Michael J. Zimmer & Samir S. Desai, Baker & McKenzie
Companies in the North American electric power sector face an uphill battle in today’s electric power wholesale and capital markets. A combination of general economic and industry crises has forced many participants to face difficult decisions to achieve their business and strategic goals until 2005. A key component of any decision to participate successfully in the North American power sector on an ongoing basis is the evaluation, in financial and strategic terms, of electric power generation assets–whether to acquire or divest them. While there has been delay in this decision-making because of a variety of factors, an increased level of activity is expected in the second half of 2003 through 2004 with 90,000–140,000 MW of power projects in play in North American markets.
Understanding market forces
The prevailing mood in the North American power market is one of retrenchment as companies reorganize their asset portfolios to stabilize their balance sheets and allay investor, rating agency and lender concerns. Issues affecting these underlying asset valuations include:
“- Are adequate confidentiality obligations in place? Are waivers of existing confidentiality obligations required? Is the acquisition or divestiture being made under an option? A right of first refusal? Are appropriate contractual notification and consent requirements being complied with? Is the arrangement an exclusive one? What break-up fees are contemplated, if any?
“- Is the entire asset being offered, or merely a share in the project? Does another party hold a right to match the offer? Are competition or market power compliance obligations implicated? Is the asset offered as part of an integrated system, including generation, transmission and distribution assets? Is the asset exempt from regulation? Will the proposed transaction cause it to lose its exemption? The regulatory consequences of such an acquisition will depend on the nature of the asset offered.
“- Will capital and credit markets support refinancing of project debt or must existing debt be restructured? Does the existing financing structure (e.g., synthetic lease) create restructuring obstacles or market perception problems? Have adequate accounting and audit controls been maintained? Which acquisition financing alternatives are available? Is the project part of a portfolio or stand-alone financing? How invested are members of the syndicate in other financings of the acquirer/seller? Is any part of the project secured by a junior creditor (e.g., a utility offtaker or fuel supplier) or are there subordinated tiers of lenders? Are there outstanding liens on project assets?
“- Does the existing project structure create any potential liquidity issues? If offtaker payment risk increases, are timing deadlines in the project agreements properly synchronized to minimize the need for more project working capital? Are lines of credit or bridge facilities available? Is the debt structure flexible enough to absorb deviations in the cash flow? Can overdue power payments be offset? Are liquidated damages sufficient to service debt and meet operating costs? Are alternative power sales arrangements feasible?
“- Which specific counter-party credit concerns should be mitigated with credit support? Is the credit support structured to account for the effects of ratings or share price deterioration? What is the risk of insolvency of the offtaker? How would bankruptcy affect its purchase obligations and the treatment by the bankruptcy trustee of the power purchase agreement? Which credit support obligations will have to be assumed, e.g., fuel supply? Will any hedging transactions have to be unwound or can they be assumed?
“- What are the relevant restrictions in the project or credit agreements on change of control, assignment, consent provisions, minimum standards of acquirer creditworthiness, counter-party credit downgrades, and coverage tests? Are there any such restrictions in applicable permits or on permit transfers? What is the likely cost of obtaining necessary approvals, and who will bear them? What are the implications of triggers for seller distress, offtaker downgrade, buyer exit, and electricity price volatility?
“- Are there any investigations or reviews that will affect asset value or tie up project personnel, e.g., SEC inquiry or FERC trading inquiry? Is the regulatory regime in the state unwinding? Are consumer advocacy groups involved? Is there greater regulatory scrutiny of power asset transfers? Have auditors recently been changed, and are copies of the minutes of management or partner meetings made available?
The buyer’s transaction team needs an integrated set of multidisciplinary skills to evaluate and help validate model assumptions and other projections relating to the proposed acquisition. Optionalities can create more value from the asset. Often a buyer’s winning bid is based on more than a lower discount rate applied to future project cash flows. Value can be used to enhance a bid or purchase strategy, and the buyer needs to understand the uncertainties in model assumptions, such as:
“- Will changes to the transmission market affect the value of the project? What effect will RTOs, FERC’s standard market design and transmission congestion management have on the sale of electricity from the project? Is there any prospect for transmission line upgrades or independent transmission links that would provide capacity to new competitors? How do these factors affect assumptions about current and future sales from the project?
“- Are there any transmission restrictions that make spot, hour-ahead, or day-ahead sales more difficult? How cooperative is the relevant transmission owner? Can the pricing assumptions be supported by the transmission owner’s business culture and commercial objectives? What are the transmission owner’s rights with respect to the project’s interconnection with the grid? How do these rights affect the dispatchability and maintenance of the project? How are financial transmission rights assigned, allocated or auctioned?
“- Are there contractual or equipment limitations that affect dispatch assumptions? Pricing, operational, dispatch and fuel supply assumptions should be evaluated against the limits and restrictions in the project agreements for electricity sales, interconnection, fuel supply, storage and balancing, warranties and long-term, O&M and water supply, and the technical limitations in environmental permits and other regulatory requirements. All of the project agreements and permits need to be properly aligned and evaluated against pro forma revenue and debt service assumptions.
“- Is there a short-term or long-term financing play that can increase value? Can the project’s leverage be enhanced with portfolio subordinated debt?
“- Will there be future opportunities in profit operations to sell new products from the asset? Will a market for ancillary services develop and be competitive? Emission credits? Is the asset entitled to sell such services or have they been committed to another party? Are there new and different equipment configurations that generate products that respond to market demands? What project expansion rights are available? Is any additional capacity of the project committed, or would it be available for sale free and clear? How is the option for additional capacity to be accounted for under new FASB requirements?
“- Are there cost reduction opportunities in project operations that can enhance value? Are there alternative fuel supplies available, or which could be available with additional investment? How is the fuel transported? Are storage and freight costs involved? Does the project have an option to increase its fuel supply requirements? How is the fuel supply option to be treated for accounting purposes?
“- Can significant benefits be derived from restructuring power purchase arrangements? Tax structuring. Are there statutory incentives for a power purchaser to agree to restructure its power purchase obligation to provide more power-sourcing flexibility to the project? Will fuel supply and any cogeneration product sales be implicated in any restructuring?
“- What is the insurance profile of the asset? Is additional coverage required? Are rising insurance costs accounted for in the pro forma modeling?
Zimmer is an international partner in the energy and major projects practice groupin the Washington, D.C. office of Baker & McKenzie. He can be reached at 202-452-7055 or by e-mail at Michael.J.Zimmer@bakernet.com
Desai is a senior associate in the energy and major projects practice group in the Washington, D.C. office of Baker & McKenzie. He can be reached at 202-452-7057 or by e-mail at Samir.S.Desai@bakernet.com