Demande R-3738-2010
RÉPONSE DU TRANSPORTEUR À L'ENGAGEMENT 13
(DEMANDÉ PAR EBMI)
Original : 2010-12-02
HQT-14, Document 3.13
(En liasse)
Demande R-3738-2010
Engagement 13
(demandé par EBMI le 2010-11-30)
Fournir le rapport produit par le docteur Makholm (troisième avant-dernier de la
page 4 de son curriculum vitae).
R13 : Voir les pages suivantes.
Original : 2010-12-02
HQT-14, Document 3.13
(En liasse)
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NATIONAL ECONOMIC
RESEARCH ASSOCIATES
Consulting Economists
200 CLARENDON STREET
BOSTON, MASSACHUSETTS 02116-5089
TEL: 617.621.0444 FAX: 617.621.0336
INTERNET: http://www.nera.com
DOCKET NO. OA08-13-000
AFFIDAVIT OF JEFF D. MAKHOLM, PH.D
On behalf of
Consolidated Edison Company of New York
January 7, 2008
Brussels, Belgium / Boston, MA / Chicago, IL / Ithaca, NY / London, UK / Los Angeles, CA / Madrid / New York, NY
Philadelphia, PA / San Francisco, CA / Sydney, Australia / Washington, DC / White Plains, NY
An MMC Company
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULTORY COMMISSION
New York Independent System Operator, Inc.
Docket No. OA-08-13-000,
Order No. 890 Transmission Planning
Compliance Filing
AFFIDAVIT OF
JEFF D. MAKHOLM, PH.D
Dr. Jeff D. Makholm declares:
1. I have personal knowledge of the facts and opinions herein and if called to testify could and
would testify completely hereto.
I.
Purpose of this Affidavit
2. On December 7, 2007, the New York Independent System Operator (NYISO) submitted a
transmission planning compliance filing for Federal Energy Regulatory Commission
(FERC) Order No. 890. The compliance filing, in Attachment I (described as “Attachment
Y” New York ISO Comprehensive System Planning Process), described significant
revisions to the NYISO tariff regarding the procedures for analyzing and funding of what it
calls “regulated economic transmission projects” in Section 15.1 of Attachment Y (which I
will call “economic transmission enhancements”). Economic transmission enhancements
are those designed to alleviate transmission constraints, and reduce congestion but are not
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-2required to maintain system reliability by the Independent System Operator (ISO), as such.1
I have been retained by Consolidated Edison Company of New York (Con Edison) to
review aspects of those revisions and to present the advantages of alternative proposals.
3. I comment on a number of aspects of the revisions to the NYISO tariff. My comments
relate to definitional questions, empirical issues associated with the proposed benefit/cost
test and governance issues associated with how projects will be eligible for approval and
cost allocation among the ISO load members.
a. The definition of the “benefits” related to the costs of economic transmission is clearly
enough stated in NYISO’s proposal. The NYISO states that the benefits of a proposed
economic transmission project are defined as the lower net overall resource cost of
generating electricity. There remains, however, the issue of whether those benefits, so
defined, will entirely accrue in lower net load payments across the NYISO. A change in
load payments is an additional valid perspective from which to examine a project—and
an important one from the perspective of those who will pay the cost of what will
become a regulated transmission asset. For this reason it is important to provide the
results of a second test, or a “load payment savings test.” These twin tests, in
combination with the voting scheme for beneficiaries of an economic transmission
1
Some writers on the subject of transmission enhancements have commented that economic and reliability-based
transmission projects are fundamentally interdependent, in that they both affect economic decisions in the
competitive generating market (see Joskow, P.L., “Patterns of Transmission Investment,” Working Paper, MIT
Center for Energy and Environmental Policy, March 15, 2005). I agree with Joskow regarding that type of
market interdependence. But the split between economic and reliability-based transmission projects envisioned
by Order No. 890 is not so much related to that economic interdependence as to the separate governance and
payment structures specified for those two definitions of electricity transmission.
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-3upgrade, would fulfill the purpose of allowing those load serving members to determine
whether the project’s cost is acceptable to them.
b. The NYISO’s proposed analysis period for prospective economic transmission projects
has various interrelated problems. The first is the study period associated with both cost
allocation eligibility and beneficiary designations, which stretches well beyond any time
horizon for which benefits, however defined, can reasonably be known. The NYISO’s
proposed horizon for evaluating benefits (10 years from a project’s in-service date)
reaches forward to a time when those benefits are highly speculative in relation to the
transmission construction and operation costs. I propose a shortened period for
analysis, where there is a better prospect that any benefits from economic transmission
enhancement projects will come to pass. Being mindful of the uncertainties associated
with projected benefits is consistent with the notion that regulated cost recovery
mechanisms should pass a stringent test when they serve to complement a competitive
generating market.
