testimony of gary ackerman on behalf of...
TRANSCRIPT
Docket No.: R.17-09-020
Exhibit No.:
Date: July 10, 2018
Witness: Gary Ackerman
TESTIMONY OF GARY ACKERMAN ON BEHALF OF THE
WESTERN POWER TRADING FORUM
TABLE OF CONTENTS
I. Introduction ..........................................................................................................................1
A. Background ............................................................................................................. 2
B. Summary of Conclusions and Proposals ................................................................. 3
II. A Three-Year Forward Requirement Should be Adopted for Local, System and Flexible RA ...................................................................................................................3
III. A Centralized Clearing Capacity Market Should be Adopted .............................................7
IV. ELCC Estimates Should Accurately Reflect the Impact of BTM PV. ................................8
V. Unbundling Flexible RA from System and Local RA .......................................................10
1
I. Introduction 1
Q: Please state your name and business address. 2
A: My name is Gary B. Ackerman. I am the founder and president of a California-based 3
consulting corporation known as Foothill Services Inc. My business address is 411 E. 4
Huntington Drive, Suite 107-222, Arcadia, California. My professional and educational 5
qualifications are provided in Attachment 1. 6
7
Q: Have you previously testified before the California Public Utilities Commission? 8
A: Yes. I have testified numerous times before the California Public Utilities Commission 9
(CPUC or Commission) as an expert witness for the Western Power Trading Forum 10
(WPTF) in my previous capacity as Executive Director of that association. I retired from 11
that role effective June 30, 2018. 12
13
Q: On whose behalf are you testifying? 14
A: I am testifying on behalf of the Western Power Trading Forum (WPTF). WPTF is a 15
California non-profit, mutual benefit corporation dedicated to enhancing competition in 16
Western electric markets in order to reduce the cost of electricity to consumers 17
throughout the region while maintaining the current high level of system reliability. 18
WPTF actions are focused on supporting development of competitive electricity markets 19
throughout the region and developing uniform operating rules to facilitate transactions 20
among market participants. I founded WPTF in 1998 and as stated above, served as its 21
Executive Director until June 30 of this year. 22
2
A. Background 1
Q: Please provide the procedural background that has led to your testimony. 2
A: On September 28, 2017, the Commission issued an Order Instituting Rulemaking to 3
Oversee the Resource Adequacy Program, Consider Program Refinements, and Establish 4
Annual Local and Flexible Procurement Obligations for the 2019 and 2020 Compliance 5
Years. On January 18, 2018, Assigned Commissioner Liane M. Randolph and 6
Administrative Law Judge Peter V. Allen issued a Scoping Memo and Ruling of Assigned 7
Commissioner and Administrative Law Judge (Scoping Memo), which provided for a 8
Track 2 to address program refinements. 9
10
Decision (D.) 18-06-030, Decision Adopting Local Capacity Obligations for 2019 and 11
Refining the Resource Adequacy Program, specifically directed that, “in their Track 2 12
testimony parties should propose a multi-year local RA requirement with a three-to-five-13
year duration, with implementation beginning in the 2020 RA program year. Proposals 14
should provide a timeline for full implementation of a multi-year local RA requirement, 15
including any necessary preliminary steps and transition or phase-in periods.”1 The 16
decision further directed that, “parties should propose central buyer structures for multi-17
year forward procurement of local RA in their Track 2 testimony.”2 18
19
My testimony responds to those directives and concerns certain other issues as well. For 20
instance, WPTF believes that the multi-year forward methodology should be applicable 21
to system and flexible RA, not just local, because local capacity potentially counts toward 22
