Monday, November 28, 2011€¦ · from the proposed Susquehanna-Roseland transmission line, the U.S. Department of the Interior’s National Park Service said Nov. 21 in a draft environmental

Volume 10 Issue 47 Monday, November 28, 2011

© 2011, SNL Financial LC. All Rights Reserved.

Minn. utilities tracking more than 100 transmission issues

BPA, California ISO pilot tests intra-hour scheduling

Fast-tracked SunZia project releases economic impacts study

Q&A: ISO-New England CEO Gordon van Welie, Part I

PJM official to tell FERC: EPA rule reliability safety valve a necessity

House energy leaders press FERC on reliability impacts of EPA rules

Colo. regulators urge utilities to work together on transmission plans

Ariz. strategic plan calls for unifying fragmented solar industry sectors

In this IssueClick on headline to advance to story

Continued on p 12

Continued on p 12

ISO-NE could see thermal overloads, voltage violations by 2020mailto:[email protected] Peter Marrin

A recent study by ISO New England Inc. said that under a variety of scenarios and demand levels, potential thermal overloads and volt-age violations could occur in almost every area of Vermont and New Hampshire by 2020.

Working three years with transmis-sion owners and the Planning Advisory Committee, a group of market participants and other stakeholders, the New England grid operator analyzed the power system in New Hampshire and Vermont to determine

how it would perform under nearly 500,000 different scenarios.

The end result, the “Vermont/New Hampshire Transmission System 2011 Needs Assessment,” identified the areas of the sys-tem in Vermont and New Hampshire that could potentially fail to meet mandatory federal and regional reliability standards.

The study, which was finalized in early November, also saw potential overloads and voltage violations in north central and western Massachusetts.

“In fact, many of these potential violations could occur at current levels of demand,” the grid operator said in a Nov. 17 posting on its website. “In addition, a number of these issues exist with or without [Entergy Corp.’s] Vermont Yankee nuclear station continuing to operate as it does today.”

A second study, which will identify poten-tial regulated transmission solutions to address the identified needs, is near comple-tion, while a third study provides high-level

In draft EIS, Park Service views ‘no-action’ option as best for 500-kV Pa.-NJ line

mailto:[email protected] JP Finlay

Given the potential environmental impact from the proposed Susquehanna-Roseland transmission line, the U.S. Department of the Interior’s National Park Service said Nov. 21 in a draft environmental impact statement that it preferred that no action be taken on the line.

In its study, the Park Service compared no action on the line with five route alterna-tives. “Alternative 1, the no-action alterna-tive, was selected as the environmentally preferred alternative by the NPS,” the agency said. “This decision was based on the avail-

able scientific data about the proposal and mitigation measures presented by the appli-cant and collected by NPS. An analysis of this data made it clear that alternative 1 best meets the requirements of the environmen-tally preferred alternative.”

The proposed line garnered national attention in October when it was named to a federal fast-track response list for transmis-sion projects around the country. The line would move power to New Jersey, an area with reliability concerns. The draft EIS said the other alternatives presented would have

Organized power markets are stepping up their efforts to integrate wind power, accord-ing to a group that has been tracking the issues for two decades.

In collaboration with the U.S. Department of Energy and its National Renewable Energy Laboratory, an international information and analysis organization called Utility Variable-Generation Integration Group, or UVIG, on Nov. 15 released a summary of the state of North American power markets. The group

was formed in 1989 to focus on wind inte-gration.

The summary is an extensive chart, a quick reference to compare markets and market rules that affect, or are affected by, wind interests. It was compiled from a sur-vey of nine regional transmission operators: the Alberta Electric System Operator, the California ISO, the Electric Reliability Council of Texas Inc., the Midwest ISO, ISO New England Inc., the New York Independent System Operator, the Ontario Independent

Power markets survey shows increasing accommodation to wind energy

mailto:[email protected] Kerry Bleskan

mailto:[email protected]



Monday, November 28, 2011

© 2011, SNL Financial LC. All Rights Reserved. SNLEnergy

Page 2

Electricity System Operator, PJM Interconnection LLC and Southwest Power Pool Inc.

