In Search of Transmission Capitalists
April 1, 2003
By Elliot Roseman and Paul De Martini
Facing a cash crunch, transmission owners look for new funding sources.
In recent months, discussions about the shortfall in transmission have touched on market structures and regulatory issues related to participant funding, nodal pricing, independent transmission companies (ITCs), multi-state entities, and the role of standard market design (SMD). However, with much more investment in transmission required now than in the past, the major issue is finding money for transmission expansion. This is the essence of the capital expenditure ("capex") problem that persists currently in the industry.
Transmission financing is on the verge of dramatic change, with funding in the very near future coming from several sources that may surprise you.
Financing Sources
Of the three principal types of transmission investment, most utilities in recent years have focused with regard to transmission investment on retrofits-modest improvements to existing lines, transformers, operations, and rights of way to ensure the continued reliable flow of power from utility-owned power plants to their customers. Occasionally, the utility might need to upgrade (e.g., double-circuit) a line to enhance reliability and increase the flow of power, but such need is infrequent. Transmission was developed primarily to ensure reliability, rather than to support commerce.
But times have fundamentally changed. Now, on top of the foundation of retrofits, there are increasing amounts of transmission upgrades and expansions required, both for reliability purposes and to support many more transactions. With the formation of regional transmission organizations (RTOs) and regional planning, substantial expansion will need to take place to better interconnect within the traditional service territory, between utilities, and between regions (i.e., intra- and inter-utility). The goals of eliminating congestion and supporting access to lower-cost wholesale power supplies will become of co-equal importance to reliability. Acquisitions of transmission assets are becoming more common. How utilities will shift transmission asset ownership and raise capital to satisfy this new picture is a major challenge for the power industry. Figure 1 shows this anticipated shift.
Investment Need
The ability to make necessary investments in transmission is clearly in doubt,1 with potentially substantial consequences for market participants and consumers. But there is hope of filling the capex gap as well. In that context, the first issue that must be addressed is whether there is a significant need for new transmission investment. The answer? Absolutely.
- Congestion in the most developed market, PJM has quintupled in the past two years, reaching $271 million in 2002. Nationwide, the figure is well into the billions. Thus, the wholesale cost of power today is already several percentage points higher than it would be without congestion.
- According to the North American Electric Reliability Council, unfulfilled transactions (TLRs) have increased five-fold to nearly 1,500 instances in 2002, compared with 300 in 1998. For example, the ability to move power out of Entergy has fallen from 6,000 MW to 1,000 MW or less in the past three years because generation additions have not been matched by transmission investment.
- According to an Edison Electric Institute (EEI)-sponsored study in June 2001, transmission investment has fallen $115 million per year for 25 years, from about $5 billion in 1975 to $2 billion in 2000 (in 1997 dollars).2
- The same study identified the nationwide need for at least $56 billion in new transmission investment over the next decade.
- At present, PJM, New England, and New York can transfer only five to 10 percent of their peak loads between them, far less than needed to support an open regional power market.
- Southern Co. alone anticipates $2 billion to $3 billion in transmission investments, nearly doubling its current asset base.
Further, as discussed below, the new resource planning procedures that FERC wishes to implement through RTOs, and the need to encourage commerce as well as reliability, will require even more of a focus on transmission investment. A mix of generation, transmission, and load response will satisfy the need for new resources in the future, but regardless, the share of the pie dedicated to transmission will increase.
How much more investment is required? The net book value of transmission in the United States is about $40 billion among investor-owned utilities, and perhaps $60 billion including public utilities. Given the renewed focus on system expansions and new investment in addition to retrofits, it would not be surprising to see this amount rise by $30 billion to $60 billion during the next decade, even taking siting challenges into account, especially if one includes the acquisition of existing systems. This is a huge increase in capital allocated to this segment of the power industry.