1 D.18-06-030, at p. 29. 2 Id, at p. 32.
3
both system and flexible requirements, and therefore procurement of local capacity also 1
impacts procurement of system and flexible requirements, making a different compliance 2
timeframe for system and local unnecessarily complicated and potentially confusing. 3
Therefore, my testimony addresses all three requirements as appropriate. 4
B. Summary of Conclusions and Proposals 5
Q: Please summarize your conclusions and proposals. 6
A: WPTF makes the following recommendations: 7
First, we recommend that a 3-year RA forward requirement should be adopted for 8
local, system and flexible RA, with explicit compliance targets. 9
Second, the CAISO should assume the role of administering a centralized clearing 10
capacity market to satisfy the “Central Buyer” concept discussed in D.18-06-030. 11
Third, effective load carrying capacity (ELCC) estimates to the greatest extent 12
possible should accurately reflect the impact of behind the meter solar photovoltaics 13
(BTM PV). 14
Fourth, flexible resource adequacy should be unbundled from system and local 15
resource adequacy, and the Commission should consider the CAISO’s proposal to 16
develop a separate flexible deliverability study. 17
II. A Three-Year Forward Requirement Should be Adopted for Local, System 18 and Flexible RA 19
Q: What is your recommendation for a forward requirement? 20
A: WPTF offers for consideration a framework for development of a multi-year forward 21
procurement requirement and an associated capacity market/hedging mechanism that 22
4
provides risk management, price transparency and transactional ease. The following 1
features would be included: 2
The Commission should establish a three-year forward capacity procurement 3
obligation; the major features of which shall include: 4
1. Full compliance at 100% of the system, local, and flexible capacity 5
requirements for all years of the three-year forward window. The forward 6
capacity requirements should be applicable to all CPUC-jurisdictional load-7
serving entities (LSEs). The request for full compliance for the out years of 8
the auction stems from the request below in Section III of my testimony for 9
incremental reconfiguration auctions to adjust through time for load-10
forecasting corrections. 11
2. The Commission shall approve the participation of investor-owned utilities 12
(IOUs) in the forward RA capacity markets. The IOU bilateral contracting 13
permitted outside of the forward markets need not be limited a priori but it 14
should be understood that the bilateral contracts applicable to the three-year 15
horizon must be included in the supply and demand totals used in the forward 16
auctions. 17
3. Jurisdictional LSEs may count Demand Response (DR) that is eligible to bid 18
into the CAISO market to satisfy forward capacity procurement 19
obligations. Some parties may advocate for Energy Efficiency (EE) to be 20
able to participate in meeting forward capacity requirements. This is 21
achievable so long as specific EE programs with a proposed measurement and 22
verification plan are offered pursuant to which such resources are obligated to 23
5
achieve a verifiable amount of load reduction over the RA procurement 1
period. This model has been put into place in PJM and is a preferable 2
approach. Alternatively, EE can serve to decrease the overall RA requirement 3
by offsetting the load forecasts that serve as the basis for RA requirement. 4
Those forecasts are prepared by the California Energy Commission (CEC). 5
However, it is unclear how the CEC incorporates its EE expectations into the 6
development of the final load forecasts, especially as it may pertain to 7
multiple forward years. Which alternative is best for California’s RA 8
construct should be the subject of further study by the CPUC and CEC, and 9
stakeholder review. 10
4. The reliability standard on which RA capacity market procurement 11
obligations are based shall be one significant outage event in ten years for 12
system requirements. 13
Forward requirements will be allocated to LSEs in the same manner as year-ahead 14
requirements are currently allocated. 15
The auction will include constraints that the entire portfolio of capacity must 16
satisfy—such as an aggregate flexibility capability, e.g., ramp rates that are equal 17
to or greater than a minimum criterion. 18
The auction should determine clearing prices for forward-year capacity in 19
different locations. There is always the possibility that the CAISO may determine 20
the need for additional installed flexible capability. However, WPTF believes 21
that a well-designed and fully functional forward capacity market should not need 22
6
extra out-of-market procurement. If the occurrence of out-of-market capacity 1
becomes frequent, then that would be a signal that further design work is needed. 2
Settlement occurs in the delivery year and reflects an LSE’s load in the delivery 3
year. 4
The CAISO capacity auction ultimately should encourage the development of 5
