corporation since September 1988. Vice President and General Auditor of Columbia Gas System Service Corporation from April 1987 to August 1988. Treasurer of Columbia Gas Development Corporation from April 1979 to March 1987.
JAMES P. HOLLAND, 46, Chairman and Chief Executive Officer of Columbia Transmission and Columbia Gulf Transmission Company since September 1990. President of Columbia Transmission from May 1988 to August 1990. President of Columbia Gulf Transmission Company from October 1989 to August 1990. Senior Vice President of Marketing of Columbia Transmission from July 1987 to April 1988, Senior Vice President of Gas Acquisition from January 1986 to June 1987.
C. RONALD TILLEY, 57, Chairman and Chief Executive Officer of Columbia Distribution Companies since January 1987.
MICHAEL W. O'DONNELL, 50, Senior Vice President and Chief Financial Officer of the Corporation since October 1993. Senior Vice President and Assistant Chief Financial Officer of the Columbia Gas System Service Corporation since 1989.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in the Corporation's Proxy Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in the Corporation's Proxy Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in the Corporation's Proxy Statement related to the 1995 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits Reference is made to pages 99 through 103 for the list of exhibits filed as a 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 the Corporation or its subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of the Corporation and its subsidiaries on a consolidated basis. The Corporation agrees to furnish a copy of any such instrument to the SEC upon request.
Financial Statement Schedules All of the financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8.
Reports on Form 8-K A report on Form 8-K was filed on November 17, 1994, discussing the Bankruptcy Court's approval of the extension of the exclusivity period to the earlier of April 18, 1995, or 45 days following the District Court's decision on the Intercompany Complaint. The exclusivity period is the period of time that Columbia Transmission and the Corporation have the exclusive right to file Chapter 11 plans or reorganization.
A report on Form 8-K was filed on February 2, 1995, containing a Press Release published on February 2, 1995, regarding the Corporation's seeking approval of a shareholder rights plan to protect shareholders' investments in the event of an unsolicited, inadequate offer for the Corporation's common stock.
A report on Form 8-K was filed on February 10, 1995, containing a Press Release published on February 9, 1995, regarding the financial and operating results for the year ended December 31, 1994.
A report on Form 8-K was filed on February 15, 1995, containing a Press Release published on February 15, 1995, regarding the election of three new members of the Corporation's Board of Directors. The Press Release also noted that three current members of the Board are not seeking reelection.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
Undertaking made in Connection with 1933 Act Compliance on Form S-8 For purposes of complying with the amendments to the rules governing Form S-8 under the Securities Act of 1933, the Corporation undertakes the following, which is incorporated by reference into the registration statements on Form S-8, Nos. 33-10004 (filed November 26, 1986) and 33-42776 (filed September 13, 1991):
Insofar as indemnification for liabilities arising under the Securities Act of 1933 (Act) may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the questions whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
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.
THE COLUMBIA GAS SYSTEM, INC. ------------------------------ (Registrant)
Dated: March 6, 1995
By: /s/ Michael W. O'Donnell ----------------------------------- (Michael W. O'Donnell) Senior Vice President and Chief Financial 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.
EXHIBIT INDEX
Reference is made in the two right-hand columns below to those exhibits which have heretofore been filed with the Commission. Exhibits so referred to are incorporated herein by reference.
EXHIBIT INDEX (Continued)
- --------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. * Filed herewith.
EXHIBIT INDEX (Continued)
- ------------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. * Filed herewith.
EXHIBIT INDEX (Continued)
- --------------------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
EXHIBIT INDEX (Continued)
- -------------------------- *Filed herewith.