P. GREGORY CONLON
NOTICE OF PROPOSED RULEMAKING (NOPR)
DOCKET NO. RM99-2-000
AUGUST 23, 1999
SUMMARY COMMENTS AND INDEX BY
NOTICE OF PROPOSED RULEMAKING
DOCKET NO. RM99-2-000
To the Honorable FERC Commissioners:
INTRODUCTION AND RESTRICTION OF MY COMMENTS:
These comments are based on my personal knowledge and experience during and subsequent to, my six year term as a Commissioner of the California Public Utilities Commission (CPUC) from the period February, 1993 through December, 1998 and as President of the Commission from the period of May, 1996, through January, 1998. This period included all of the hearings and proposed and final decisions issued by the CPUC regarding electric industry restructuring, as well as, opening the electric generation market to retail competition. Also this same period included my extensive involvement with the California State legislature in their enacting of Senate Bill 1890 relating to the same subjects. Because of this significant investment in time and effort while on the CPUC, I have continued to be involved in this developing process both in California and nationally as an active observer. My comments are based solely on my personal views from hands-on experience and knowledge, and are not necessarily the views of any present or former Commissioners or staff of the California Public Utilities Commission.
APPROACHING CRISIS IN TRANSMISSION RELIABILITY MANDATES FERC TAKE IMMEDIATE ACTION TO MITIGATE THE POTENTIAL CRISIS:
Based on the comments of several different experts, including Michael R. Gent, President of the North American Electric Reliability Council (NERC), this country is approaching a crisis in reliability (i.e. just keeping the lights on) because of the lack of adequate investment in new transmission facilities. Without a dramatic change in the current transmission capacity situation the instances of such a crisis could get worse, i.e. dramatic peak prices of several thousand dollars per megawatt-hour(MWh), as occurred in the Midwest this summer and further by antidotal evidence of the blackouts in New York and Chicago also this summer, as well as other blackouts in California in 1996. Because the primary need for new facilities is in the bulk power transmission system, FERC and/or Congress needs to do everything it can to eliminate the innate disincentive in the industry, and with which its stakeholders are struggling, in order to make the necessary new investments. I believe that Michael Gent at NERC, and others, are sounding the fire alarm but no fire engines appear to be on the way.
The July 28, 1999 issue of The Energy Daily references an Edison Electric Institute (EEI) Power Marketers Yearbook, indicating that wholesale sales for 1998 in the U.S. hit a new record in MWhs for the year, up 90% from 1997. The 1997 sales were five times greater than 1996 sales. The 1996 sales were eight times more than that of 1995. Also, wholesale transactions in 1998 were greater than the retail market, 4.0 billion MWhs, versus 3.2 billion MWHs for the retail market. The largest market is the Western Systems Coordinating Council, (WSCC), with over 40% of the wholesale sales and purchases.
As a result of this dramatic growth in demand, the need for substantial additional transmission facilities, including capacitors, substations, reconductor and new transmission lines clearly are vitally needed. An illustration of the lack of new investment in transmission capacity, is a graph in the Electric Power Research Institute's (EPRI's) Electricity Technology Roadmap, the 1999 Summary and Synthesis, page 22 displays a graph taken from Cambridge Energy Research Associates data, that confirms the decline in miles of new transmission lines built in the period 1985 to 1990 compared to 1990 to 1995. This data shows a decline of 60 percent in all sizes of bulk power transmission lines, 230KV and above, and even a greater decline in the higher voltages, 345KV and 500KV. This level of new investment declines further in 1996 (supra, p.27).
Although new technology may reduce some of the new transmission line needs, the above statistics are somewhat alarming, especially with the continued growth in electric demand occurring every year.
According to Michael Gent, the current situation is approaching the "edge", if not already crossing it. FERC's action, along with Federal legislation, backing up any areas of unclear FERC legal authority is needed as soon as possible.
ACTION BY FERC SHOULD BE AS QUICK AND DECISIVE AS THAT OF A SURGEON WITH A CRITICAL PATIENT:
Current remedies in the proposed RTO NOPR are relatively mild. The remedies are more voluntary in nature and very considerate of states rights concerns and avoiding any hint of divestiture of transmission assets from the IOUs. In time this process may well work, but the problem now is that this country evidently does not have the time for such an approach. There is much uncertainty as to where the country is going regarding its future transmission policy: as to who regulate what assets, state or federal regulators; who is going to ultimately own the transmission assets, the Independent System Operators (ISOs), a separate Transmission Owning Company (Transcos), a joint-venture or who; and many other critical decisions that need to be resolved before new money goes into transmission assets. Maybe the Bible quote I heard at a recent meeting, from Proverbs, "Where there is no vision, the people perish." Maybe in the current situation it should be changed to "Where there is no vision, the people perish in the dark."
