In November of last year, NERC issued its latest Long Term Reliability Assessment in which the recently anointed Electricity Reliability Organization (ERO) painted a rather grim picture.The report projected demand to increase by 19% over the next decade in the US (13% in Canada), and even warned of the potential for rolling blackouts in as little as five to ten years if transmission constraints are not addressed in the most congested areas.Capacity margins, currently averaging 17% nationally, will drop to just 7% by 2015.
Meanwhile, the cost of grid reliability continues to put a multi-billion dollar drag on the US and Canadian economies. The California ISO announced earlier this year it had “cut” reliability-related costs (e.g., reliability-must-run generation, out-of-sequence dispatch, etc.) to $476 million in 2006.If that sounds like a dubious cause for a press release, consider that the ISO spent $670 million in 2005 and a whopping $1.1 billion in 2004.The upside is that all that money flowing toward solving the congestion problem makes for a strong “price signal” to would-be investors in transmission projects, and there have been some big ones announced in recent months.
Hydro One will build a 500kV line from its Bruce nuclear facility to its Milton substation, a distance of 180 km, in order to facilitate two reactors returning to service as well as the development of 700 MW of wind resources in the area.The project, which will provide 3,000 MW of new transmission capacity, represents the largest expansion project at Hydro One in twenty years.Next door at Hydro Quebec, a 1250 MW back-to-back HVDC link announced in November will provide Ontario with more emissions-free hydro power as well as a new interconnection between the asynchronous Ontario and Quebec systems by 2009.
Other proposed projects, however, remain only “proposed.”San Diego Gas and Electric (SDG&E) has plans for a transmission project that would run east-west across Southern California’s Imperial Valley.The utility estimates the line would produce $57 million per year in savings in foregone congestion charges and increased access to low-cost generation from outside the state.The project would shave $1 million per year in avoided line losses alone.
Regulators and state-level authorities have also been busy.The California Energy Commission, for example, is now looking into designating transmission corridors in the state along the lines of the national corridors envisioned in the Energy Policy Act of 2005 (EPAct).A bill in the state senate would streamline the permitting process for projects in identified corridors.On March 27, Colorado governor Mark Ritter signed two bills into law, one expanding the state’s commitment to obtaining more of its electricity from renewable sources and one introducing EPAct-style enhanced cost recovery for transmission projects within so-called “energy resource zones.”The latter act is designed to facilitate reaching the goals of the former.
Whose job is it anyway?
The legislative moves and the announced projects fall into a typical industry definition of “reliability,” specifically, improving the capacity and resiliency of the high voltage transmission system.A more inclusive concept of reliability would extend to distribution and generation, but perhaps part of the reason we focus so much on transmission, aside from the much larger impact of an outage at that level, is because it’s much harder to identify who is actually responsible for transmission-level reliability.
At the distribution level, the answer is simple: the local utility is responsible for the reliability of its network. Problems experienced within a given service territory are unlikely to affect neighboring systems, much less customers hundreds of miles away, so it’s a fairly self-contained question.Transmission, obviously, affects more people over a wider area, but the really complicating factor is that there are many different entities that all play a material role in maintaining the grid’s integrity.There is broad consensus on what the objective is (i.e., a reliable transmission system), but exactly how that goal is to be achieved is less obvious.
EPAct is a massive piece of legislation, and it includes a variety of measures aimed at improving the reliability of the US power system.Two elements, however, have received an inordinate amount of attention since the Act’s passage: the establishment of mandatory reliability standards (and an accompanying enforcement regime), and the creation of National Interest Electric Transmission Corridors (NIETCs).A closer look at both of these components reveals potential fault lines, which to be fair, the entities involved are now in the process of addressing.
Setting the Standard(s)
Following the August 2003 blackout, the call for mandatory reliability standards reached a crescendo.Two years later, EPAct provided a response—national standards that would be backed by a rigorous enforcement regime with penalties reaching up to $1 million per day for non-compliance and administered by an independent Electricity Reliability Organization (ERO).NERC was certified as the ERO in July 2006, and since that time has worked hard to develop standards through its stakeholder process and get them approved by FERC.
On March 15, FERC approved 83 of the 107 standards submitted by NERC, but also sent 58 of those back for further clarification.The remaining 24 standards were deemed to be unenforceable, or applied only on a regional level.Subsequently, NERC submitted eight region-specific rules that will only apply to the WECC area, but FERC has not ruled on those as yet.
