Transmission Asset Sales: Running the Regulatory Gauntlet
May 15, 2003
By Daniel L. Schiffer and Marc D. Machlin
There are many considerations and obstacles to overcome before transmission assets can be bought or sold.
By now, everyone has heard of the first high profile, large-scale transmission system sales that have taken place in the industry, which were made to look like a smooth and easy process by leveraged buyout kings such as Kohlberg Kravis Roberts & Co. (KKR), and independent transmission operators such as Trans-Elect (see Chart 1). But most will agree that buying or selling a transmission system requires careful planning and is not always feasible; the transactions carry with them a whole host of financial risks and regulatory obstacles that must be traversed before the deal is done.1
Some potential sellers may choose to stay on the sidelines. There always will be utilities that prefer to stay vertically integrated and do not want to deal with tax issues and questions of what to do with the money, or the implications to the future health and earnings power of the utility company (see sidebar, p. 48).
Other potential sellers may be willing to move forwared if they can get comfortable with the business risks and regulatory issues. Having the best market intelligence and understanding of the regulatory climate will be essential for transmission asset sales in the near future among utilities and utility holding companies anxious to raise cash and improve their balance sheets in the wake of the Enron debacle.
It is no coincidence that many of the recently announced deals have taken place in the Midwest, which has had an ideal climate for transmission divesture along with supportive statutory frameworks.2 Regulators in other states, including Pennsylvania, also may be receptive to such transactions,3 whereas southeastern and western regulators have been extremely vocal about their concerns that asset sales may transfer regulatory authority from state capitals to Washington, D.C. (In New England, regulators have been advocates of electric restructuring, but they often have encouraged divestiture of generation rather than transmission assets.)
Moreover, depending upon the regulatory climate, the economics of divesture may be unattractive. While federal regulators may create a climate under which potential purchasers would pay attractive prices for transmission assets, there is a very real threat that state regulators would require all proceeds in excess of book to flow back to customers (see, e.g., Democratic National Committee v. Washington Metropolitan Area Transit Commission, 485 F.2d 786 [D.C. Cir. 1973], cert. denied, 415 U.S. 935 [1974]). Selling utility assets for proceeds that are effectively capped at book value at a time when utility equities are trading at a premium to book4 is simply a recipe for destroying shareholder value.
Thus, for utilities considering these transactions, it is essential to have a favorable state regulatory climate that allows the selling utility to retain enough sales proceeds to make a sale economically attractive to the company and its shareholders. Direct state control over the rates charged for transmission service is limited and diminishing as a result of Order 2000 and the proposed standard market design.5
Yet state utility commissions typically do have authority to determine the retail rate impact, if any, of profits earned upon the sale of transmission assets; this gives those commissions "a meaningful seat at the table." In the end, the favorable state regulatory climate needed for transmission asset sales can most reliably be expected in those jurisdictions that support ongoing efforts by the Federal Energy Regulatory Commission (FERC) to restructure the industry.
Regulatory Issues: Buyer Beware
The analogous regulatory issue for the buyer is whether it will be permitted to earn a return on that portion of its investment that exceeds the selling utility's book value. FERC generally has required use of depreciated original cost, both for measuring the rate base and for calculating future depreciation costs. Under this approach, a buyer typically inherits the rate base of a prior owner even if the buyer has purchased assets (or an entire firm) for a price higher than depreciated original cost or book value.6
In the merger context, usually at the state level, the regulatory treatment of consideration in excess of book (the acquisition premium) often has taken the form of amortization funded by synergy savings achieved or projected by the merger sponsors. At FERC, the issue has been raised in requests for an incentive return on equity and recognition of accumulated deferred taxes7 reimbursed to the seller as an element of the rate base.8
FERC's Grid Rates Policy provides for either a 200 basis point return on equity adder or inclusion in rate base of accumulated deferred taxes paid to the seller. The adder is payable to any independent transmission company that transfers control of its facilities to a regional transmission organization (RTO). It earns 50 percent for the transfer of control to an RTO and an additional 150 basis point if none of its passive or active owners are market participants in the RTO. The return on equity is calculated on a net present value basis for the period, beginning with the transfer of control and ending Dec. 31, 2012.9
Two recent cases sketch out the parameters of the commission's incentive policy. In ITC Holdings (Detroit Edison) (102 FERC 61,182, Feb. 20, 2003), FERC accepted rates that reflected both a 100 basis point return on equity incentive and inclusion of accumulated provision for depreciation in the rate base, as well as a capital structure with a 60 percent common equity ratio (102 FERC 61,182, at pp. 58-68). By contrast, in Illinois Power Company (102 FERC 61,184 Feb. 20, 2003), the commission set for hearing rates based on a 50-50 capital structure, a 13 percent return on equity, and the levelized gross plant original cost method for determining the capital cost to be included in rates. This method has the effect of including both accumulated depreciation and accumulated deferred taxes in the rate base (102 FERC 61,184 at pp. 17-26). The most likely result of the Illinois Power order establishing hearing procedures is a restructured arrangement that will give the commission a further opportunity to refine its incentive policy.
