Forecasting Equity Returns for Merchant Power

Project developers are paying premium prices for the most advanced technology gas turbines.  Is improved heat rate worth the cost?  This presentation will examine the marginal economics based on market price forecasts in different regions of the country.  We will also examine whether the existing competitive market frameworks give proper recognition to quicker start-up times, improved ramp rates, and other performance characteristics.

• Under what conditions would you pay a premium for performance?
• What are your competitors ordering and why?
• How much freedom under your air permit cap do you need?
• Will ISO-NE's 4-hour daily market change your strategy?
• Is there an upper limit to efficiency, and what else can manufacturers improve?

The Repowering Option - Is it Suitable For Your Target Plant or Should You Deploy Another Development Tactic

Repowering is a strategy that successful companies always consider when bidding for existing plants.  The price competition for well-positioned older plants is so fierce that every opportunity to add or enhance value must be pursued.  Typically, repowering is defined as replacing an existing boiler with gas-fired combustion turbine-generators (CTGs) and heat recovery steam generators (HRSGs), while using the existing steam turbine-generators (STGs) along with the existing site infrastructure.  Repowering has the potential to:

• Improve cycle efficiency and operating flexibility
• Minimize permitting and construction downtime
• Reduce emissions
• Minimize investment cost

The challenge of repowering is to balance the savings in cost and schedule against efficiency limitations and reliability risks.  A new combined cycle plant can be thermodynamically optimized in ways that repowering cannot because of the existing STG configuration (e.g. steam inlet conditions, steam reheat potential, feedwater design.)

Equally important is the issue of STG reliability.  Investigating the condition of the existing STG prior to repowering is critical.  Any doubts concerning steam path components, rotor life, blade/nozzle integrity, and generator condition must be addressed.  At best, older STGs require more frequent inspections and overhauls tend to be longer and more expensive.  It may be cost-effective to replace the rotors with newer, more efficient designs,replace seals and other high-wear parts, reinforce stator windings, and other actions to improve the STG.  At worst, repowering plans may be scrapped and a new STG purchased if the improved cycle efficiency, the vendor's warranty, and the longer operating periods between major maintenance outweigh the incremental capital cost.

Cost and Security of Backup Power Supplies

Technology progress coupled with the landmark regulatory and legislative initiatives in many U.S. states and Canadian provinces herald the development of cogeneration for institutional power and thermal loads.  Institutional customers' renewed interest in inside-the-fence cogeneration can produce large reductions in total energy costs.  Energy savings are potentially greatest where market prices are linked to natural gas and oil, or where incumbent utilities have received regulatory approval to collect stranded costs through access charges.  In many parts of North America, regulatory commissions have begun to promulgate incentives to encourage "distributed competition."  In a classic tug-of-war, incumbent electric distribution companies (discos) are crafting new service terms through changes in rate structure.  These new commercial terms will potentially increase materially the cost and risk related to "leaning" on the local cables for supplemental energy or backup service.

Favorable cogen economics for universities, colleges and hospitals have been around for decades.  One of the main commercial risk factors that makes the financial calculus hard to pin down is the formulation of a bankable estimate of backup power supply costs during intervals when the prime mover is down for scheduled or unscheduled maintenance.  While plant availability factors for small-scale cogens may exceed 90%, periodic reliance on incumbent discos for backup power can play havoc with the project financial pro forma, cutting significantly into the expected payout envisioned through cogen.  Preoccupied with customer migration and spiraling per-customer charges, many discos have begun to implement punitive backup power rates that can diminish the lion's share of the gains realizable through inside-the-fence cogen.  Rigorous evaluation of the costs to secure a secondary source of electricity when a gas turbine or diesel engine is unavailable is therefore an integral component of the evaluation process.

This paper addresses how an institution can safeguard its commercial interests under three scenarios: (i) purchasing all power from the market, (ii) self-generating the majority of the energy requirements with reliance on the disco for supplemental energy and backup services, (iii) "islanding" the institutional campus in order to avoid any periodic reliance on local wires.

The Impact of Regulation, Unbundling, and Regional Transmission Groups on T&D Value

Deregulation has transformed the electric utility industry from a low-risk to high-risk enterprise.  There has not been this much uncertainty in the power business in over 75 years.  Competition is inexorable.  It has swept across the U.S. as is moves down the supply-chain from the generator-bus to the customer's meter.  There remain a few pockets of utility and legislative / regulatory resistancewhere the old-style rate base paradigm controls how energy prices are set, capital is attracted, and service reliability is sustained.  But, for the most part, utilities with significant stranded cost liabilities can't resist the transition to retail choice.  Divestiture, of course, has been the quid pro quo for stranded cost recovery.  Once the incumbent's generation assets are divested, the leftover "wires" franchise represents an irresistible target for global utility investors.