c. The NYISO’s proposed treatment of costs is also a problem, for it deals with only a
portion of the capital costs of transmission projects. The NYISO proposal is to match
10 years of project costs with 10 years of benefits. But under traditional cost-of-service
principles, including amortization over the full 30-40 year life of the project, much of
the cost of a transmission project is still to be recovered after year 10. For the later
period, the amortized transmission costs are well known while any benefits from an
economic transmission enhancement project will be manifestly speculative. It is not
hard to see why those who might pay for economic transmission enhancement projects
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-4could object to leaving these known costs out of an initial benefit/cost analysis. Rather
than leave much of the capital cost out of the analysis, I propose to include it all.
d. The NYISO is, as much as anything, a governance structure to effect joint planning and
cost allocation for those elements of reliable and reasonably economical electricity
supply that cannot be left to the market. In this respect, with modifications, the
NYISO’s proposal reasonably fulfills the requirements of Order No. 890. In particular,
the NYISO’s proposed voting mechanism gives those targeted for the payment of
economic transmission enhancement costs a proportional vote in deciding its adoption.
In addition, the NYISO’s proposal for an 80 percent super majority threshold for
approval is helpful. It means that over four-fifths of those who will pay the allocated
costs will have to agree to the economic transmission enhancement proposal for it to
pass. I support the stringency of such a test for jointly-funded, cost-of-service
regulated, economic transmission enhancement projects.
4. I address each of these issues in the following sections of my affidavit. Following a
discussion of my qualifications in Section II, I describe in Section III the context for
electricity transmission that makes such complex governance structures for electricity
transmission enhancements unavoidable. In Section III, I discuss the concept of economic
transmission enhancements. Section IV deals with the definition of benefits, and Section V
deals with the time frame for measuring them. Section VI discusses the perils of fuel price
forecasting as a component of benefits. Section VII addresses how to assess the cost of
economic transmission projects. Finally, in Section VIII, I discuss the NYISO’s voting
proposal.
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-5-
II.
Qualifications
5. I am a Senior Vice President with National Economic Research Associates (NERA).
NERA is a firm of consulting economists with its principal offices in a number of major
U.S. and European cities. My business address is 200 Clarendon Street, Boston,
Massachusetts, 02116.
6. I have M.A. and Ph.D. degrees in economics from the University of Wisconsin, Madison,
with a major field of Industrial Organization and a minor field of Econometrics/Public
Economics. My 1986 Ph.D. dissertation at Wisconsin is entitled “Sources of Total Factor
Productivity in the Electric Utility Industry.” I also have B.A. and M.A. degrees in
economics from the University of Wisconsin, Milwaukee. Prior to my latest full-time
consulting activities, I was an Adjunct Professor in the Graduate School of Business at
Northeastern University in Boston, Massachusetts, teaching courses in microeconomic
theory and managerial economics.
7. My work as a consulting economist principally involves the area of regulated industries—
both those that operate networks (such as electricity transmission and gas/oil pipelines,
electricity and gas distribution systems, telecommunications networks, water utility systems
and rail/subway lines) and those operating infrastructure business at specific sites, such as
airports, electricity generation plants, gas processing plants, oil refineries and sewage
treatment plants. In such industrial settings, I have researched and given evidence
regarding regulated pricing, the presence of absence of market power, competition, the fair
rate of return, regulatory rulemaking, incentive ratemaking, load forecasting, least-cost
planning, cost measurement, contract obligations and bankruptcy, among other issues.
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-6Since 1981, I have prepared expert testimony and statements, and I have appeared as an
expert witness in many state, federal, and United States District Court proceedings, as well
as in regulatory and court proceedings abroad.
8. I have also directed studies on behalf of utility companies, governments, and the World
Bank in many countries. In these countries, I have drafted regulations, established tariffs,
recommended financing options for major capital projects and advised on industry
restructurings. I have also assisted in the privatization of state-owned utilities and have
been a witness in international arbitrations under international investment treaties regarding
the expropriation by national governments of utility assets. As part of my international
work I have conducted formal training sessions for government, industry, and regulatory
personnel on the subjects of privatization, pricing, finance and regulation of the regulated
industries. I have published articles in publications such as Public Utilities Fortnightly,
Natural Gas, The Electricity Journal and speak frequently at national and international
economic conferences regarding regulatory issues.
9. I provided live testimony before the FERC in its 1998 Public Conference on ISO’s in
Docket No. PL98-5-000 on behalf of the Edison Electric Institute (as part of the panel on
ISOs and transmission pricing). I subsequently provided a paper to the FERC in 2000 on
behalf of the PJM Transmission Owners regarding their transmission enhancement proposal
as part of the PJM’s Order No. 2000 compliance filing. In 2001, I provided an affidavit on
behalf of members of GridFlorida, regarding their transmission pricing plan, as part of its
own Order No. 2000 compliance filing.