The Impact of PUHCA
Any private firm owning transmission assets is a FERC-regulated public utility. More important, any entity owning a significant equity interest in that public utility is subject to the Public Utility Holding Company Act of 1935 (PUHCA). Investors funding the acquisitions of transmission assets typically wish to avoid PUHCA entanglement, and they usually can do so by limiting control over the operating company to the minimum necessary to protect their interests as investors.10
In General Electric Capital Corp., SEC No-Action Letter (April 26, 2002), the SEC concluded that GE's significant financial involvement in Michigan Electric Transmission Co. LLP (METC) would not result in GE being a holding company or an affiliate under the PUHCA. METC was formed to own all of the transmission assets then owned by Consumers Energy, the nation's fifth largest electric company. METC's general partner is Trans-Elect, an entity owned and controlled by a number of executives with extensive and distinguished electric utility backgrounds. GE is a preferred limited partner and provided virtually all of the equity capital of partnership. Another GE subsidiary was expected to own 25 percent of Series C preferred equity issued by Trans-Elect, which equated to 12.5 percent of that entity's total equity.
The SEC provides a detailed summary of GE's rights as a limited partner. Key findings include: (1) independence and experience of the owner-executive group of Trans-Elect; (2) management of the partnership is clearly vested in the general partner; (3) rights reserved to GE as limited partner are limited to those necessary to protect the limited partnership investment and do not go to day-to-day management of the partnership; and (4) the high standard that must be met before the general partner can be terminated and replaced.
The SEC also discussed GE's rights as a 25 percent holder of Series C preferred stock in the general partner. The Series C holders' voting rights are limited to a modest number of extraordinary items, namely: amendment of the general partner's articles of incorporation; mergers or substantial asset sales or purchases; stock redemptions; dilutive stock issuances; benefit or option plan amendments; and agreements with officers.
Moreover, GE has no veto power over these items since they are subject to simple majority vote of the preferred stock and GE holds only 25 percent of that stock. Finally, the SEC letter emphasized that the general partner's experience, economic stake, independence, and financial incentives militate against any finding of control by GE. Overall, the SEC has provided a clear road map for those who want to take a significant economic stake in an ITC without subjecting themselves to PUHCA.
While the SEC's no-action letter may facilitate planning by ITCs and their investors, public utilities must evaluate PUHCA-related issues in deciding whether to divest their transmission assets. Specifically, a utility that is considering a mergers and acquisitions strategy should determine whether a sale of its transmission assets would impair its ability to form a single integrated public-utility system with potential merger or acquisition candidates.11
On a more long-term basis, if PUHCA is repealed, investors, transmission companies, and utilities would have even greater flexibility in structuring these transactions. Ultimately, repeal of PUHCA could enhance the ability of independent transmission firms to attract and retain capital.
Utility Planning for a Potential Divestiture: The Devil in the Details
The substantial planning or evaluation for a potential divestiture includes, after the identification of the power lines, substations, and other assets likely to be divested, a calculation of the past and projected earnings attributable to these assets. At the same time, the utility must examine its credit agreements, loan agreements, and other financial instruments to determine whether there are any significant impediments to a sale. This review should also determine if the sales proceeds must be dedicated to the payoff or retirement of any specific obligations.
As part of the planning process, the utility also must consider basic organizational issues. Once the separate entity is set up, the interdependent relationships among the transmission entity, generation, and local distribution do not end. In order for regulators and company managements to be comfortable, arrangements-usually written contracts-should be in place to govern transactions between these disaggregated entities for the near and intermediate terms.
Once a utility decides to move forward, a first step is typically the transfer of assets and personnel to an affiliate and the negotiation of a number of contracts with the new affiliate. Stand-alone salary and benefit programs have to be designed for the employees of the new entity to ensure that its management will truly be independent of the divesting electric company. Transmission assets have to be identified with specificity and transferred.12 Key contracts to be performed on transmission lines by the distribution utility should be negotiated and signed to cover operation and maintenance, construction, and administrative services. Such contracts also should address right-of-way ownership and expansion rights,13 interconnection agreements, transmission agreements, membership in the RTO, and assumption by the ITC of agreements made by its predecessor.
While these all could be negotiated in the first instance between the divesting electric company and the independent transmission company, the more practical approach-the one taken by all sellers thus far-has been to work with an affiliate to structure the basic framework of the new transmission entity, with refinements as part of the negotiation process with the purchaser of the new entity (i.e., a stock sale, not an asset sale).