Intense competition among independent merchant generators occurs at the wholesale level while marketers and energy service companies (ESCOs) slug it out for market share at the retail level.  In much of the U.S. as well as in England, Europe, Asia, Latin America and Australia, a consumer revolution has blurred the distinction between wholesale and retail service.  Valuing transmission (T) and distribution (D) assets necessitates the same rigorous assessment of commercial prospects, regulation, merger-induced synergies, and market structure as does valuation of generation assets.  While the modeling tools differ, the valuation principles are remarkably similar.

Pinning down the cash flows from T&D operations is in large part science, but no doubt necessitates a significant amount of art.  As more and more generation assets are consolidated in the hands of around eight global energy companies, there is a similar trend toward consolidation in T&D.  Generation, of course, is subject to the tyranny of the market.  T&D, on the other hand, remains regulated, and the regulation, at least for now, tends to be heavy handed.  Acquirers need to get comfortable with the "beta" risk associated with uncertain state and federal regulation of wires companies.

• Has the divestiture and securitization process effectively stripped out the risk that underlies the risk premium utility investors receive?
• How will the capital attraction standard work for wire companies? Will "real" yields materially decline commensurate with the perceived reduction in risk?
• Will transcos and discos be able to provide investors with satisfactory returns over the next five to ten years? Over the very long term?
• Should widows and orphans hold onto the stock of wires companies?

Sweeping generalizations in fledgling markets are dangerous.  As with any investment decision, thorough due diligence is a must.  In valuing T&D investment opportunities we start the due diligence process with a few basic questions:

• What is the outlook of the regional economy, including the demographics, the sustainability and growth of the industrial and commercial sectors, the extent of write-offs, accounts in arrears, and theft (in developing countries)?
• Can mergers and acquisitions (M&A) lead to available and achievable cost reduction opportunities via improved economies of scale, elimination of redundant operations, utilization of information technologies, reduction in cost of capital, or other means?
• Are revenue growth opportunities available and achievable including the leveraging of depreciated assets to compete aggressively in newer, high-growth, high-margin industries, for example, telecommunications bandwidth?
• What is the nature and status of the state regulatory environment including M&A precedent, ratemaking practices, and environmental requirements?
• Are transmission supply "curves" fixed or variable over time, that is, can investment in new transmission projects capture price basis differentials between or within markets?  Can transmission owners compete away from traders market inefficiencies otherwise realized through cross-commodity arbitrage?
• What is the nature and status of the transmission coordination structure including investment incentives, trading policies and oversight of market power?

Environmental Benefits Associated with Cogeneration and District Heating Systems

State-of-the-art technology can deliver a cogeneration system with district heating that is fuel efficient, cost-effective, and easily maintained. In addition to readily quantifiable cost savings, a modern cogeneration / district heating system can provide significant environmental benefits that will ease permitting, minimize the cost of complying with future environmental regulations, and as an added bonus, provide often overlooked public goodwill.

Significant environmental benefits are associated with the improved efficiencies offered by new generation technology, especially when used to cogenerate both electricity and thermal energy. Higher thermal efficiency leads to lower fuel consumption and reduced emissions of SO2, NOx and CO2. The net reductions in emissions can be especially dramatic when out-dated technology is supplanted by new equipment. This paper addresses how the commercial development of cogeneration systems that include district heating and chilled water can substantially reduce the net environmental impacts of meeting energy needs compared to the alternate available technologies.

Build v. Buy: New Commercial Benchmarks

Electricity deregulation has accelerated the rate of technology substitution in the electric energy sector, and it has also spawned new transaction structures that incorporate innovative risk management techniques.  In energy markets that have embraced retail choice, a "gold rush" mentality has gripped merchant generators who compete among themselves to achieve market share.  Several tens of thousands of new merchant power producers (MPPs) are proposed in New England, New York, the PJM, Texas and California.  In many other parts of the U.S., prominent energy development firms are racing to permit greenfield sites suited for advanced gas turbines with nameplates ranging from 250 MW to 1000 MW.  Very few transmission projects have been announced to date.  Other energy companies are acquiring the divested generation assets of the investor owned utilities that have struck favorable regulatory bargains permitting stranded cost recovery in exchange for divestiture.  In most instances, the MPPs that are competing for market share are attracting debt and equity on the basis of the structure of the long term energy market.  This market is one where the price of electricity is derived from the price of natural gas.

The market for energy is both commoditized and financial, that is, long term market clearing prices are essentially derivatives "plays" between gas and power at the highly efficient heat rates characterizing production from advanced gas turbines.  This means that lenders and investors are betting that the price relationship between natural gas and power at superior heat rates will permit the orderly return of capital.  This is a safe bet.  It is the linkage between natural gas and power that MPPs and the contracting parties must understand in order to be well positioned in the evolving fragmented commodity based energy business.