Investors, whether they be present owners of transmission assets or potential investors, seem to need more certainty of these critical questions before they will invest the millions required to meet the future needs of the bulk power transmission system. FERC should pay paricular attention to NERC's opinion as to the seriousness of this problem. The primary driver of the recommended speed and firmness in FERC's decision-making is the seriousness of the need for new transmission facilities and related reliability issues. FERC needs to step-up to the bar because if there is a critical failure in the U.S. bulk power transmission system in the near future, because of the problems discussed above, FERC will have the accountability to the public based on the decisions made in this RTO NOPR.
Some say that FERC will "feel uncomfortable" taking this responsibility and accountability. The fact is, no one else but FERC can act in a decisive manner in the short time frame available. FERC has the forum (RTO NOPR) and the expertise to act in a courageous and forceful manner to get the job done this year. There is no question in my mind that FERC, through its Commissioners and staff can act in this NOPR to make it happen. If FERC does not act appropriately, only the Congress can come in and deal with these very technical and complex issues, a very difficult job for such a high level policy organization. FERC needs to do it now so the Congress only needs to clarify any unclear authority of FERC and support the overall policy decisions of the RTO NOPR.
THE CALIFORNIA COMMISSION WAS IN A VERY SIMILAR SITUATION A FEW YEARS AGO BUT FOR TWO DIFFERENT REASONS--HIGH RATES AND A SICK ECONOMY:
In 1993 and 1994 California's economy was in the worst recession since the Great Depression; it had a double-digit unemployment rate with over 500,000 workers unemployed; it had high energy rates, with prices 150% of the national average and 200% of some of the surrounding Western States. The energy related companies in California felt that the CPUC was the cause for the high rates, regardless of the facts. The large users were angry and the small consumers were not happy with the high rates. The CPUC had to act because the anger of the large customers meant no new investment in California for these companies, but in other states, which meant no new jobs in California by these same companies. This fact-pattern convinced me to have the necessary courage to act as decisively as I could, and with the similar support by other Commissioners, to completely open the electric generation market and allow complete customer choice within five years, if not sooner. To go from a complete monopoly in electric generation, transmission and distribution functions to a completely deregulated generation market required major decisions that the CPUC was not anxious to make.
Mitigation of market power and stranded asset recovery were the two most challenging issues to be decided. Some form of divestiture was necessary to mitigate the abuse of market power of the wires, even though we had no specific legislative authority to support such action. We ordered voluntary divestiture of 50% of the fossil generation and reduced the rate of return on the remaining generation stranded assets, but we allowed 100% recovery of the book value of the stranded assets, which were mostly generation asset and above market PURPA contracts. The State legislature in its Senate Bill 1890 (SB1890) legislation enhanced the CPUC's policy decision, and fortified the CPUC's policy decision in most key policy issues. Change of this magnitude does not come out of anything but necessity. I believe FERC is in a similar position today, with tough decisions necessary. FERC has a critical problem of reliability in the electric bulk power transmission system and the uncertainty of future transmission investment as the driving necessity to act.
FERC SHOULD TAKE THREE IMMEDIATE STEPS IN ITS RTO NOPR TO ADDRESS THE RELIABILITY ISSUE AND CORRECT MOST OF THE UNCERTAINTY OF FUTURE INVESTMENT IN THE BULK POWER TRANSMISSION SYSTEM:
In my opinion, the three most important actions that FERC should take are:
CREATE MANDATORY RTOS AS LARGE AS POSSIBLE TO PROTECT AGAINST CASCADING INTERCONNECTION-WIDE OUTAGES:
In May, 1996, after I became President of the CPUC, California had two major outages, on July 6th and August 10th, both caused by occurrences outside the state but resulting in major damages and inconveniences within California. I learned the hard way what happens when multi-control centers control one multi-state interconnection, California suffered at least $100 million in damages on August 10th alone. Some have estimated the damage as being much more. Finally, one entity conceded that weaknesses on their system caused the August 10th outage. Without emergency action taken by Oregon to use idle hydro generation, that was supposed to be spilling water over the dam for fish mitigation, California outage on August 10th may have recurred in each of the next few days. This is because the initial outage damaged several generating units within California reducing significantly the generating capacity available the following days. These two experiences are clear in my mind and are some of the most compelling reasons for my strong recommendation in this area that RTOs should be as large a part of an interconnection as possible. I suggest FERC gain an understanding from the experts how close the Western States came to losing the entire Western Interconnection on August 10th, 1996.