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-710. My curriculum vitae is attached hereto.
III.
The Concept of Economic Transmission Enhancements
11. An economic transmission enhancement project is defined as one that will alleviate a
transmission constraint and reduce congestion, but is not considered necessary to eliminate
a reliability-based need.2 From an economic perspective this definition is somewhat
artificial, and the line between “economic” and “reliability” transmission enhancements is
not a sharp or obvious one. But a workable distinction has developed in Order No. 890 for
the planning and governance of transmission enhancements.
12. “Reliability transmission” is designed to satisfy a Regional Transmission
Operator/Independent System Operator’s (RTO/ISO(s)) criteria for assuring adequate
connections between electrical load and available energy supply from power plants. In most
instances the reliability transmission will be sufficient enough to allow for the economic
flows of energy supply by taking advantage of the existing reserve capacity on the RTO
system. As load declines in the shoulder periods, generation in higher cost areas is
dispatched downward or off-line, and the generation in lower cost areas is dispatched above
the local demand level, utilizing the reliability transmission to supply the otherwise higher
cost area. However, the reliability transmission may not always be able to accommodate
the least cost dispatch of the region’s generation resources, leading to the divergence of
wholesale electricity prices in one area versus another (i.e., congestion).
2
Congestion, for its part, is defined as the event where one or more transmission lines are filled to capacity leading
to price divergence between two market areas.
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-813. Relieving transmission congestion is not solely a question of building new transmission
capacity, however. Transmission congestion can also be alleviated by development of
generation or consumption efficiency projects on the constrained or “high side” of an
interface. Such development of new competitive generating resources can provide the
equivalent reduction in transmission congestion. Some congestion costs, however, cannot
reasonably be eliminated as an economic matter. In some cases, for some periods, the cost
of producing electricity is just higher. Since a minimum amount of local resources may
always be needed to support reliability, there may be some level of permanent congestion
costs during some hours that are unavoidable as a matter of overall economic efficiency.
14. Given the interdependence of generation, transmission, and load, economic transmission
enhancements serve in general to alleviate transmission constraints and prevent that
congestion-based divergence in wholesale electricity prices. For those paying the higher of
the divergent wholesale electricity prices, economic transmission enhancements have the
prospect of lowering their price of energy supply. But the reverse is also true—
transmission lines can cause the price of energy supply to increase on the other side of a
congested bottleneck as the existing generation supply is re-dispatched to higher cost points
on their incremental cost curves.
15. Indeed, this prospect that economic transmission enhancements will lower wholesale
power costs in a particular area is where the difficulty lies—and why Order No. 890 and the
various compliance filings are so complicated. For it begs the question: why, if additional
transmission could lower someone’s power costs won’t they simply agree to pay for it?
The problem, as anyone connected with the Order No. 890 process and its FERC
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-9antecedents knows well, is that electricity transmission is a unique sort of energy delivery
network. The physics of electricity means that in most cases it is not possible to track
electricity from particular producers to particular consumers—electricity goes where it will
over the network that exists. The creation of a market for generated power has not changed
the physics of electricity transmission.
16. Gas also goes where it will, in its own great FERC-regulated interstate network—after a
fashion. But it does so at such a relatively torpid pace (15 million times slower than
electricity) and with such predictable overall direction as to permit accounting and
commercial conventions to trace effectively an individual producer’s gas to a particular
consumer—even though for most of its journey, from the gas fields to the market areas, one
producer’s gas is totally intermingled with the gas of others. Those conventions and the
contract-based nature of the interstate gas transmission network (i.e., it is not a common
carrier), allow for a market in gas transmission not available to electricity transmission.
Interstate gas transmission in the U.S. is essentially “private carriage” for a sharply limited
clientele: those with capacity contracts.3 Such a commercial regime means that if a new gas
transmission pipeline (an “economic gas transmission enhancement”) could lower gas
prices for a group of consumers, they can readily band together and sign contracts to pay for
and build it—thus owning exclusive physical gas transmission rights to use or re-sell.
Economic gas transmission enhancements—the quintessential “merchant transmission”—
3
It is true that the FERC continues to regulate the rates of all interstate gas transmission companies. But because
of the manner of incrementally pricing the cost all new capacity additions, and also the secondary market for
such capacity, gas transmission capacity is essentially market priced both during the planning stage and in actual
operation.