In this paper I explore the array of technological, market and financial considerations affecting how MPPs structure their transactions.  New transaction structures are discussed in the context of the commercial risk factors large end users should consider in the evaluation of strategic energy options. The primary areas of inquiry are as follows:

• Does outsourcing of the energy procurement function confer significant economic benefits? What are some of the key risk factors that should be considered in making the decision to outsource?
• What are the financial and performance benchmarks affecting merchant plant performance?  How do these benchmarks impact the transaction structures for MPPs and end-users who sell or purchase their energy through bilateral or market indexed prices?
• What are some of the second-tier commercial considerations that may undermine the timely realization of economic benefits under the new transaction structures?

Alternatives to Ammonia Dependent NOx Control Technologies for Cogeneration and DHC Applications

Concerns regarding the exposure of millions of Americans to high ambient concentrations of ground-level ozone have brought about increasingly stringent NOx emissions limits for both new and existing energy facilities.  In response to these emissions standards, selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) are being widely implemented to control NOx emissions.

SCR and SNCR, while effective in controlling NOx emissions from power and steam generation facilities, require the use of ammonia, or a related reagent such as urea to achieve the necessary levels of NOx reductions.  Ammonia storage and handling can pose worker safety concerns.  Moreover, the SCR and SNCR systems currently in commercial operation emit small amounts of unreacted ammonia into the atmosphere (often referred to as ammonia slip).  In this regard, the U.S. Environmental Protection Agency (EPA) and a number of state and local agencies are seeking to encourage the use of alternatives to ammonia-based control technologies.  In some instances these regulators are contemplating restrictive standards dealing with ammonia emissions, worker exposure to ammonia and the safe storage of ammonia.

This paper will provide a summary review of the technological maturity and comparative economics of three technologies considered to be commercial or near commercial alternatives to ammonia-based NOx emissions control technologies: catalytic combustion, catalytic oxidation/absorption and natural gas reburning.  The costs and relative performance of alternative technologies will be described, along with the trends and driving forces affecting the implementation of increasingly stringent NOx emissions limits.  The implications of recent regulatory initiatives, such as in Massachusetts, dealing with ammonia slip from NOx control systems will also be considered.

Monetizing Key Value Drivers in Utility Generation Auctions

Across the U.S., generation asset divestment has been the quid pro quo for recovery of stranded costs.  The so-called irrational exuberance that has gripped investors is founded on the very rational enthusiasm of the sellers.  Through the third-quarter 1998, asset sales over of 25,000 MW have been announced.  Over $8 billion has changed hands or is about to change hands.  Another 34,000 MW of additional generating capacity is currently available for sale.  Most generation asset divestitures have occurred in the premium priced New England and California markets-regions with massive deadweight costs comprised of uneconomic generating plants, PURPA contracts, nuclear power plants, out-of-the-market fuel contracts, and sundry regulatory obligations.  The bidding in New England has been particularly torrid.  Divestitures in Pennsylvania, New Jersey, New York, and Montana have followed these regions.

In this paper, I will explore how buyers and sellers have valued generation assets.  Emphasis is placed on the monetization of certain intangible value drivers that have fostered the "blue-sky" valuations that often separate winners from losers.  Chief among these hard to pin down variables are: optionality, that is, the ability to add large increments of new capacity through repowering of existing fossil assets or the exploitation of site economies; ancillary services, that is, recognition of transmission services that foster grid stability; environmental currency, that is, the sale of credits or allowances; and, perhaps most importantly, risk management.

A Business Perspective on the Competitive Transition of the Electric Utility Industry

The traditional model of electric utility regulation encompassed three functions: generation, transmission, and local distribution.  Normally these functions were consolidated into a single entity.  Regulation of the industry was justified on the basis that electricity generation, transmission and distribution were natural monopolies; to achieve scale economies and avoid wasteful duplication of services, the selection of a single firm to provide service would best satisfy the public interest and necessity.  Whereas the conventional regulatory compact shielded practically all power generators and utilities from the prospect of bankruptcy, under the new deregulated system, market forces will set prices for generation services.  The wires function will remain regulated, however as regulatory and market risks facing both transcos and discos is muted.  ISOs and PXs are designed to be not for profit; as such there are no reasonably foreseeable circumstances that would cause regional ISOs or PXs to reject contract obligations.  On the other hand, the vagaries of the market will be directly felt by gencos and the various marketers, aggregators, brokers and traders.  While gencos may effectively manage market uncertainties through equity capitalization, other industry participants who trade electricity in different regions of the country may not be adequately capitalized to meet their obligations.