Between a Rock and a Hard Place:

Transmission Planning and Expansion

 

Aleka Scott, Transmission Manager

PNGC Power

Portland, Oregon

 

For the Mighty Columbia Conference

October 23, 2003

 

 

Since August 14 2003, it’s fashionable to be “in the know” about transmission.  Suddenly everyone is interested in what you have to say.  For those of us who have spent years in the trenches of transmission policy, this recognition is a welcome respite from the anonymous grinding nature of transmission discussions.  My entire career was vindicated when the Wall Street Journal carried a map of transmission constraints on its FRONT page. 

 

Sic transit gloria – such passes glory.  The trenches remain and the issues do not yield to sound-bite size fixes.  And so here we are.  Talking transmission.  Do try to stay awake!

 

One of the major areas of concern in the transmission arena these days is lack of capital investment.  Contrary to ex-DOE Secretary Bill Richardson’s proclamations on August 14, 2003, we do NOT have a third-world transmission system.  Indeed, any of you who have been to the third world know of what I speak.  We do not have rolling blackouts on a regular basis.  We do not experience grid collapses every 6 months – or even every 18 months.  More money can be put into the system to reduce the odds of a blackout, but the law of diminishing returns rules.  Reliability in a transmission system can always be improved but the risk of outage cannot be reduced to zero.  However, it is true that there has been very little transmission investment in the nation as a whole over the past 15 years.  Loads have grown, as has our dependence on sensitive electrical devices. 

 

On the generation side, development of new capacity has been freed from the hands of the regulated utility.  There was a rush in the 90’s to build generators, mostly gas-fired combustion turbines.  For a time, the excess capacity in the transmission system allowed rather robust access to loads by these new generators.  But investment in the transmission system has not kept pace with load growth or generation additions.  We no longer have a gold-plated transmission system.

 

We have a system that was largely built to serve loads of vertically integrated utilities.  Transmission lines were designed to bring a utility’s remote generation to its load centers.  Here in the Northwest, the exceptions are the Interties to California.  BPA, with its excess of spring and summer generating capacity built Intertie lines, both AC (4800 MW into northern California) and DC (~3,100 MW into the LA area).  These lines made possible the seasonal exchanges of power which help both regions optimize costs.

 

In the vertically integrated utility, generation and transmission planning were tightly integrated.  A utility would look at the total cost of delivering generation to load.  The cost of the generation including any fuel deliveries and the cost of transmission needed to reach load were evaluated as a package.  The reliability needs of the transmission system were also considered in this planning. Thus generation planning and transmission planning were part and parcel of an integrated planning effort.

 

Enter the new world of deregulation.  FERC Order Nos. 888, 889, 888a 889a.  Separation of transmission from generation functions.  Selling of ancillary services as separate items.  Control room separation.  Applying standards of conduct is not like separating conjoined twins.  It’s more like trying to strip the circulatory system out of the body.  The circulatory system needs blood.  The blood needs the circulatory system.  The body does not operate well if the two are not exactly coordinated and operated within very small tolerances. 

 

So we find ourselves in an awkward place just now.  We have separated our transmission systems from the generation system.  These systems are now planned and, for the most part, operated independently of one another.  The Open Access system put in place by FERC through its Order Nos. 888 and 889 ripped the system apart.  While this new world order may have mitigated the problems of discriminatory access, it has created a whole new set of problems.  These problems are not easily solved.

 

Transmission systems need power to run.  Power systems need transmission to move power.  For example, the recent voltage collapse of the Eastern system, and the outage here in the West in August on 1996, were both voltage collapses – not enough reactive power was supplied to the system by generators.  Since reactive power cannot travel very far because of the resistance in the transmission lines, reactive support[1] (i.e. generation) must be located in strategic areas to support the transmission system. 

 

A contributor to the August 1996 Western Interconnection voltage collapse was the lack of response and indeed unexpected performance of generation.  Generation did not supply reactive power to the grid as expected and tripped off-line much sooner than expected.  Although the causes of the northeastern blackout are not yet known, we do know that this event was a voltage collapse.  It is likely that generation failure to perform as expected contributed to the severity of the recent blackout.   A mismatch between planned generator performance and actual performance can lead to significant problems on the grid.  In this regard, transmission planning would benefit from mandatory reliability criteria that applied not only to control area operators and transmission owners but also to generators.

 

Particularly bedeviling is the problem of transmission planning for new generation.  Transmission planners have a plethora of information about where generation will be located.  BPA, for example, has over 25,000 MW of generation in its interconnection “queue.” Generators make requests to individual transmission owners for interconnection and are placed in a  “queue.”  Individual studies looking at the impacts of each generator are performed per the queue order.  Multiple transmission systems may be impacted by a new generator or transmission request, however the study process typically stops at the border of the requested transmission owner.  To make matters worse, a new generator may need interconnection services from one utility but transmission service from one or more other utilities.  In today’s Order 888 and 889 environment, all requests for interconnection and transmission service are looked at by transmission provider and by request.  The lack of the ability to coordinate requests among impacted transmission owners may require a generator to pay for multiple studies and may indicate the need for redundant or excess improvements.  Further exacerbating the problem is the inability in today’s system to “cluster” transmission requests, either by time period, by complementary nature of the requests, or by geography.