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- 10 have been many, varied, and generally uncontroversial private matters in the restructured
gas market in the U.S. since around 2000.4
17. But such a commercial system does not apply to electricity transmission. Over a
considerable region, electricity transmission lines operate as a pooled resource with neither
the ability to predictably trace electricity flows nor the means for electricity consumers to
secure exclusive physical transmission pathways. Some cases do exist where electricity
transmission tends to look like “private carriage,” such as for high-voltage direct current
(HVDC) lines or controllable AC lines, or special connections such as a transmission line to
an island. But these cases tend to attract private investors and are uncommon solutions to
transmission bottlenecks. They are not where the contention lies regarding economic
transmission enhancements to the existing transmission grid like that overseen by the
NYISO and the subject of Section 15 of Attachment Y of its Order No. 890 compliance
filing.
18. The pooled, “common carriage” nature of existing large-scale transmission systems, like
that operated by the NYISO where exclusive physical transmission pathways cannot be
identified, defeats most private (i.e., “merchant”) transmission efforts. Like gas pipelines,
transmission wires represent a very long-term investment in sunken and immobile capital.
Motivating the sinking of such private capital for the interstate transmission of anything
requires extraordinarily predictable credit and payment commitments, which the current
4
The FERC still certifies new interstate gas pipeline capacity, but those certificate cases are comparatively tame
since the culmination in 2000 of the new rules governing contract carriage on the nation’s gas transmission
network.
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- 11 manner of operating and pricing the pooled electricity transmission network does not
permit.5
19. The question, as appropriately framed by Order No. 890, is when and how the pooled
transmission system operated by an ISO/RTO should cause its members to fund economic
transmission enhancements as regulated assets. Which is to ask: if the market cannot make
such investments privately without ISO/RTO planning and regulatory funding, how can the
NYISO provide for such investment and still reasonably tie the costs of the project to its
beneficiaries?
IV.
The Definition of Benefits
20. In various places in its filing, the NYISO discusses “benefits” or “beneficiaries.”6
Economic transmission enhancements imply by their very nature that, but for a transmission
constraint, less expensive power may displace more expensive power. Economic efficiency
is achieved any time this happens—fewer of society’s resources are consumed to produce
the same quantity of power. The NYISO defines its benefit metric for proposed economic
transmission enhancements as the “present value and annual NYCA-wide production cost
savings.”7 While this test is perhaps a more fundamental metric and may be the appropriate
5
For a discussion of both the financial and economic barriers to eliciting private (i.e., “merchant”) funding for
economic electricity transmission enhancements, see: Joskow, P.L., and Tirole, J., “Merchant Transmission
Investment,” Journal of Industrial Economics, Vol. 53, No. 2 (June 2005), pp. 233-264; and Makholm, J.D.,
“Electricity Transmission Cost Allocation: A Throwback to an Earlier Era in Gas Transmission,” The Electricity
Journal, Vol. 20, No. 10 (December 2007), pp. 13-25.
6
See Revised Attachment Y, section 15.2 and 15.3.
7
See Revised Attachment Y, section 15.3.b
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- 12 screen to determine a project’s eligibility for further cost /benefit analysis and
consideration, it does not provide enough information to identify the load beneficiaries who
will ultimately bear the cost of the project.
21. Such economic efficiency as measured by a production cost savings analysis does not
automatically create what could be called “benefits” for the customers of the load
beneficiary members of the NYISO. If the lower cost power does not affect the pool price
or the region’s location-based marginal price (LBMP), then the “benefit” associated with
the more efficient generation of power will go to the power plant’s owners, not to those
who consume the electricity. Such will occur any time that an economic transmission
enhancement displaces only a portion of the high-cost generation that sets the LBMP.
22. From the perspective of the load serving members of the NYISO similar to Con Edison, the
beneficiaries of the economic transmission enhancement need to be reasonably well
identified. If the benefits go to unregulated power plants that will now operate with a
reduced physical constraint in the transmission grid—enabling additional access to a higher
priced market area to sell more generation at the higher price—and the cost of energy
supply to the loads remain unchanged, it would be unfair to charge the regulated
transmission enhancement cost to those same loads. This is not to say that it is
unreasonable to pursue lower cost generation. But the procedures contained in the
NYISO’s Attachment Y are there to allocate the new regulated transmission costs (of either
the reliability or economic variety), only allowing for these costs to be assigned to the
ISO’s load members if and when the market does not adequately respond to either the
identified reliability needs or the persistent congestion. It wouldn’t suffice, in that process,
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- 13 to assign to those load members the cost of projects whose associated benefits would be
realized in the market by unregulated generators (i.e., lower cost generators receiving the
pool price rather than higher cost ones).
23. For example, it is possible for a new and more efficient power plant connected to an
economic transmission upgrade to have costs largely, if not wholly, below the marginal cost
unit setting the energy market price. That new plant would thus realize the benefits of
lower cost production instead of the loads. Ultimately the total cost to the loads—that is the
cost of their energy supply plus the cost of the new transmission line—may not be lower
than the cost of supply without the new transmission line. This is the potentially
undesirable outcome that would likely occur if the NYISO limited its analysis to the
production cost savings eligibility screen. It highlights the necessity for the further net load
payment savings analysis as an essential component of the NYISO economic planning cost
allocation process.