Utility Finances: Shaky at Best
Given a burgeoning and critical need for new transmission, are utilities prepared to make such substantial investments in transmission? Not at all. Traditionally, utilities raise capital from three sources: 1) internal cash flow; 2) bondholders; and 3) equity investors/shareholders. In each area, the available pool of capital is being depleted just when transmission needs the most investment and consumers would benefit the most from such new infrastructure. Utilities were once the paragon of investment safety, but according to a recent study by Standard & Poor's:3
- Bonds are unattractive. In 2002 there were an unprecedented 182 downgrades of utility holding and operating companies and only 15 upgrades, continuing 2000 and 2001 trends. A full 62 percent of electric utilities are just investment grade ("BBB") or below, while those rated "A-" or better fell from 51 percent to 38 percent in one year;
- Industry financing activity (debt and preferred securities) fell from $86 billion in 2001 to $74 billion in 2002. In the meantime, debt rose to nearly 60 percent of total capital in 2002 from 55 percent in 1998, affording bondholders less protection;
- Public equity is unattractive. According to Bloomberg, as of Feb. 14, the Philadelphia index of electric utility stocks had fallen 24 percent in one year;
- Internal funds are way down. Funds-flow interest coverage and pretax interest coverage have slipped, to 3.3x and 2.8x in 2002, from 3.9x and 3.1x in 1998; and
- The poor performance of non-utility divisions has had a substantial negative impact on utility investors and customers from deferred equipment and maintenance expenditures. Largely due to such ventures, more than $25 billion in debt is coming due in 2003, without much revenue to show for it.4
Thus, the ability of utilities to fund transmission investments from traditional sources is seriously compromised, with few prospects for near-term improvement. In such a climate, utilities tend to focus on those transmission investments necessary to keep the lights on (i.e., retrofits) but not much more.
Some utilities (e.g., American Transmission Co. and TransLink) have formed ITCs and separated transmission, both financially and structurally, from the rest of the utility. This is a positive development for raising capital, since ITCs have a clear focus on transmission, regulated rates, and separation from other potentially volatile segments of the utility. Whether through ITCs or standalone transmission firms, a sole focus on transmission will enable such companies to find better ways to operate, increase throughput, manage risk, identify investments, raise capital, and handle regulatory issues. We expect significant consolidation of the ownership of the transmission business as a result.
In sum, public equity, debt markets, and bank financing have become less accessible to the electric industry for infrastructure capital. Given the shortage of utility financial options, there is likely to be a gap in utility capital available for transmission investment. Those utilities fortunate to have adequate access to capital markets may choose not to seek such financing to fund transmission projects, in an effort to preserve capital and share risks.
Non-Utility Sources of Capital to the Rescue?
If utilities are not going to fund new transmission, where is the capital going to come from? Answer: a wealth of new sources.
The areas of transmission in need of investment-the retrofit of existing systems to maintain reliability and capabilities; upgrades to enhance reliability and capacity of existing infrastructure; new expansion; and acquisition of transmission systems-overlay both intra-utility systems and inter-utility systems as outlined in Figure 2. Each area presents unique characteristics to financing capital investment and may come from different sources.
While utilities continue to focus on retrofits, current third-party transmission financing in North America is primarily directed at upgrades and expansion projects. Compared with retrofits, these projects are more discrete, tangible assets, with defined revenue streams, and therefore better investment targets for such investors. For example, many of the projects under consideration for private investment involve point-to-point system interconnections and high-voltage direct-current lines.5 Third-party investors tend to prefer such specific assets to readily distinguish their returns from the utility as a whole, though other options may develop. Acquisitions clearly have the opposite focus, since they seek a revenue stream from the transmission asset base as a whole.
How will these investments be financed? Not surprisingly, discrete asset projects will tend to use project-financing techniques, while projects involving new assets that are integral to the existing asset base will primarily use corporate finance. For example, transmission insulator retrofits likely will involve traditional utility corporate financing from internal cash flow or new capital from equity and/or debt. However, this may change if early private investment in more discrete transmission projects proves successful. Transmission systems recently acquired by private entities will use a mix of private and public finance to fund retrofits on their systems, likely taking the form of corporate rather than project investment.