new resources, sustain needed existing resources, and diminish the need for 6
procurement of new resources through LTPP-like processes. 7
The auction will include appropriate demand and supply market-power mitigation 8
measures. 9
Backstop Procurement 10
The forward auction design for RA procurement should diminish to the greatest extent 11
possible reliance on backstop procurement mechanisms such as Reliability Must Run 12
(RMR) and the Capacity Procurement Mechanism (CPM). A well-designed market that 13
satisfies all the reliability requirements including the complicated ones that lead to 14
collective deficiencies should make out-of-market procurement to extremely rare. First 15
and foremost, to accomplish this there needs to be an improved timeline for 16
demonstrating local, system and flexible capacity. The process should start earlier in the 17
year and conclude, say, by June 30 of the compliance-showing year allowing at least six 18
months for determining any local reliability gaps instead of the one or two months that is 19
part of the current process. After the RA showings are made, the CAISO can decide if 20
one or more RMR and/or CPM resources need to be added, and thereby make that 21
designation. 22
7
III. A Centralized Clearing Capacity Market Should be Adopted 1
Q: What is your recommendation with regard to the Central Buyer concept proposed 2
in D.18-06-030? 3
A: A Central Buyer is a vague proposal that attempts to work around the jurisdictional issues 4
of agreeing to let the CAISO conduct a centralized forward capacity market. WPTF 5
believes that the CAISO would be the best entity to conduct and administer a centralized 6
forward capacity market. It might be possible to achieve an alternative procurement 7
platform to the CAISO although the practical distinction to having a non-CAISO entity 8
manage the capacity market is likely illusory. Regardless of who might run a market 9
clearing platform, any such mechanism that establishes forward prices and obligates 10
participants’ future credit comes under the regulatory purview and enforcement of federal 11
agencies such as the CFTC and the SEC. FERC has long-standing working agreements 12
with these agencies in order to clarify which agency has authority if there are 13
enforcement issues. Therefore, a third-party conducting a forward capacity auction for 14
California other than the CAISO might give the impression that the State entirely controls 15
the process, but that assumption can be challenged. In fact, FERC’s authority over 16
resource adequacy stems from its jurisdiction over market-based rate sales of capacity.3 17
3 The Commission grants market-based rate authorization for wholesale sales of electric energy, capacity and ancillary services by sellers that can demonstrate that they and their affiliates lack or have adequately mitigated horizontal and vertical market power. The Final Rule on Electric Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity And Ancillary Services By Public Utilities and its progeny (Order Nos. 697 through 697-D), offer greater detail regarding the Commission’s currently effective policies applicable to electric market-based rate authorization.
8
Q: What do you recommend in lieu of a Central Buyer? 1
A: I recommend that the CAISO should, working collaboratively with the CPUC and 2
stakeholders, develop a forward Resource Adequacy capacity auction and reconfiguration 3
auctions to allow for inter-year adjustments that will account for all supply necessary to 4
meet local, system and flexible forward capacity procurement obligations. It shall 5
include the following CAISO activities: 6
Administer a capacity market including the determination of clearing prices and 7
settlements that result from the auction. 8
For each delivery year, the RA capacity market will include a three-year forward 9
base auction and reconfiguration auctions to account for changes in load forecasts 10
that lead to changes in RA requirements (including expectations about the 11
performance of demand-side resources that are treated as load reductions) and 12
expectations about the likelihood that resources (potentially including demand-13
side resources) will perform in the delivery year. 14
If the Commission absolutely cannot allow the CAISO to perform this role, then it 15
should be performed by an independent third party having clearinghouse 16
experience and expertise. A California IOU or a California government agency 17
should not be tasked with this responsibility. 18
IV. ELCC Estimates Should Accurately Reflect the Impact of BTM PV. 19
Q: What is your recommendation regarding Effective Load Carrying Capacity and the 20
impact of BTM PV? 21
9
A: WPTF believes this is an issue that is long overdue for Commission resolution. In R.14-1
10-010, the prior RA proceeding, ELCC proposals were made that identified how BTM 2
PV significantly affect ELCC. 3
Q. What is the impact of inaction on this issue? 4
A. The current practice significantly overstates the volume of capacity available at time of 5