It would seem that a minimum size RTO would be 50,000 MW's of transmission capacity, since the Electric Regional Council of Texas (ERCOT) is about that size and it seems to be working fine. Ideally one RTO for each of the five interconnections should be the goal, to protect against interconnection-wide cascading blackouts. This is what I understand came close to what happened on August 10, 1996, in the Western States Interconnection's 125,000 MW's of transmission capacity, located in 14 western states, three Canadian provinces and three Mexican states. The Western States Interconnection had a so-called islanding capability which should have divided the entire system up in three or four separate isolated sub-systems immediately. Somehow it did not work completely as planned and the risk of losing the entire interconnection was close. Both the WSCC and NERC Report on the outage should explain what happened to FERC, since I believe it has a direct bearing on the realistic size of RTOS.
From this experience, I believe, interconnection-wide RTOs are the ultimate goal, but if engineers can convince FERC that the islanding concept or some other such concept will work to avoid the entire interconnection from coming down at the same time, then this type of sub-system should be used to set the minimum size RTO. Geographic regions within an interconnection will argue their separate interest of local control should prevail because of the states rights arguments. Although many will not agree, I believe that local control, although desirable from a states rights standpoint, should be sacrificed to get interstate control of the entire interconnection from a reliability standpoint in one RTO under FERC's jurisdiction.
The states rights issue can be dealt with by appointing public representatives from each state, to represent the public interest of each state, on the Board of the RTO. This is what, I believe, was the intent of the California Legislation creating the California Oversight Board in its SB1890. The August 10th outage happened in the middle of the month-long daily meetings with the California Legislature's Joint Committee and all the interested parties. I believe the outage weighed heavily on the legislative representatives, and that the expansion to include other states was also envisioned in SB1890, since the CPUC was ordered in the bill to draft an interstate compact and attempt to get all the other western states to adopted it.
Although this compact was not adopted by the other states, I believe that the Oversight Board and FERC's RTOs are very similar organizational concepts and should be adopted by FERC, with mandatory participation by all entities that are owners of the interconnection transmission lines, including the provinces in Canada and the states in Mexico. These other countries will have to be brought in to the RTO by an international agreement or compact with the help of other U.S. agencies as appropriate, the Department of the Secretary of State or the Department of Energy.
The RTO must have the ability of establishing various reliability standards that each and every participant should be required to comply with. Otherwise one exception, who is not a participant of the RTO, can cause a similar August 10th problem without any accountability to the RTO and avoiding any possible fines that would be imposed. The heart of reliability from the Western Interconnection experience is for the RTO, or FERC with delegated authority to the RTO, to set mandatory standards, that all participants must comply and tough sanctions or fines be imposed commensurate to the consequences of the problem or outage created. I do not see how it would be possible to have the proper level of authority and accountability without mandatory participation of all entities' operation on the interconnection or a sub-system RTO, if it is not one RTO for the entire interconnection.
The concept of multiple control centers within the interconnection seems to be somewhat inefficient in a world of large RTOS and should be addressed by the appropriate technical experts in order to consolidate the many control centers as much as technically feasible, to improve the coordination and communication within an interconnection.
TRANSCOS RATHER THAN ISOS MEET THE TWO OBJECTIVES OF RELIABILITY AND NEW INVESTMENT:
Based on the experience of the CPUC's restructuring, deciding what type of an organization the transmission assets should be included is extremely difficult, but equally extremely important, depending on your objectives. In California our primary objective, as discussed earlier, was mitigating market power of the incumbent Investor Own Utilities (IOUs). The fear was that the IOUs would use the wires to advantage the use of their generation assets. The second objective was to determine an organization structure that could be implemented in a short enough time-frame to allow competition in the market place soon enough to solve the problem of high rates and the sick economy.