New transmission upgrade and expansion projects are currently seeking capital from private equity and debt financing sources. Electricity infrastructure projects involving transmission hold the potential to attract investors seeking investments with a long economic life and relatively stable and regulated returns. According to private sources, there are several billion dollars available for new transmission investments for the right opportunities.
We believe that some of these sources of capital will be quite new to the utility industry and to transmission in particular. Some will be passive investors, while others will seek an active management role. For example:
- Transmission-only companies (e.g., Trans-Elect, TransLink) will serve as project developers, managers, and investors;
- Engineering, construction, and O&M firms (e.g., Bechtel, Black & Veatch) will be seeking project-related contracts in exchange for their capital commitments;
- Equity investors (e.g., investment firms such as KKR and Berkshire Hathaway, and asset managers such as Trimaran) will seek management fees and capital appreciation;
- Pension and university endowment funds (e.g., Canadian Teachers Fund, CALPERS) will primarily seek stable returns, long-term capital preservation, and growth; and
- Sources of structured finance (e.g., AIG, GECC) and other partners will seek stable cash flows and attractive returns.
This unprecedented expansion of the pool of capital available for transmission will require entirely new transactions and project structures, as transmission owners try to blend traditional corporate and public finance with project-oriented, private sources. This expansion is the best near-term hope for filling the capex gap. Partnering with utilities makes sense, for the regulatory and rights of way reasons cited above, but new sources will provide the engine for transmission system upgrades, expansions, and acquisitions.
These investments can take many of the same forms applied to independent power plants and gas pipeline projects over the past 20 years. The basic vehicles are: a) private equity investment though partnerships or corporate structures involving preferred and/or common stock; b) project or corporate debt financing on a non-recourse or asset-backed basis; and c) leases involving the project/corporate transmission assets. There are many permutations to the applications in structured finance today that may be applied to new transmission investment.
The application of these financing techniques depends on the alignment of capital needs, investors' interests and objectives, and the transmission owners' and developers' business priorities. However, based on commentary by the financial community in FERC's recent conference on capital availability, it appears that those projects or acquisitions that have long-term stable revenue opportunities through regulated rates or contractual arrangements with load-serving entities, IPPs, and other market participants are more likely to obtain funding. The sidebar, "Transmission & Private Equity: Doing the Deal" (p. 24), describes the structure of several such recent deals. Merchant-type projects face more challenges for funding in today's financial environment. In this sense, the situation with transmission is no different than the situation facing domestic power plant development.
Regulatory Change: Helping or Hurting?
Will regulatory developments improve the transmission picture, and if so, will it be soon enough? There is a blizzard of regulatory change taking place that affects transmission, but with regard to encouraging transmission investment, the picture is decidedly mixed. FERC's intent is that the formation of regional transmission organizations (RTOs) and the implementation of SMD will help address the shortfall in transmission in the process of fostering more competitive wholesale markets. RTOs are expected to encourage appropriate transmission investment in at least five ways: ensuring open grid access; objectively calculating available and total transmission capacity; conducting interconnection studies for new generators; sending nodal pricing signals; and working to reduce congestion and increase the flow of power across regional "seams." SMD, if implemented, would be a substantial catalyst for new transmission, since it would put in place a resource planning process to identify what mix of resources, including transmission, should be added, and conduct competitive bids to put that mix into effect. Thus, RTOs and SMD could have a substantial impact on transmission investment, but the impact of these changes will take time and will roll out only in selected areas in the next few years.