system peak. As such, grid reliability may be compromised. 6
7
Q. What is your recommendation regarding this issue? 8
A. WPTF believes it would be appropriate for the Commission to direct for the 2020 9
compliance year that BTM PV should be expressly modeled as a supply resource rather 10
than backing out of the load forecast the volume of load that is met with BTM PV. 11
12
Q. Why is this necessary? 13
A. The ELCC estimates adopted last year do not include BTM PV as an explicit resource, as 14
was demonstrated by the August result. Although the initial Energy Division estimate for 15
solar ELCC approximated 30% of nameplate capacity (including BTM PV), the final 16
August results backed out BTM PV, which artificially increased the solar ELCC to about 17
40% of nameplate capacity. RA compliance should rely on ELCC estimates that reflect 18
BTM PV as supply. WPTF understands that this treatment likely requires concomitant 19
changes to other aspects of RA compliance, e.g., RA requirements based on load 20
forecasts that do not already reflect the impact of BTM PV, a determination of who is 21
able to “count” the RA capacity associated with BTM PV, and potentially rules related to 22
10
whether BTM PV will participate in CAISO markets and be subject to the same 1
availability incentives as other RA resources. 2
3
Q. What has been Energy Division’s position on this issue? 4
A. Energy Division’s February 24, 2017, proposal in fact explained, “The effect that BTM 5
PV has on overall solar ELCC stems from the fact that as solar penetration increases, 6
peak load net of solar generation shifts further into the evening when solar generators 7
cease generating. This shift in load hours affects average solar ELCC.”4 8
V. Unbundling Flexible RA from System and Local RA 9
Q. What do you recommend with respect to this topic? 10
A: Furthermore, the CAISO has proposed that the Effective Flexible Capacity (EFC) should 11
be decoupled/unbundled from the Net Qualifying Capacity (NQC) under the Flexible 12
Resource Adequacy Must Offer Obligation (FRACMOO) stakeholder process and has 13
indicated that it will submit the final FRACMOO proposal to the Commission in Track 2 14
of this proceeding. I recommend that the Commission support this unbundling proposal, 15
as well as the CAISO’s proposed plan to study the development of a separate flexibility 16
deliverability assessment. One feature of the study may be to decouple Effective Flexible 17
Capacity (EFC) from Net Qualifying Capacity (NQC). This issue has been discussed in 18
several previous RA proceedings and is certainly ripe for full consideration now.19
4 See section III.D. of Energy Division’s proposal dated February 24, 2017.
11
Q: Why should this be done? 1
A. Separating out flexible RA from generic RA makes sense because these products offer 2
two different services – flexible RA addresses non-peak operational needs with energy 3
only whereas system and local RA are required to address system-wide capacity needs 4
during peak periods. 5
Q: What other reasons justify this approach? 6
A. Additionally, the CAISO has proposed developing a flexible deliverability study for 7
flexible RA products. WPTF supports developing a new flexible RA study versus a full 8
capacity deliverability study (FCDS) for flexible resources. The confusion, it seems, 9
stems from intermittent resources that may contribute energy during non-peak periods 10
whereas the critical need for grid reliability can be demonstrated in a full capacity study 11
that examines a resource’s ability to deliver at peak on the entire system. A FCDS for 12
flexible-only resources often results in unnecessary system upgrades that make critical 13
flexible resources uneconomic. By developing a more appropriate deliverability study, 14
additional flexible resources may be available to more quickly address the increasingly 15
steep ramps challenging the system. 16
17
Q: What about storage resources? 18
A. Lastly, storage resources should be credited for the full range of services (full charge to 19
discharge) under all flexible RA products on the condition that the storage resource isn’t 20
available for providing other market services. The condition is key to assuring that the 21
storage resource is available when needed. The California grid is witnessing larger and 22
12
more dramatic ramping needs, so it is critical to ensure that fast, flexible products like 1
energy storage are enabled to fully provide such critical services. 2
3
Q. Does this conclude your testimony? 4
A: Yes. However, WPTF reserves the right to address other issues in reply testimony due 5
August 8. 6
1
GARY B. ACKERMAN, President, Foothill Services Inc.
411 E. Huntington Dr. Ste. 107‐222
Arcadia, CA 91006
SPECIALIZED PROFESSIONAL COMPETENCE
Economic and political assessment of regional and national energy developments, including
market design, new technologies, transmission infrastructure, electricity and natural gas trading and
marketing, and private‐interest advocacy.