24. Recognizing that not all benefits of an economic transmission enhancement are realized by
the load serving members, the NYISO proposal also “measure[s] the present value and
annual zonal LBMP load savings for all load zones which would have a load savings, net of
reductions in TCC payments, and bilateral contracts (based on available information)”8 to
designate project beneficiaries. This more stringent benefits analysis is critical in
determining whether a project should move forward. It will supply the primary
8
See Revised Attachment Y section 15.4.b
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- 14 information—whether the net present value (NPV) of the load payment savings is sufficient
to meet the assigned project costs—utilized by voting beneficiaries.
25. The voting mechanism proposed in section 15.6 of Attachment Y does indeed imply that
the load payment savings analysis and its definition of benefits, focusing on load members,
is important. Recognizing that project benefits are not always realized by the load
beneficiaries, it is vital that the NYISO process include: (1) the combination of the two part
eligibility screen/benefit designation analysis so that load beneficiary members have the
appropriate decisional information; and (2) the voting mechanism, so that load members
who will bear the costs of economic transmission upgrades have a key voice in allowing the
projects to go forward. I recommend that the combined two step analysis and voting
mechanism in the NYISO proposal be adopted. I specifically discuss below in Section VIII
the appropriateness of the voting mechanism.
V.
The Time Frame for Measuring Benefits
26. The NYISO proposes to study benefits for an economic transmission enhancement “over a
ten-year period commencing with the proposed commercial operation date for the project.”
(Attachment Y, Section 15.3.a.) There are two problems here. The first is that this period
does not align with the period that the NYISO uses for its other planning processes, either
for the Comprehensive Reliability Plan (CRP) or for the Congestion Assessment and
Resource Integration Study (CARIS). The second is that for such a time frame (which
would place the 10 year analysis after what could be a lengthy development period), the
benefits, as such, are largely—if not wholly—speculative.
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- 15 27. Transmission projects may have lead times ranging from three to 10 years. This means that
the analysis period for benefits stretches three to 10 years beyond the 10 year reliability and
congestion study period of the CRP and CARIS, respectively. Extending the analysis of
benefits beyond the limitation of the current NYISO modeling capabilities (for its CRP and
CARIS) is a cause for concern. Models such as those supporting CRP and CARIS are not
by their nature simple trend lines. Moving the analysis further into the future to encompass
the extra duration beyond the planning period would either require a comprehensive
extension of the model (which the NYISO has not proposed specifically for the CRP and
the CARIS, and is not needed for these processes), or a simpler type of model adjustment
that is either ad hoc or comparatively subjective. Further, moving any of these analyses
further into the future introduces uncertainty with respect to load growth and development
of new competitive resources that may include generation, energy efficiency, or competitive
(likely controllable) transmission. In a joint planning process under the aegis of the ISO,
those proposing potential regulated economic transmission projects would know that their
own project justification depends on that simpler and less robust type of modeling, which
will essentially result in forecasting without the advantage of a sound baseline set of
projects necessary to maintain the reliability of the system. This could result in uncertain
and advantageous identification of benefits for the economic transmission enhancement
project in question, as the developers wish to present it in the best possible light.
28. A more debilitating problem of an analysis period that goes beyond that used for CRP and
CARIS is the essentially speculative nature of anything that occurs in those extra years in
particular beyond the 10 years. Predicting the cost or utilization of particular power plants
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- 16 on a grid quickly becomes a speculative activity. The following factors, among others,
defeat easy predictions: (1) power plant fuel price levels change (sometime rapidly); (2)
“basis differentials” (meaning the relative fuel prices in one location versus another) can
change rapidly also; (3) load growth absorbs plant capability that may have been rendered
idle by a transmission constraint; (4) congestion payments are quixotic, model-dependent
and uncertain, particularly in the later years; (5) load patterns change between regions; and
(6) environmental constraints (such as potential carbon taxes), costs, and subsidies depend
on unpredictable legislative or regulatory action. More specifically:
a. The benefits of economic transmission enhancements will depend on lower fuel
capacity in one region versus another. Over time, such surpluses will diminish as load
in that region grows. When local load grows faster than anticipated, whatever benefits
for economic transmission enhancements exist will diminish more quickly. Those
benefits are sensitive to this factor, and it is clearly difficult to forecast it well beyond a
handful of years.
b. Actual and forecasted congestion payments depend on the underlying topography9 of
the ISO and the models it uses to derive its LBMPs. Going beyond the normal planning
horizon for the NYISO means that any forecasting will have to assume a continuation of
a topography that is likely to change as new competitive power plants come on line,
others are retired and other transmission ties or reinforcements are built.