Endnotes
- The number of companies announcing a desire to raise capital and improve their capital structures is legion. See, e.g., American Electric Power, news release dated Jan. 24, 2003, http://www.aep.com/investors/financialreleases/default.asp?dbcommand=DisplayRelease&ID=986&;Section=Financial&colorControl=on. Few have publicly identified transmission as a non-core assets suitable for divesture.
- See, e.g., Illinois Public Utilities Act §16-111(g), 220 ILCS 5/16-111(g).
- The Pennsylvania Public Utility Commission has strongly supported standard market design. See, e.g., press release dated Jan. 13, 2003, http://puc.paonline.com/press_releases/Press_Releases. asp?UtilityCode=EL&UtilityName=Electric&PR_ID=956&View=PressRelease, Comments filed Jan. 10, 2003, Docket No. RM 01-12.
- See, e.g., http://biz.yahoo.com/p/electupriu.html.
- The FERC's assertion over all transmission rates other than those bundled with retail sales was upheld in New York v. FERC, 535 U. S. 1 (2002), in an opinion that contains dicta to support FERC jurisdiction over all transmission, including services bundled with retail sales.
- See Uniform System of Accounts for Utilities Subject to the Federal Power Act, Electric Plant Instruction 2; 18 CFR 298; Montana Power v. FERC, 599 F.2d 295, 300 (9th Cir. 1979); Niagara Falls Power Co. v. FPC, 137 F.2d 787, 796-97 (2d Cir.), cert. denied, 320 U.S. 792 (1943) (Judge Augustus Hand, concurring); Duquesne Light, 488 U.S. at 308-310.
- See, e.g., Trans-Elect Inc. (Consumers Energy), Order on Rehearing, 98 FERC 61, 368, pp. 4-5 (2002).
- FERC is generally reluctant to utilize "double leverage" or otherwise look behind the capital structure of the regulated entity. See, e.g., William Natural Gas, 84 FERC 61,080 (1998) rehearing denied, 86 FERC 61,232 (1999). This reluctance, combined with relatively favorable debt-equity ratios, provides an investor with another vehicle for recouping an acquisition premium that is not explicitly recognized in rate base.
- A further 100 basis point adder is available for certain transmission upgrades funded by the independent transmission company pursuant to an RTO planning process.
- As a practical matter, the investors are not giving up much, since the independent transmission company has already ceded so much operating control to the regional transmission operator.
- PUHCA provides that the SEC "shall approve" a merger unless it makes certain adverse findings. PUHCA prohibits approval of an acquisition if the SEC finds that the resulting holding company will no longer constitute a single "integrated public-utility system." PUHCA §§10(c)(1), 11(b)(1); 15 USC §§ 79j(c)(1), 79k(b)(1). This is defined as "[A] system . . . whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capable of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more states, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation and the effectiveness of regulation." PUHCA §2(a)(29), 15 USC § 79b(a)(29). See, generally, National Rural Electric Cooperative Ass'n v. SEC, 276 F.3d 609 (D.C. Cir. 2002).
- While the seven-indicators test in Order 888, 75 FERC 61, 080, pp. 401-02 (1996), and its application by state public utility commission define the line between transmission and distribution assets, drawing the line separating transmission and generation-related assets can sometimes be trickier.
- Trans-Elect Inc. (Consumers Energy), 98 FERC 61,132, pp. 12-16 (2002), is especially instructive on the right of way issue because the parties structured the transaction with the rights of way retained by the seller. The buyer was obligated to make annual lease payments. This reduced buyer's capital requirements and provided the seller with a long-term stream of income and cash flows. FERC approved this arrangement but modified it by limiting the seller's retained interest to uses that do not impair or interfere with transmission-related uses.
*Plus annual easement payments for retained right-of-way.
Dan Schiffer and Marc Machlin are attorneys with Pepper Hamilton LLP. Contact Schiffer in the Detroit office at schifferd@pepperlaw.com Contact Machlin in the Washington, D.C. officeat machlinm@pepperlaw.com.
The Deferred Tax Issue
Understanding the tax issues that must be addressed before selling transmission assets.
Deferred taxes are often a significant component of a utility's capital structure. Generally, they arise from the fact that federal income tax expense paid is less than the amount recorded for book purposes or reflected in the cost of service in setting rates. The difference is chiefly attributable to depreciation that is more rapid for tax purposes than for ratemaking purposes. Typically, the accumulated deferred taxes balance, which at any point in time is the difference between a property's book and tax basis, is treated as zero-cost capital for rate purposes. When a utility sells an asset, the accumulated deferred taxes become payable, and it loses the benefit of any such zero cost capital. In past transactions in which transmission assets have been sold, the buyer has typically reimbursed the seller for the lost tax benefit and has sought to reflect the additional consideration paid in future rates to be paid for transmission services. This is potentially allowable under the exception to the general principle of original cost ratemaking allowing recognition of the premium paid by the buyer where the transaction will ultimately benefit ratepayers. -D.L.S. and M.D.M.
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