Regulation also can provide a financial boost. For example, on Jan. 15, 2003, FERC issued a pricing policy for transmission that would grant incentives for several activities: 50 basis points in return on equity (ROE) for joining an RTO; 100 basis points for new transmission investment approved as part of an RTO planning process; and 150 basis points for forming an ITC. This policy, if adopted, would raise the return on equity for transmission to between 14 and 15 percent using traditional leverage, and to the high teens with a more leveraged investment, a level that can appeal to a new class of investor. FERC has offered sweeteners on specific transmission deals before, but not in a generic manner. This positive step toward encouraging transmission needs to be fine-tuned, but it sends the correct signal that FERC recognizes the need to encourage transmission investment as a market facilitator, and capital from non-traditional investors.
Also, some RTO-specific decisions are encouraging transmission investment. In its Dec. 19, 2002, decision approving PJM as an RTO, FERC required PJM to evaluate merchant transmission on a co-equal basis with utility-based investments in its planning, thus opening a door to new sources of equity. Further, that decision-for the first time-specified that RTOs must consider commercial factors just as much as reliability in deciding what resources should be added. This departure from the traditional focus on "keeping the lights on" is a critical shift. Taken together, these are two important precedents that FERC will likely impose on other RTOs as they form.
So, will regulatory changes lead to the right level of investment in transmission? In each region, the utilities, NERC, and the fledgling RTOs and ITCs are in the process of identifying the specific lines and other transmission investments required to meet the new market requirements. However, there are a lot of details to work through before we know whether FERC's regulatory vision will be effective in getting sufficient transmission built. If we rely only on the evolving regulatory process to foster the market conditions that will support substantial transmission investment, we are likely to fall short, both in dollars and in the timing of such investment.
The benefits of new transmission would far outweigh its costs, especially if those investments are well targeted. Transmission shares one major feature with an insurance policy-having too little is a major risk. Perhaps there should be a national debate and a national transmission summit, at which market participants could focus attention on the impediments, incentives, opportunities, and benefits that are possible from "getting transmission right." It is possible to solve the transmission capital expenditure problem in the relatively near term, but only with new deal structures and new sources of capital.
Elliot Roseman is a principal with ICF Consulting, Inc. in Fairfax, Va. He can be reached at (703) 934-3859 or eroseman@icfconsulting.com. Paul De Martini was a vice president with ICF and recently joined an investor-owned utility.
Transmission & Private Equity: Doing the Deal
The following examples, drawn from public announcements of recent investment, illustrate how private financing is playing a role in the development of transmission.
California Path 15 Upgrade6
Path 15 upgrade is a project to de-bottleneck an 84-mile stretch of electrical transmission lines in the California Central Valley. The new 500-kV line will cost about $300 million, with an expected operational date in summer 2004.
Trans-Elect Inc. is partnering with the Western Area Power Administration (WAPA) and Pacific Gas & Electric Co. (PG&E) to design, build, and finance the project. Trans-Elect has a 72 percent share of the Path 15 project and is responsible for sourcing project financing. WAPA has a 10 percent share and has project-manager and land-right acquisition responsibilities. PG&E has the remaining 18 percent share and is responsible for substation construction. Equity will come from Trans-Elect (82 percent) and PG&E (18 percent). Trans-Elect is expecting its equity participation to combine with funds from GE Capital Services Structured Finance Group Inc. Project debt financing reportedly will be from one or more financial institutions, arranged by Macquarie Corporate Finance (USA).
Project Neptune7
Neptune Regional Transmission System LLC (NeptuneRTS) is a proposed HVDC undersea cable transmission system providing 1,200 MW of new transmission through two planned links between New Jersey and New York. One cable will connect New York City with Sayreville, N.J., while the second cable will connect Long Island to Sayreville. The project is expected to cost $500 million and take two years to construct. In 2001, Neptune RTS received FERC approval of its merchant-based tariff in anticipation of revenues and returns based on market demand for access between PJM and New York.