9
By topography, I mean the collection of all of the ISO’s power sources, transmission links and loads that are
spread out over the landscape that it serves.
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- 17 c. Load patterns change between regions. As with the topography of the RTO/ISO, these
changes affect any forecasts of benefits.
d. Environmental issues are an important factor to the economical production of power
from different types of plants. Carbon taxes would raise the relative cost of coal-fired
power and the persistence of wind power subsidies (or new subsidies directed at nuclear
power) will do the same. All depend on the timing and content of regulatory actions or
legislation (in addition to possible international treaties), which is manifestly
unpredictable.
29. It should be apparent that my point is this: if the period for measuring benefits lies beyond
the ISO’s normal planning horizon, the calculation of benefits is inherently speculative. No
competitive entity would bank (as a literal matter) on sources of such benefits beyond the
ISO’s 10 year planning horizon. Investment capital for transmission links in competitive
markets requires a much more certain stream of both benefits and payments available for
investors and lenders.10 We should not expect the ISO’s members to think that the
calculation of those benefits beyond 10 years is based on any sort of firm footing. I would
recommend that the limit for the calculation of benefits stop with the ISO’s planning
horizon for CRP and CARIS.
10
In Makholm (2007), p. 19, I describe the difficulty that the financiers of the gas transmission links in the 1950s
to create mechanisms to underwrite gas pipeline transmission expansions. The U.S. insurance industry had to
create new loan instruments to make it possible—instruments that relied upon the highly predictable nature of
FERC gas pipeline ratemaking, on the nature of the physical transport contracts and on the stable and highly
credit worthy nature of the buyers (generally regulated gas distribution companies).
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- 18 -
VI.
Fuel Forecasting
30. Fuel forecasting has particular problems when it serves to form the basis for new
transmission investments. In particular:
a. Fuel price level forecasting is a perilous activity, as those prices essentially exhibit a
“random walk.”11 Unlike the weather, there is no predictable measure of central
tendency for future fuel prices. They depend on both microeconomic (production cost)
and macroeconomic (currency exchange rate and global economic activity) conditions
that themselves are very difficult to forecast. Changes in direction for fuel prices are
particularly hard to anticipate—a persistent failure of those in that business of
forecasting.
b. Relative fuel price levels in different locations depend on many things, including the
weather, the presence of gas transmission bottlenecks and the creation of significant
new gas or oil transmission links. Basis differentials change over time between gas
producing and consuming regions of the country, all of which affect the cost of power
generated at different locations.
31. I reviewed historical forecasts of oil and natural gas prices prepared by the Energy
Information Agency (EIA) of the Department of Energy. These forecasts are published as
part of the Annual Energy Outlook (AEO). In particular, I reviewed the EIA’s comparisons
of AEO price forecasts for oil and natural gas to the actual realized prices for these
11
“Random walk” is defined as an example of a time series in which the current value of a variable is equal to its
most recent value plus a random element.
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- 19 commodities. On a consistent basis, the forecasts often diverge widely from the prices that
actually occur. Such a divergence is unsurprising, given the volatile nature of fuel prices
generally. Further, most of the error is on the high side.
32. I attach three tables to my affidavit to illustrate my point. Table 1 shows that the forecast
prices for oil and natural gas have been greater than the actual prices more than 60 percent
of the time, with an overall forecast error of over 50 percent. Table 2 shows oil price
forecasts made in various years before each year (1-year, 2-year, 5-year, etc.) as compared
to the actual observed oil prices for that particular year. In percentage terms, Table 2 shows
a 128.5 percent difference is seen in the 5-year forecast for 1987. This means that the
forecast of prices made 5-years earlier in 1982 was 128.5 percent greater than the prices
realized in 1987. Such forecast errors have exceeded 400 percent. Table 3 shows a similar
analysis for natural gas prices. The evidence is both clear and unsurprising: forecasts for
inherently volatile fuel prices are not very reliable, and have tended to significantly
overstate actual oil and natural gas prices.
33. Given the uncertainty in fuel cost forecasts and the likelihood that relative fuel costs will be
a determining factor in the cost/benefit test, I would conclude that the proposed study
period for economic cost allocation, and beneficiary designation, in the NYISO’s
Attachment Y contains a time horizon that is much too long.
VII. Including the Whole Cost of the Economic Transmission Enhancement
34. Future benefits for an economic transmission upgrade are uncertain—the costs of the
upgrade, however, are comparatively well known. Like other forms of energy transmission
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- 20 (as in the case of gas and oil pipelines), transmission costs are up-front and sunk. Other
than the relatively predictable costs of maintaining the facilities, and line losses, the price
for their use over time is not much more than the amortization of the sunken costs
(including carrying costs for the outstanding rate base). Such is part and parcel of the way
that the “revenue requirement” in regulated utility investments of all types is recouped
through regulated charges in the U.S.