The development of the standards— which largely mirror the voluntary regime NERC presided over in its previous life— is encouraging, but the big question remains as to who, exactly, these rules apply to. The standards themselves offer no definitive statement, and FERC has not ruled on the issue.The text of EPAct isn’t much help. The law uses very broad language, defining the entities subject to ERO oversight as “users, owners and operators of the bulk transmission system” that are necessary to run the transmission grid.That includes generation, but not distribution.
So who does this definition include?
The answer hinges largely on how you define “bulk transmission”.NERC’s interpretation includes entities operating transmission facilities at 100kV or above, with further definition on a regional basis.However, FERC has stated that, while it will use NERC’s definition, it reserves the right to re-interpret it to address any gaps FERC sees in the standards’ coverage.
This is a curious state of affairs, and it could present a significant amount of uncertainty in how the industry’s new reliability regime will function.NERC is set to begin enforcement of the standards on June 1, with enforcement focused mainly on the most serious violations.FERC has even suggested discretion in enforcement of penalties for those entities that have not been subject to reliability standards before such as public power agencies.
The Commission appears to be treading a fine line, though. While FERC seems to be OK with the kid glove treatment for the newcomers, Commission Chairman Joseph Kelliher was less accommodating in his response to calls for a delay in penalties across the board.
“They’ve had two years of field testing in 2004 and 2005,” he said in reference to the utilities subject to the standards. “I’m focuses on the summer of ’07.I think our job is to get as many standards that meet the statutory test enforceable before the summer of 2007.”
Cross-Border Enforcement
As if the wrangling within the US wasn’t enough, there remains the question of how the newly certified ERO will fulfill its role with entities located in Canada.In April of 2006, NERC filed to be the ERO in each border province, but must still establish working agreements with each of them.That process is ongoing, sure to provide job security for a small army of lawyers, engineers and policy analysts.
Some provinces are further along than others, and the nature of the compliance requirement differs from one to another.Utilities in Alberta, Manitoba and Saskatchewan, for example, all currently operate under NERC standards by virtue of membership in WECC and the Midwest Reliability Organization.In New Brunswick and Ontario, NERC standards are “baked in” to the wholesale power market rules for those areas, so all market participants must comply with them to retain their right to buy and/or sell power.Layered on top of all this are the Memoranda of Understanding (MOUs) that NERC is seeking to establish with each of the provinces to formalize its authority.
Once the MOUs are in place, presumably all will be well.NERC will have the authority it needs under provincial law to carry out its role as ERO.But what will happen in the meantime if/when a Canadian provincial authority disagrees with NERC’s assessment of a penalty against one of its resident utilities?Consider the following excerpt from NERC’s comments in a recent FERC filing. The “body” in question is the ERO.
If a body mandated by the [Quebec] Régie under the agreement referred to above considers that an entity subject to a reliability standard does not comply with the standard, the body must give the entity the opportunity to submit observations, and report to the Régie on its findings and may recommend the application of a sanction. After giving the entity the opportunity to be heard, the Régie is responsible for determining if the entity has failed to comply with a reliability standard, and impose, if appropriate, a sanction that may not exceed 500,000 $CAN a day.
At current exchange rates, that maximum sanction comes to less than half the $1 million (USD) per day top end of NERC’s penalty matrix.Further, the provincial regulator still retains final authority.It may be unlikely, but the possibility exists under this language for the Quebec Régie to nullify or greatly reduce a penalty assessed by NERC against a Quebec-based entity, or even to overturn the ERO’s determination that a violation occurred.
Of course, this is exactly the kind of situation parties on both sides are seeking to avoid with the establishment of an MOU.The key will be to get these agreements signed and in place before the “real” enforcement begins this summer.
The Corridors of Power
“Backstop siting authority” was perhaps the most talked about element of the entire electricity title in EPAct, and with good reason.Siting large transmission projects had become a regulatory odyssey stretching out to more than a decade in a few high-profile cases.Now, the US Department of Energy (DoE) has the authority under EPAct to designate National Interest Electric Transmission Corridors, and any project proposed within one of those corridors could receive siting approval from FERC if the local and state authorities fail to act within one year.
EPAct sought to speed up the siting process for transmission with the NIETC provision, but there are two important and interrelated gray areas in the statute.The first is the question of when that one-year clock starts to tick, and the second centers on what constitutes a “failure to act” on the part of the state regulator.Neither of these issues is likely to be settled in the near future, and either could provide the basis for a protracted court battle.Given that siting is perhaps the most contentious issue in the T&D business, it may be up to an administrative law judge to define what Congress intended.