PROFESSIONAL EXPERIENCE
Western Power Trading Forum: Founder and executive director of a mutual‐benefit, non‐profit
corporation. Mission is to encourage and promote lower electricity prices and enhanced system
reliability in policies undertaken either by the Federal Energy Regulatory Commission (FERC),
California Independent System Operator (ISO), or the California PUC. Current membership of
eighty‐four entities includes generators, marketers, commodity traders, banks, retailers, and
other major market participants in the Western‐states electricity business. (1998 ‐ 2018)
California Resources Corp.: Consultant on California electricity issues to assist community outreach
efforts in Los Angeles and Ventura counties for the California company that spun off from
Occidental Petroleum in 2014.. (2018 – present)
Asociación de Comercializadores de Energía (ACE): Founder and administrator of a Mexican trade
association based in Mexico City representing the interests of qualified buyers and sellers in
Mexico’s restructured wholesale and retail electricity markets. (2017 – present)
ITC Grid Development: Consultant to internal development group focusing on prospective transmission
projects in the Western states. (2013 – present)
Western Independent Transmission Group: Founder and executive director of the non‐profit trade
association that promotes the interests of independent transmission owners and developers.
Advocate for policies before the FERC, CPUC, sub‐regional transmission planning groups within
the WECC footprint, and the CAISO. Current membership of eight entities can be found on the
group’s website: www.transmissionusa.org. (2011 ‐ 2013)
Calpine Corporation: Provided senior managers information on expected costs for different
transmission‐operating options to maximize profitability of merchant plant situated outside of
CAISO control area. (2004)
Automated Power Exchange: Expert witness testimony regarding a three‐way dispute between
cogeneration project (seller), a bankrupt Energy Service Provider, and the California Power
Exchange (buyer). (2002)
Ridge Energy Group: Prepared study for Houston‐based compressed‐air storage developer on the
market feasibility utilizing storage with wind‐based energy sited in California or Arizona. (2002)
2
Southern Nevada Power Project: Co‐developed the plan for a gas‐fired generation project to be located
in the Sandy Valley area of Southern Nevada. Project currently being developed by Diamond
Energy (1995 – present)
Sale Agent for Rio Linda Power Generation Project: Represented the interests of developer/seller of 500
MW gas‐fired project sited in Sacramento area to FPL Energy. Negotiated joint venture
development agreement for re‐siting facility before the California CEC. (1999 – 2001)
Occidental Petroleum: Advise natural gas marketing group on strategies to enhance value to electric
generation buyers of gas commodity and storage services from client’s Elk Hills facility in
Bakersfield. (1999 ‐ 2001)
Wellhead Electric: Advised cogeneration developer and operator on restructuring options in the new
California market. (1998 ‐ 1999)
Robinson‐May Department Stores: Advised department‐store chain regarding strategies for retail
procurement of electricity. (1998)
Mock Energy Services/Avista Energy: Regulatory Affairs coordinator for the joint venture, represented
client in all aspects of California electricity restructuring including the Independent System
Operator/Power Exchange (ISO/PX) Trust Advisory Committee. Served as the President of the
ISO’s Scheduling Coordinator Users Group from February 1997 to January 1998.
Chevron U.S.A.: Development of a natural‐gas‐fueled merchant electric generating facility that would
dramatically alter the way power is bought and sold in the western U.S. (1994 – 1995)
CSW Energy: Assistance to the independent power plant development non‐regulated subsidiary of
Dallas‐based Central and Southwest Services. (1993 – 1995)
ARK/CSW Energy: Advise the cogeneration joint venture on all aspects of business development from
earliest conceptual stages to the execution of power purchase agreements. (1991 – 1998)
Decision Focus, Inc.: Developed new business and sold utility planning software for DFIʹs electric, and
gas and oil business. (1982 – 1989)
Systems Control Inc.: Senior consultant on energy R&D projects for EPRI and the U.S. Department of
Energy. (1978 – 1982)
Commonwealth Edison Company: Entry‐level research analyst on load forecasting techniques for utility
peak loads and energy. (1975 – 1978)
EDUCATION
University of Chicago ‐ M.A., Economics, (1976)
Michigan State ‐ B.A., Economics, (1973)
3
Publications
Reports:
1.Impact Assessment of the 1977 New York City Blackout, (with W.T. Miles, and J.
Corwin), Special report for U.S. Department of Energy, Division of Electric Energy
Systems, HCP/T5 103‐01, Palo Alto, July 1978.