35. In such an instance, it would appear to make little sense to weigh the benefits of an
economic transmission enhancement with only a portion of the amortized cost. Yet, that is
what the NYISO proposes: “[t]he project cost allocated under this Section 15.4 will be
based on the total project revenue requirement, as supplied by the developer of the project,
for the first ten years project operation.” (Attachment Y, Section 15.4.e.) What about the
rest of the 20-30 year lifetime of an economic transmission upgrade?
36. Failing to take into account the remainder of the revenue requirement will cause a
reasonably obvious bias in the weighing of benefits and costs. It will result in a bias toward
regulated transmission projects over market alternatives to a bottleneck. If the great
majority of actual costs of economic transmission upgrades occur up-front, and the benefits
become quickly and increasingly speculative over time, then using only the first 10 years of
regulated revenue requirements will present a bias in favor of projects that look economical
today, but which may not be economical over the useful life of such a transmission upgrade.
37. I would propose that the recovery period for the economic transmission enhancement
project be closely aligned to the benefit study period, as it would for other alternatives
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Consulting Economists
- 21 developed by the market in response to pricing signals. This process should complement
and not supplant the development of market resources in response to such signals.
VIII. Voting on the Outcome of the NYISO Planning Process
38. To reiterate, because project benefits are not always realized by the load paying
beneficiaries, it is important that the NYISO process include a voting mechanism. Then,
the load members, who will bear the costs of economic transmission upgrades, can have a
key role in allowing the projects to go forward. The NYISO proposal to hold a vote of those
members designated as beneficiaries of a proposed economic transmission project is both
sound and reasonable. There are two good features of the voting proposal: (1) the
beneficiaries receive proportional votes; and (2) a super majority of 80 percent of those
votes is required for the project to move forward.
39. To a certain extent, such a voting scheme elicits the kind of verdict that a market would if
there were no barriers to merchants providing new electricity transmission investments. If
one or a number of the ISO load members believed that the benefits to their customers were
sufficiently substantial and long-lived to absorb the cost of a particular transmission
enhancement, there is no particular reason why they wouldn’t seek to fund it themselves
outside of the process described by Attachment Y. But as I discussed above,12 both
technology and the method for recouping transmission charges do not permit independent
lenders or investors to be assured of the repayment of their long-lived capital (except under
12
See Paragraphs 15-18.
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Consulting Economists
- 22 the circumstances that I mentioned). Hence the NYISO proposed to do it as a group
planning activity, subject to a vote by those who would ultimately pay.
40. To the extent that the benefits of an economic transmission enhancement are speculative, or
the costs are mismatched with the benefits, voting members would be able to consider these
issues and develop an appropriate position. This is particularly so if a member perceives
that the allocation of costs is disadvantageous to its customers as compared to projected
benefits.
41. The proposed voting method, then, is a practical and reasonably effective way to avoid the
building of economic transmission enhancements whose benefits do not dependably cover
their cost and/or whose cost allocation may be subjective or otherwise perceived to be
unfair. Alternately, if the project makes sense, voting for it would allow its costs to be
recovered proportional to the measured benefits from all load serving members in the
region or zone, and would allow the realization of the compelling benefits without any
concerns about “free rider-ship.”13
42. It may seem that the NYISO, in its voting proposal, has created a high threshold to build
regulated transmission enhancements for the purpose of alleviating congestion caused by
transmission constraints. In the end, that is not terrible, for the FERC, as well as much of
the market, recognize that it is better for those stakeholders that would most directly and
13
Those “free riders” could either be LSEs who benefit—but who do not pay for—the economy transmission
upgrade, or competitive generators who appropriate the economic benefit of the upgrade, as I had discussed
earlier.
n/e/r/a
Consulting Economists
- 23 objectively benefit from transmission upgrades (like groups of power generators or other
sub-sets of the ISO membership) to find a way to fund such transmission links directly.
43. This concludes my affidavit.
Dated: January 7, 2008
Jeff D. Makholm, Ph.D.
Subscribed and sworn to
before me this
day of January 2008
Notary Public
My commission expires:
n/e/r/a
Consulting Economists
- 24 -
Table 1
Summary of Differences between Annual Energy Outlook
Reference Case and Realized Outcomes
All AEOs
Absolute
Percent OverPercent
Estimated
Differences
(1)
(2)
World Oil Prices
Natural Gas Wellhead Prices
68.0%
61.0%
52.9%
63.5%
Source:
Energy Information Administration / Annual Energy Outlook
Retrospective Review.
http://www.eia.doe.gov/oiaf/analysispaper/retrospective/index.html
Note
The comparison summarizes the relationship of the Annual
Energy Outlook case projections since 1982 to realized
outcomes for AEO1982 through AEO2006.