Ideally a Transco, created by a complete divestiture of the bulk power transmission assets of the three IOUs into one California Transco, was what I considered the ideal and best solution. Unfortunately I, personally, also did not believe this could be done soon enough to meet our time line objectives, and it was not clear enough that the CPUC had the specific legal jurisdiction to order such divestiture. Thus the Independent System Operator (ISO) was the practical second choice, one that could be implemented in a much shorter time frame and meet the market power objectives.
The lack of trust between the IOUs on one side and the large customers and the Independent Power Producers (IPPs) on the other, of the IOUs' using or abusing market power drove the separation even further when the California Power Exchange (PX) was separated from the ISO. This additional separation was necessary to separate the physical scheduling and dispatch function from the economic pricing of the energy. I will discuss more about the necessity of having the PX below, and will leave further comment until then.
Either a ISO or a Transco could work to establish a RTO but, I believe, a Transco would be the better choice.
TRANSCOS ALSO BEST ALIGN THE INTEREST OF THE CUSTOMER, THE MANAGEMENT AND THE SHAREHOLDER:
Today the California ISO seems to be working very well and is meeting the objectives discussed above of mitigating market power and performing the scheduling and dispatch function as intended. However, I still believe today that a privately, for-profit Transco, would be more preferable because it would let the entity operating the transmission assets also be the owner of those same assets, i.e. turn a passive investment of the IOUs into an active investment of the independent shareholders of the new Transco. Then FERC could get out of the way and let a clear profit incentive drive the Transco to make the new transmission facility investment needed today throughout the U.S., without a preconceived process of regulation to decide what should be built, when, and by whom.
The California ISO has a process to determine future capital needs. I understand it allows for consideration of new generation assets instead of solely new transmission facilities. This is a method that in theory should work but it has the ring of the BRPU (Biannual Resource Plan Update) process. Those familiar with this method to select future generating capital expenditures proposed in the early 1990's at the CPUC, know that this final order got bogged down in the detail of the process and that no one was satisfied with it. FERC even issued an order indicating that BRPU was not consistent with PURPA. The BRPU proposed decision was on the CPUC's agenda when I was first appointed to the Commission in February, 1993, and was passed and deferred until it was finally killed in the final months of my term in 1998. I am afraid that the process at the California ISO may have a similar fate. Therefore, I believe that a completely independent Transco with its own set of stockholders, independent of the IOUs', would have all the profit incentives needed to grow its assets and meet the transmission facilities assets needed to meet the growing demands of today's and the future market.
FERC could still oversee the capital additions for gross error by the Transco of building transmission assets where generation assets may have been preferable. A profit driven Transco with realistic powers to select or approve a site, I believe, would make decisions quicker, make investment faster and meet the expansion needs of new demand better than would the ISO scenario.
Let me explain by example from the telecommunications industry how a Transco could be formed. Pacific Bell, the Regional Bell Operating Company for both California and Nevada had both its wire line and its cellular phone operation under the same ownership of shareholders. It decided that it would better serve future growth and the shareholders' value and interest to spin-off the assets of the cellular system into a new corporation with the stock of this new entity given to the shareholders of Pacific Bell. Thus after the stock was distributed to Pacific Bell's shareholders it was no longer under the management or control of Pacific Bell but a completely new entity, Air Touch with new management and new shareholders. It is my understanding that once separated the stock price of the two public companies was greater than the old consolidated share price before the spin-off.
I believe this is the same process proposed by Entergy Corporation (Entergy), but the shares of the new corporation are to be put in a non-voting Trust still owned by Entergy. The Transco I have in mind would merely take the shares in non-voting Trust and distribute them to the shareholders of Entergy, thus creating a completely independent Transco which the shareholders of Entergy may keep or sell, but in which the management and control of the Transco would be by a new management, reporting to a different set of shareholders. (These may be the same or different than the shareholders who received the new shares.) Once the new Transco is formed and operating with new management, regulated solely by FERC, FERC can allow it to flourish the same as an interstate gas transmission pipeline does today, by growing assets in a profitable manner.One of the main disincentives of this type of Transco creation is that FERC would be the sole regulator. If FERC set the rate of return incentives lower than these assets earn under state regulation today, no IOU management will want to spin off assets to its shareholders who thereby will earn less than they are today under state regulation. FERC needs to consider the appropriate ratemaking and rates of return to be allowed the new entities, whether a Transco or an ISO.