DoE is expected to issue draft NIETC designations in June, based on its congestion study (also a product of EPAct) and the deluge of comments the agency received on the subject.Draft designations will be followed by a public comment period before the agency assigns final NIETC designations by August 8, 2007.
Reliability Through Efficiency
While the need for increased transmission investment has been obvious for some time, the fact remains that even under favorable siting processes new lines take years to build.Even FACTS devices, which increase transfer capacity and stabilize voltage, can take a year or more to come online.The reality of the situation is that, in some locations, these options either are not technically feasible or may not have the impact in the short term that is required.
Perhaps that’s why NERC President Rick Sergel at a recent conference in Washington, DC said that he sees demand response as the number one priority for enhancing grid reliability.His reasoning is simple:DR delivers an immediate impact with relatively little up-front investment (depending on the nature and scope of the given program, of course).
Sergel’s suggestion is more than wishful thinking, too.There is historical precedent to support it.During the 2000-01 power crisis in California, customers in the state affected a 10% reduction in demand, and that was with the programs and communication processes in place at the time.Mostly, it was fear of rolling blackouts that drove consumer behavior, but the point was made.Demand response offered a very real alternative to adding supply from the spot market, if even possible, or reducing demand through less voluntary means.
Really, demand response is one form of efficiency, if you accept a broad definition of the term.It amounts to doing more with existing resources, and therein lies perhaps the greatest untapped potential in the quest for greater reliability because in a constrained system, a megawatt saved may well be better than a megawatt generated if you can’t get the power where it needs to go.
DoE is pushing efficiency via standards for distribution transformers, and while the improvement on a per-unit basis is small (a few percentage points), the impact when multiplied across the entire installed base is significant.Figures for T&D losses are often cited in the 8% - 10% range, and if even a small fraction of those losses can be avoided, the savings go right to the economy’s bottom line.
There are, of course, other ways to cut losses in the T&D system.HVDC transmission, for example, is being used today over much shorter distances thanks to the advent of a voltage source converter-based variety of the technology (e.g., the Cross-Sound Cable between Long Island and Connecticut).Even gas insulated substations contribute to grid efficiency by allowing power to come into a city center at higher voltage rather than incurring the losses associated with stepping voltage down at an outdoor substation on the outskirts.
The demand side, though, is where efficiency has the greatest potential.Compact fluorescent light bulbs are often cited as an example of technologies that present a win-win in the form of cost savings for the user and reduced demand for the utility.Now consider another example, variable speed drives.Motors power everything from compressors to assembly lines and consume more industrial power than any other single device.The vast majority of motors, though, run at full speed all the time, even when they don’t have to, because they lack a variable speed drive to control them.With a VSD in place, a motor can be programmed to run only when needed and the difference in energy usage can be enormous.Savings of 60% are not uncommon, making for a very rapid return on investment.
The confluence of cost savings and energy efficiency is clearly the sweet spot for improving reliability on a system-wide basis.When a technology comes with a business case as compelling as that of a variable speed drive, the buyer doesn’t need any further reason to implement it.The impact on reliability is merely a bonus, and an external one at that.
Residential and smaller commercial customers may not face choices as obvious as the plant owner looking to bring down his six-figure electricity bill, but the principle still applies under a more holistic idea of efficiency.For the residential customer, this concept of ‘macro efficiency’ might simply mean running the dishwasher at night. The appliance still uses the same amount of power, but the system as a whole is made more efficient, and more reliable, by shifting that usage to off-peak periods.
The last several years have seen significant changes in the way both the power industry and the grid itself function in North America.Most of the attention has focused on the restructuring of wholesale and especially retail energy markets, but now the industry faces perhaps an even greater challenge. Our electricity infrastructure is aging, even as we become ever more dependent upon it.Reliability is essential, but to make the transmission system as robust as we need it to be will require industry professionals, regulators and even customers to develop a more nuanced understanding of just what that term, “reliability,” means when placed into a societal context.
In technologies like FACTS and variable speed drives, we have the means to improve efficiency and in turn, reliability.In EPAct, we have a legal framework for defining and ensuring reliability at a national, and even international, level.And we have regulatory mechanisms in place like cost recovery during construction to encourage reliability-enhancing projects.All the pieces are on the table.Now it’s up to us to put them together.
About the Author
Bob Fesmire is a communications manager with ABB's Power Products and Power Systems divisions.He writes regularly on transmission and distribution, IT systems and other industry topics. He can be contacted at bob.fesmire@us.abb.com.