Explanation:
Column 1 shows the proportion of years for which the deviation between the EIA forecast
and the actual outcome was such that the forecast was greater than actual.
Column 2 shows the average absolute percentage deviation between the forecast and the actual..
n/e/r/a
Consulting Economists
- 25 -
Table 2: World Oil
Summary of Differences between Annual Energy Outlook forecast
and Realized Outcomes
Percentage Differences in Real Prices
Length of forecast
End of
Forecast Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
1 year
2 years
5 years
7.7
84.7
-12.5
7.4
110.0
36.9
128.5
-19.6
32.4
10.2
25.5
10.9
0.8
-14.0
4.8
56.1
-21.0
-21.3
13.0
-7.3
-2.9
-31.7
-27.5
4.6
-24.9
40.6
28.0
36.9
6.4
-11.7
0.3
62.4
15.1
-47.0
-4.6
-3.7
-13.4
-28.4
-49.9
10-11 years1
12-16 years2
105.9
55.1
19.0
19.6
34.3
65.5
27.5
35.0
83.7
25.1
-19.3
-1.5
-5.0
-29.1
-37.0
-51.6
331.0
117.3
168.3
252.7
168.6
66.7
81.1
81.2
40.4
-5.3
-37.8
492.7
351.0
241.7
132.5
82.8
69.9
42.0
41.4
Source:
Energy Information Administration / Annual Energy Outlook
Retrospective Review.
http://www.eia.doe.gov/oiaf/analysispaper/retrospective/index.html
Notes:
1) If forecast was available for years 10 and 11, year 11 was used.
2) Longest forecast was used for 12-16 years. For example if a forecast
was available for all years, 16 year forecast was used.
3) Table presents the percent differences between actual and projected prices.
4) Negative values indicate underestimates and positive overestimates.
5) Percentages are based on real current prices and avoid any inflation assumptions.
Explanation:
Each row in the table above represents percentage differences (i.e. percentage
overestimated/underestimated) between actual world oil prices in the
year mentioned in column one and forecasts made regarding world oil prices
in previous Annual Energy Outlook reports published by the Energy Information Administration.
For example for the year 1995, a forecast made one year prior in 1994 overestimated
the price by .8%, a forecast 2 years prior overestimated price by 6.4%, and a forecast
made 5 years prior overestimated price by 65.5% and so on. In general, as can be
seen in the table, the longer the forecast period the less accurate are the projections.
n/e/r/a
Consulting Economists
- 26 -
Table 3: Natural Gas Wellhead
Summary of Differences between Annual Energy Outlook forecast
and Realized Outcomes
Percentage Differences in Real Prices
Length of forecast
End of
Forecast Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
1 year
10.4
34.4
17.1
15.2
0.6
10.2
15.8
6.2
-5.1
14.9
28.9
-19.8
-21.4
12.1
-1.9
-39.3
-12.9
-30.1
-33.2
-26.8
-26.5
2 years
5 years
16.7
49.3
59.0
35.4
24.6
11.4
21.3
-0.4
13.0
46.2
-10.0
-19.7
-2.8
3.0
-40.1
-43.3
0.8
-48.1
-42.8
-50.5
10-11 years1
12-16 years2
299.6
132.5
144.6
95.9
91.9
56.6
49.1
61.7
15.7
12.0
39.2
9.6
-40.4
-46.6
-17.1
-48.1
-54.0
-62.3
501.7
213.0
231.9
195.8
193.7
45.8
7.8
60.5
-1.4
-29.5
-43.2
721.7
339.9
341.8
193.4
71.9
18.2
18.1
21.9
Source:
Energy Information Administration / Annual Energy Outlook
Retrospective Review.
http://www.eia.doe.gov/oiaf/analysispaper/retrospective/index.html
Notes:
1) If forecast was available for years 10 and 11, year 11 was used.
2) Longest forecast was used for 12-16 years. For example if a forecast
was available for all years, 16 year forecast was used.
3) Table presents the percent differences between actual and projected prices.
4) Negative values indicate underestimates and positive overestimates.
5) Percentages are based on real current prices and avoid any inflation assumptions.
Explanation:
Each row in the table above represents percentage differences (i.e. percentage
overestimated/underestimated) between actual world oil prices in the
year mentioned in column one and forecasts made regarding Natural Gas Wellhead prices
in previous Annual Energy Outlook reports published by the Energy Information Administration.
For example for the year 1995, a forecast made one year prior in 1994 overestimated
the price by 28.9%, a forecast 2 years prior overestimated price by 46.2%, and a forecast
made 5 years prior overestimated price by 61.7% and so on. In general, as can be
seen in the table, the longer the forecast period the less accurate are the projections.
n/e/r/a
Consulting Economists