 

Transmission planning is fraught with new uncertainties.  A generator may or may not proceed even after a request is studied.  Often transmission system work has a much longer lead-time than generation construction, often at least double the lead-time of a generator.  What is the significance of this disparity in lead-times?  A new generator could be constructed in say 2-3 years.  Transmission construction can take 5-7 years.  So a generation investment could destroy or greatly lessen the value of a transmission investment halfway through the transmission investment process.  Couple this with regulatory uncertainty regarding recovery of transmission investment and longevity of transmission rights, and you get nervous investors.  Nervous investors mean either no or more expensive investment.  

 

And what of merchant transmission?  Perhaps the very long investment return period (30-40 years), or the inability to secure the value of the investment in a changing regulatory environment, or the incredible technical difficulties of siting, rating, and running a transmission line in an interconnected grid discouraged those intrepid investors.  Certainly FERC’s seesaw of proposed regulation has not decreased fear of regulatory takings.  For example, regulatory taking can occur by an RTO’s forced auction of rights, by being denied recovery at either the state or federal level, by losing the value of a transmission investment when a generator goes in on the congested side of a path, or simply by the derating of a line for reliability purposes.

 

Further, transmission reliability investments have suffered.  Of course, anyone who has been around transmission planners (pocket protectors required) knows that it can be a fine line between expansion for reliability and expansion for economic reasons.  Rarely does an investment serve only one purpose. Whether because the ultimate service to load obligation has been weakened by deregulation, because of environmental and community protest (NIMBY) over new lines, because investor-owned utilities are preserving their scarce capital for the seemingly more lucrative deregulated generation or telecom market (ha!), or because of regulatory uncertainty concerning stranded costs and cost recovery, little reliability investment has occurred for over a decade.

 

Lack of transparency is a problem in today’s transmission planning and expansion world.  Data that was once available for planning is now considered commercially sensitive, confidential information.  This hamstrings existing planning efforts from identifying beneficial projects on a system-wide basis.  Future planning efforts need full information so that transmission problems and solutions are made transparent to all transmission stakeholders. 

 

So the problems are clear:

 

  1. Disconnection of generation and transmission planning caused by rise of the independent generator and the separation of transmission and generation functions.

 

  1. Uncertainty regarding generator location and timing.

 

  1. Queuing process looks at one project at a time.

 

  1. Queuing process looks at one transmission system at a time.

 

  1. Differing lead times for generation and transmission construction.

 

  1. Differing investment return periods: transmission being longer term (30-40 years), generators have much shorter return periods.

 

  1. Technical complexities of transmission including siting, permitting, rating, and operations in an interconnected system.

 

  1. Lack of transparency of problems and solutions

 

  1. Lack of common and sufficient data

 

Are there solutions to this quagmire?  Is there any way to rationalize the planning and expansion of the transmission system?  Let’s talk about the vision of a transmission system planning and expansion program that could work.  This vision is fairly straightforward.  The first step is an independent, robust planning process open to all interested parties that evaluates reliability and expansion on a system wide basis and results in recommendations as to needed upgrades or additions.  Secondly, a dispute resolution mechanism is necessary as there will undoubtedly be disagreements regarding efficacy of and allocation of costs of recommended actions.  The third and most important element of a planning and expansion process is the authority, the teeth, to get recommended transmission built. 

 

Let’s elaborate on the basic vision.  Many of the words used in this arena are loaded with meaning.

 

“Independent” planning is fundamental to transmission planning success.  FERC’s separation of transmission and generation and its standards of conduct are attempts at independence of the transmission planning system from the generation or merchant side of the business. Independence in transmission planning is the bedrock upon which non-discriminatory planning should be based.  Independence ensures that generators and transmission users can trust that their interests are fairly considered and that decisions are unbiased.  It is also critical that the planning entity be independent in order to obtain confidential commercially sensitive data from generators and loads.  Independence is the grease that will make the transmission planning process work.

 

“All interested parties” means that solutions other than transmission are considered in the process.  It also means that all stakeholders (regulators, owners, users, developers, environmental and community interests, and others) are welcome to participate in the planning process.  Solutions to problems stand a much greater chance of eventual implementation if all interested parties have input to the final product.  This is particularly true of participation by state regulators.  While structural changes in basic regulatory structure are not in the works, participation by regulatory staff keeps the regulatory community up to speed on projects that may eventually come before it for cost recovery.  This open process should provide some substantial measure of demonstration of prudency for any project that comes out of the process, thereby increasing the chance of recovery.