2.The Application of Energy Supply/Demand Models to Regional Power System
Planning, (with F. Ma, J. Patmore, and D. Stengel), prepared for U.S. Department
of Energy and the University of Oklahoma (DOE EC‐77‐S‐05‐5468), Palo Alto, June
1978.
3.U.S. Electric Power Grid Concepts: The Existing System and Proposed Concepts
for Improvements to Bulk Power Supply, (with N. Badertsher, J. Corwin, and C.
Sayler), reprinted in The National Power Grid Study, Vol. II, (Department of
Energy), Washington, DC, September 1980.
4.Evaluation and Transfer of Electric Utility Models Using Comparison Methods,
(with D. Budenaers, and R. Chen), prepared for EPRI (TPS 79‐220), Palo Alto, May
1980.
5.Impact of Customer Load Management Technologies in Utilitiesʹ Load Shapes,
(with M.L. Chan), prepared for EPRI RP 1084‐1, Palo Alto, July 1979.
6.Benefits and Costs of Load Management: A Technical Assistance and Resource
Material Handbook, (with R. Lau, J. Patmore, F. Ma, and Argonne National
Laboratory), ANL/SPG‐12, Chicago, June 1980.
7.Generation Planning and Reliability Study, (with T. Bowe, and W. Dapkus),
prepared for the Illinois Commerce Commission, Palo Alto, August 1981.
8.Application of Decision Analysis to Electric‐Utility Load‐Leveling Strategies,
prepared for Argonne National Labs (ANL‐31‐109‐38‐5306), Palo Alto, September
1981.
9.Analysis of Demand‐side Options, prepared for East Kentucky Electric Power
Cooperative (1986), Iowa Public Service (1986), and Los Angeles Department of
Water and Power (1987).
10.Prospects for Supply, Transportation , Demand, and Price in Western Europe
and Contiguous Regions, prepared for the sponsors of the DFI Western European
Gas Program, Mountain View, August 1993.
4
Articles:
1.ʺDefense Expenditures and the Survival of American Capitalismʺ, Armed Forces
and Society, (with C. Nardinelli), Vol. 3, No. 1, pp 13‐16, Fall 1976.
2.ʺShort‐Term Load Prediction for Economic Dispatch of Generationʺ, IEEE
Conference Proceedings PICA‐79, (with D. Ross, R. Bischke, R. Podmore, K. Wall),
pp 198‐204, May 1979.
3.ʺA Methodology to Evaluate the Costs and Benefits of Electric Customer Load‐
Management Technologiesʺ, Energy Technology VII Proceedings, (with M.L. Chan,
E. Marsh, and J. Yoon), pp 54‐66, March 1980.
4.ʺSimulation‐Based Load Synthesis Methodology for Evaluating Load‐
Management Programsʺ, IEEE Transactions on Power Apparatus and Systems,
(with M.L. Chan, E. Marsh, and J. Yoon), Vol. PAS‐100, No. 4, pp. 1771‐1778, April
1981.
5.ʺDetermining the Benefits and Costs of Load Management Systematicallyʺ,
Public Utilities Fortnightly, (with R. Mueller), Vol. 1207, No. 9, pp 26‐32, April
1981.
6.ʺData Transfers Among Electric Utilitiesʺ, Public Utilities Fortnightly, Vol. 107,
No. 9, pp 26‐32, April 1982.
7.ʺShort‐Term Load Prediction for Electric‐Utility Control of Generating Unitsʺ,
Short‐Term Forecasting, D. Bunn and E. Farmer, eds., (Wiley Press, London)
December 1985.
8.ʺDesktop Computers: Too Young to Offer Any Benefits?ʺ Electrical World
(McGraw‐Hill, New York), July 1983.
9.ʺThe Optimal Penetration of Direct Load Control Switchesʺ,(with J. Gafford)
Transmission and Distribution, (Cleworth Publishing, Cos Cob, CT), July 1983.
10.ʺBridging the Planning and Operations Gap,ʺ Electrical World, (McGraw‐Hill
Inc., NY, NY) October, 1987.
11.ʺHow an Electric Utility Production Cost Model Can Be Validated,ʺ (written on
behalf of John Stremel, Decision Focus Inc., and William Stillinger, Northeast
Utilities) Public Utilities Fortnightly, (Public Utilities Reports, Arlington, VA),
December, 1988.