DTE Transmission Acquisition8
DTE Energy is selling its transmission business subsidiary, International Transmission Co. (ITC), to a partnership of Kohlberg Kravis Roberts & Co. (KKR), a private investment firm and Trimaran Capital Partners LLC, a private asset management firm, for approximately $610 million in cash.
The ITC system comprises nearly 3,000 miles of high-voltage electric transmission lines and associated facilities and easements. ITC currently serves the LSE requirements of Detroit Edison and will continue to provide service under a proposed transmission rate cap charged to Detroit Edison's customers until Dec. 31, 2005. Future rates will be subject to adjustment by FERC. ITC contemplates the electric transmission system will continue to be operated by the Midwest Independent System Operator. KKR and Trimaran intend to provide additional investment in ITC to support retrofits, upgrades, and expansions. -E.R. & P.D.
Many Paths to the Solution: The ABCs of Transmission Building
A combination of techniques could achieve the goal of sufficient investment in transmission.
A. An increasing share of new investment in transmission needs will come from non-traditional sources, including equity investors, institutional investors, and standalone transmission companies. Utilities and ITCs will need to become more skilled at orchestrating this group of potential capital sources, targeting the investment opportunities to different entities.
B. More utilities will decide that transmission is not in their strategic interest and will sell or contribute their transmission assets to ITCs and private transmission firms.
C. Transmission costs will rise to cover the new investment required, but overall, customers' bills should be lower as a result. Since transmission is about 10 percent of the system, even a 20 percent increase in transmission investment would increase retail rates by just 2 percent. However, overall rates would be reduced through reducing congestion and lowering wholesale costs.
D. Regulators will need to make a meaningful contribution. Developments on the RTO, ITC, financial incentives, and resource planning front hold the promise that transmission will gain a higher profile and lead to more investment, but the timing of this contribution is uncertain. There also should be a resolution of the participant funding issue, which could hamstring transmission as it has done in recent years.
E. The federal government could decide that transmission is a priority too important to be left to the vagaries of the market, especially for certain high-voltage, highly congested lines. Whether for national security or economic reasons, the administration could decide to sponsor (through direct investment, federal bonds, or competitive bids) the development of specific lines that will achieve its purposes, while also serving as a catalyst for investment.
F. Finally, there could be an outside event that stimulates transmission investment. While obviously undesirable, a major outage of the type experienced in 1965 in New York State that cascaded through much of the Northeast could provide the spark for a "Marshall Plan" to develop and strengthen the grid. -E.R. & P.D.
Endnotes
- The investment required is not just in new high voltage wires, though that is a significant component. The industry also needs new substations, transformers, reconductoring, switches, and more, all working in tandem to increase the efficiency of the system and support the movement of power both within and between regions. New technologies (e.g., FACTS, super-conductivity) that enable more power to be transmitted through existing lines and rights of way require funding as well.
- Eric Hirst and Brendan Kirby, "Transmission Planning for a Restructured U.S. Electric Industry," June 2001, p. 9.
- Barbara Eiseman and Kevin Beicke, Standard & Poors, "U.S. Power Industry Experiences Precipitous Credit Decline in 2002; Negative Slope Likely to Continue," Jan. 15, 2003. The study also cites the major reasons for such downgrades, which include growing debt finance outside of the utility industry; regulatory difficulties; weakening of bondholder protection fundamentals; and constrained capital markets.
- Rebecca Smith, Wall Street Journal, "Beleaguered Energy Firms Try to Share Pain With Utility Units," Dec. 26, 2002, p. 1.
- One current exception to this trend is the Path 15 project in California, an upgrade to an existing intertie line, with Trans-Elect leading the sourcing of capital. The success of this project may prove to be a case study for other upgrade projects in terms of identifying discrete assets, in this case a new line segment, sourcing and structuring non-utility financing.
- Data from Trans-Elect Inc. corporate Web site.
- Data from Neptune Web site and press releases.
- DTE Corp. press release, Dec. 3, 2002.
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