 

“Robust” means that wires as well as non-wires alternatives to transmission problems should be examined.  It means that the planning is done by an independent entity.  It means solutions are transparent to all stakeholders.  For example, if a particular area has transmission constraints only during a very few winter hours, a demand-side curtailment program might be more cost effective and timely than a new transmission line.  Or perhaps a small peaker unit located near load would make more sense.  The robust, independent, open to all process would identify transmission options as well as alternatives to transmission.

 

“Authority” to get things built, or to allocate costs of construction, is desperately needed.  There are many transmission planning forums: NRTA, NWTPC, NTAC, SSG-WI, or OTCPC to name a few.  However, because transmission is expensive to build, recovery is uncertain, and benefits often flow to multiple parties, many needed projects wind up in transmission planning purgatory – meetings full of sound and fury signifying nothing.  Some entity needs to be granted authority to either compel transmission construction or allocate costs of needed transmission reliability expansions to transmission owners.  This authority could rest with an RTO or with an independent transmission planning and expansion entity. 

 

This independent planning entity would need to develop and maintain a database for transmission planning.  This common database would include load data, generator data and power flow base cases.  This database would not only reduce planning and expansion disagreements within the region but would also be incorporated into a west-wide planning process.  Transmission owning utilities would have an obligation to make data available to the planning entity.  Generator data should also be required.  Confidentiality of data would of course have to be addressed.  However, much of our regional planning efforts have floundered of late because load and generation data are considered confidential.  In this regard the planning entity’s independent nature would help parties feel comfortable that they are not turning data over to their competitors.  We must find a way to look at the big picture again, not just the little bits and pieces. 

 

Further, the planning entity could study interconnection requests or transmission service requests that impact more than one transmission owner.  Or going further, a common queue for requesting interconnection or transmission service could be formed.  The common interconnection queue (say for the Northwest) could also result in a single study being performed on a system-wide basis.  Clustering of requests could also be accomplished by this planning entity.  The planning entity could perform its studies on a cyclical basis – say an annual or bi-annual cycle.  In this way all of the impacts of new generation interconnection would be studied and addressed.  A common queue and study process and the ability to cluster requests would substantially reduce study costs, increase study effectiveness, reduce the need for multiple requests, and speed answers to interconnection and transmission service requests.

 

This planning process would be for higher voltage facilities – those facilities that impact bulk transfers across the system.  Below this threshold, the planning entity could simply require a demonstration that power can be reliably delivered to wholesale loads such as cooperatives, munis, or PUDs.

 

In summary,

 

  1. The transmission planning entity is independent of market interests.

 

  1. The planning process is open to all and problems and solutions are transparent to all stakeholders.

 

  1. Planning is done in cycles so that generation projects can be incorporated into a planning cycle.  There is a single region-wide queue for interconnections requests and a single queue for transmission requests.  Studies for such requests could be done on a system-wide basis.

 

  1. Planning is done on a system-wide flow basis for high voltage facilities; on a reliability basis for lower voltage facilities serving wholesale utilities. 

 

  1. There is one set of planners which studies the high voltage system.

 

  1. The planning process is open with inputs coming from generators who have made requests, non-transmission alternatives (demand-side), and other interested parties.  States have representatives in the planning process for ease with eventual siting or recovery activities.

 

  1. The planning entity is given backstop expansion authority; i.e. either the power to construct and collect rates from transmission owners or the ability to allocate costs to transmission owners for collection through transmission rates.

 

  1. The local planning inputs into subregional planning as necessary. Sub-regional (i.e. Northwest) inputs into regional (i.e. west-wide) as necessary.

 

  1. The independent planning entity maintains a common database of loads, powerflows, and other data necessary to do transmission planning.  It has the authority to compel production of data from transmission owners and generators.  This common data is incorporated in the west-wide studies as well.  Confidential data is protected by the independent planning entity.

 

We in the Northwest have an opportunity to craft our own solution.  The good news is that quite a bit is being done.  Here in the Northwest we are well on our way to reforming our planning and expansion process.  The Seams Steering Group – Western Interconnection Planning Work Group or SSG-WI PWG is working on a west-wide transmission plan.  The Northwest Power Pool’s Transmission Planning Committee is gearing up to be the sub-regional planning entity for the Northwest including responsibility for database maintenance.  It is the authority issue that remains unsolved.  The RTO West Regional Representatives Group (RRG) is currently examining different ways to address these planning problems.  Whether the result is the RTO West Stage 2 proposal or something short of it, there is plenty of room for improvement in the planning and expansion arena.  There is broad agreement that planning reform should be fast-tracked. Action take as a region may forestall action taken by FERC.  We can still be masters of our own destiny if we act quickly.  

 

Note:  This article has been reprinted in the March issue of “The Electricity Journal.”

 



[1] Although it is possible to construct static VAR devices, generation is the most common source of voltage support to the transmission system.