After FERC had approved initial rates for the new entity, I believe that a Performance Based Ratemaking procedure, which would allow the Transco to earn within a range of returns on equity based on its performance, would provide the necessary incentives for the IOUs to be willing to spin-off its transmission assets. This would allow what would otherwise be a passive investment, without the owner having any say-so in the new RTO or ISO structure because they could not have more than a one percent ownership in the RTO Board which would oversee one or more Transco within the interconnection. FERC must make it financially attractive for the IOUs to spin-off their transmission assets to a new entity or they will not believe it is in their shareholders' best interest to do so and will fight it all the way. Although it is a challenge, I strongly recommend separately owned independent Transcos over the ISOs of today.
The CPUC allowed a substantially lower return on stranded assets to provide a balance with the customers in sharing the burden of recovery of stranded assets. The CPUC allowed a 7.5% return, a debt return, instead of the allowed return on rate base of approximately 9.5%. This was in effect an almost 400 to 500 basis point lower return on equity. It would seem that FERC could do the same thing in reverse, to allow a substantially higher return on rate base for the new Transcos or ISOs to provide an incentive to the IOUs to divest their assets into a Transco or transfer control to an ISO.
FERC SHOULD REQUEST CONGRESS TO PROVIDE BACK-UP SITING AUTHORITY TO PROTECT AGAINST UNREASONABLE SITING DECISIONS AND DELAYS BY STATE AGENCIES:
The challenge to build future transmission lines in a multi-state environment could be very difficult. If an RTO, Transco or ISO determine after considering all other types of new investment in transmission facilities that a new transmission line must be built through several states, individual state siting agencies will have to approve the route through its state. If one state determines that there is little, if any, direct benefit to its state, then siting approval may be delayed unreasonably or denied. This would cause a major obstacle to building a interstate transmission line through multiple states without FERC having some back-up siting authority to override state authority. I believe, this authority given to FERC could be the same as that it possesses today for interstate natural gas pipelines that cross multiple states.
Again this touches the sensitive area of states rights, but as much as I share that concern as a states rights advocate myself, if a new transmission line is a multiple-state line that is needed to meet the future demand needs of the interconnection in total, there must be a means to have it built in a reasonable length of time. Siting delays or disapprovals by non-cooperating states could be divisive and fatal to the timely construction of critically needed facilities to meet the needs of the reliability of the interconnection and the other states using it.
FERC must have the necessary authority to enforce reasonable siting request, or critically needed future transmission lines could be delayed to a point that it causes risk to the interconnection that could cause a reliability crisis that FERC and the rest of the world is trying to avoid. Granting the right of eminent domain to Transcos or ISOs in the same Federal legislation would be another way to overcome the same problem. This too could be accomplished by FERC's recommending to Congress that such right of eminent domain be granted instead of granting FERC back-up siting authority.
COMMENTS ON OTHER ISSUES REQUESTED IN THE NOPR:
There are a number of other issues that the NOPR requested comment to which I could add some input, but in the interest of only dealing with the most important issues that I have had the knowledge from my experience as a California Commissioner, I will comment on one other issue.
This issue was addressed in the California restructuring and was one of the most divisive issues between the Commissioners. The majority decided to require a Power Exchange (PX) because, and I am speaking for myself as part of the majority, that: (1) it was needed to protect the small consumers from so-called "cream-skimming"; (2) it was needed to develop a deep liquid cash market to help facilitate a financial futures market in electricity; and (3) it was needed to create a hourly electricity market to allow all customers to react to price signals every hour of the day or night to encourage energy conservation.
Cream Slimming Argument--I believe this argument and some of the other reasons for a PX are addressed in the CPUC's December 20, 1995, policy decision on electric restructuring, but let me describe some of it for FERC's benefit. The CPUC set a mandatory requirement that (1) the IOUs were to sell all their electricity generation (that they did not divest) into the PX and (2) the IOUs were to buy all their electricity from the PX to be sold to all the IOU's remaining customers who did not elect to switch to new supplier. Thus, there was complete assurance that the small residential and commercial customers would have access to all the generation units, both low cost and high cost production.