5
12. “Deal Triage,” (co‐authored with Robert Nicholson, Bank of America Global
Project Finance), Infrastructure Finance, (Financial World Publications, New York)
February, 1997.
13. “Buyers Beware the Confusion,” (co‐authored with Daniel Violette, and Harry
Misuriello), Energy Buyer’s Guide, (Information Forecast, Inc., Sherman Oaks, Ca.)
May, 1997.
6
Professional Papers and Panels:
1.ʺAttempts to Forecast the Demand for Electricity: The Commonwealth Edison
Experienceʺ, (with G. Corey), Delivered at the University of Chicago, Econometrics
and Statistics Colloquium, April 6, 1977.
2.ʺDescription of SCI Load Management Modelsʺ, (with F. Ma) prepared for
Argonne National Laboratory, Special Studies Group, September 1979.
3.ʺKey Steps in Load‐Management Evaluation and Transferability of Load Dataʺ, prepared for Argonne National Laboratory, Special Studies Group, October 1979.
4.ʺFactors Affecting the Adaptation of Load Managementʺ, prepared for U.S. Department of Energy, Economic Regulatory Administration, October 1980.
5.ʺShort Term Forecasting of Monthly Energyʺ, prepared for the EPRI 6th Load Forecasting Symposium, Dallas, Texas, December 1982.
6.ʺAn Emerging Economic View of World Natural Gas”, (with D.H. Dorsett,
Chevron Corp.) prepared for the 1992 Society for Petroleum Engineers Oil and Gas
Economics, Finance, and Management Conference, London, U.K., April 1992.
7.ʺA Case Study of an American Demand Management Bid”, (with James C
Crossman, Financial Energy Management) prepared for the 1st National Demand
Management Conference, Melbourne, Australia, May 1992.
8. “NUG Needs in an Order 636 World: Opportunities for LDC’s”, prepared for the
AGA Strategic Planning Committee Meeting, San Francisco, Ca., August 1992.
9. “Assuring the Independence of ISO’s”, prepared for the Power 97 Conference,
Houston, Texas, July 1997.
10. “Market Participation: The Impacts of Cost and Complexity”, (with Ken
Nichols and Jenny Klein) prepared for the ISO Conference, Denver, March 1998.
11. “Report from the Front Lines: Status and Update on Implementing Regional
Congestion Pricing Schemes”, presented at the Infocast conference on Congestion
Pricing and Tariffs, Washington, D.C., September 1998.
12. “The California Experience”, presented at the EEI National Accounts
Workshop, Chicago, September 1998.
7
13. “Scheduling Coordinators’ Experience with the California ISO”, presented at
the California Coalition of Public Utility Counsels, Monterey, California, October
1998.
14. “Reviewing the California Experience”, presented at the Energy NewsData
Conference on Leaders & Strategies in the New Western Energy Market, Seattle,
November 1998.
15. “Scheduling Coordinator Impressions of the ISO”, presented at the Megawatt
Daily Conference on California Power Markets, San Diego, February 1999
16. “Panel on Risk Management in Trading”, presented at Distributech 1999, San
Diego, February 1999.
17. “Demand Provision of Ancillary Services”, presented at the Technical Advisory
Committee of the California Board of Energy Efficiency, San Francisco, February
1999.
18. “Will Retail Competition Work in California?”, key note speech presented at
the Annual Sacramento Business Journal meeting on power issues, Sacramento,
October 1999.
19. “What happened in California During the Summer of 1999?”, presented at the
California Energy Markets conference, San Francisco, October 1999.
20. “ New Policies at the California ISO” presented at the Association of Bay Area
Governments conference, Oakland, November 1999.
21. “RTO’s in the Western Region”, presented as keynote speaker for the Power
Association of Northern California, March 2000.
22. “RTO’s: Reinventing the Grid”, presented as panelist and moderator at
National Gas Intelligence conference GasMart 2000, Denver, April 2000.
23. “Trading’s Future: Reading the Tea Leaves”, presented at the Platts News
Energy Service conference on Day of the Trader, New Orleans, October 2002.