Without the PX and the mandatory IOU selling to and buying from the PX, the larger customers would have the leverage to buy from the low cost generation units, while the residential and small commercial would be left with the dregs, the high cost generation units. This point has not been completely appreciated yet in California because the SB1890 legislation froze all rates during the transition period, when most of the stranded assets are to be recovered. Because of a number of factors, mainly the profitable sales of the fossil generating plants and ultimately the sale or appraisal of the hydro generating units, this transition period has ended for one of the IOUs, San Diego Gas and Electric Co., and is expected to end for the other two in the year 2000. At this time the rate-freeze will end, or has ended, and the PX price will be the price (averaged over 30 days each month) that all the remaining customers, both large and small, who have elected not to switch to new suppliers, will pay each month for the energy portion of their bills.The average price for energy in PX for the first year was 2.4 cents per kwh, while the old embedded price included in the IOUs' overall rate was over 5.0 cents. The point is, do you believe that the small residential customers would have gotten the 2.4 cents average PX price after the rate freeze ends, or would the large customers received a lower price and the residential and small customers paid a higher one, if no PX had been established? This was the most important reason to me for the creation of the PX and the mandatory sell/buy requirements.
The real benefit of the California restructuring and opening the market to competition has been masked because of the rate freeze. Once it ends for all three IOUs, which I expect to happen next year, rates for the residential and small commercial customers will drop between 10% to 15% more, (the SB 1890 legislation has already required a 10% reduction up front in 1997 to these same small customers) while the large commercial and industrial customers will receive a 20% to 25% reduction at the same time.
Develop a Deep Liquid Cash Market to Facilitate a Financial Futures Market--Although not as apparent why this is important, the CPUC was told by a number of financial experts that if you are going to have a electricity futures market there must be a developed cash market for the financial future prices to key off of, and one the market was confident would not be manipulated by regulators or others when the financial futures are about to expire at their term. The reason the futures market was important, at least to me, was that it was needed by new electric generators, IPPs if you will, to mitigate their financial risk to build new speculative generating plants without having firm contracts to sell most of the output to the IOUs, as in the past.
Another reason to establish the PX was because of the concern that no one may build new generating plants in a competitive market. The PX price provided a clear price to IPPs and their investors as to what the market price of electricity is, has been in the recent past, and likely to be in the future. The PX price was also to facilitate a financial futures market for the IPPs to lay off some of the non-contracted for capacity of the new plants built on speculation of being able to sell its output after the plant is constructed and in operation.
Although there are other factors causing the IPPs to build new generating plants, California should be satisfied with over ten plants now applying for siting of new generating units at the California Energy Commission. This request for over 10,000 MW's of new capacity is equal to about 20% of California's total generating capacity today and is estimated to cause over $5.0 billion of new investment in California at a cost of $500 a KW.
The Hourly PX Prices Will Provide Important Price Signals to Both Conserve Energy in Periods of Peak Usage and to Mitigate Market Power--The December 20th, 1995, CPUC policy decision stressed at length the importance of providing hourly price signals to all customers to cause conservation of energy, primarily in peak periods. It would also benefit lower customer bills and help clean up air quality of the environment. Again this opportunity has been deferred because of the rate freeze, but as I stated earlier, this freeze is expected to end in the year 2000. With deregulation of both the metering and billing function of the energy portion of all customers' bills at the beginning of 1999; and with the end of the rate freeze in the year 2000, all customers will be able reduce their bills and conserve energy during the peak by reducing their usage during high-priced peak periods. This can be done by contracting with their IOU or a new supplier, for a real-time pricing tariff and obtain a real-time hourly meter to measure the hourly use.
Another important reason of customers' reacting to real-time prices, is to mitigate market power during peak periods. With demand subject to price elasticity by customers having both real-time meters and pricing, when the price of energy escalates on peak usage days customers will be able to reduce some of their usage and prices will fall. A representative of the U.S. Department of Justice has made this point, I believe, at a National Association of Regulatory Utility Commissioners' (NARUC) Electricity Committee meeting; but it was after the CPUC had already issued its policy decision. This logic became very compelling to me as an additional reason for a PX and a reason, I believe, it is very important for FERC to consider in addressing the Power Exchange issue.
SUMMARY OF COMMENTS:
Although I am interested in the national issues of reliability, electric restructuring and retail competition, my primary concerns and comments relate to the potential California impact of FERC's new rules and procedures in the RTO NOPR. As mentioned in the introduction, these comments are based on my first-hand knowledge and experience on the CPUC and subsequently as an active observer.
FERC has a unique opportunity to take a bold and courageous course of action that will not only assure future national reliability of the nation's bulk power transmission system, but also eliminate the great uncertainty overhanging the entire future investment in electric transmission facilities.
I wish FERC well in making a final decision and issuing a final order by year-end. California needs FERC's decision and the nation needs it. I am confident that the FERC's commissioners and staff are up to the challenge.
P. Gregory Conlon