Researchers found that every North American regional transmis-sion organization dealing with large-scale wind integration is using wind plant output forecasts to improve operational reliability and economics. RTOs and ISOs are increasingly factoring wind genera-tion into the economic dispatch process and allowing wind genera-tors to bid into the day-ahead market, UVIG said.

The researchers asked questions on the structure and scheduling of energy markets, types and techniques of wind forecasting in use, whether negative pricing is allowed, and whether the grid operator has any kinds of situational restrictions on wind power. Special atten-tion was paid to ancillary services requirements and markets and capacity markets, reserves and value.

Some trends seem to be emerging in forecasting, such as increasing availability of ramp forecasting and the near-ubiquity of centralized forecasting. The lone exception, ISO New England, is implementing a centralized forecasting system and the first phase is scheduled to be online in the third quarter of 2012. Methods of allocating the costs of forecasting, by contrast, are about evenly split between RTOs that cover the costs themselves and those that allocate it to variable generators.

A few operators report that wind is having an impact on ancillary services requirements. The New York ISO found that integrating 8 GW of wind will require higher amounts of regulation but will have no impact on the amount of operating reserves for contingency events. An ISO New England study said higher regulation may be necessary at higher levels of wind penetration, but existing resources may be enough to supply it.

SPP also foresees a need for more regulation capacity. The Cal-ISO has switched to a seasonal regulation purchase schedule, so purchases are affected by high wind seasons. The Cal-ISO expects to need more regulation and more load following in the future. The AESO does not need to make any changes yet but is considering add-ing regulation and developing a ramping service to deal with wind, perhaps including a ramping-down service provided by wind.

COMPANIES REFERENCED IN THIS ARTICLE:

http://www.snl.com/interactivex/snapshot.aspx?id=4098930Alberta Electric System Operator http://www.snl.com/interactivex/snapshot.aspx?id=4058979California ISO http://www.snl.com/interactivex/snapshot.aspx?id=4065908Electric Reliability Council of Texas Inc Independent Electricity System Operator http://www.snl.com/interactivex/snapshot.aspx?id=4060718ISO New England Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4087542Midwest ISO http://www.snl.com/interactivex/snapshot.aspx?id=4061775New York ISO http://www.snl.com/interactivex/snapshot.aspx?id=4062332PJM Interconnection LLC http://www.snl.com/interactivex/snapshot.aspx?id=4098958Southwest Power Pool Inc.

http://www.snl.com/interactivex/doc.aspx?CDID=A-13682358-125862PR: UVIG Releases Update to Summary of Status of Wind Power in Electricity Markets

http://www.snl.com/interactivex/doc.aspx?CDID=A-13718929-115622Misc: AESO

http://www.snl.com/interactivex/feedback.aspx?Id=13718723&Action=estory* E-mail this story.

Minn. utilities tracking more than 100 transmission issues


In a biennial report to state regulators, Minnesota’s transmission-owning utilities said they have identified more than 100 existing transmission inadequacies across the state.

Every utility that owns or operates transmission facilities in the state has to report every two years on the status of the transmis-sion system, including proposed solutions to “present and foresee-able inadequacies.” The reports to the Minnesota Public Utilities Commission are required under a state law passed in 2001 and are due every two years. The transmission owners held a webcast for the public on Nov. 18, talking about the report and transmission plan-ning in general.

Previous PUC efforts to involve the public in planning have fallen flat, with low attendance at public meetings and webinars. This time, regulators asked utilities to report on their contact with local officials and the public during the transmission planning process. The utili-ties said Midwest ISO processes allow “ample opportunities for the public to be involved.” A majority of the state’s utilities are Midwest ISO members. “Those utilities that are not part of MISO also provide opportunities for the public to be involved in their transmission planning activities,” the utilities said, but the public does not care unless a project is near them.

“The experience of Minnesota utilities has shown that unless a project has been identified and includes a general area where the project is needed (such as an overall area of the state or specific issues between substation locations or municipalities), stakeholders are uninterested in the process,” they said.

Covers studies, some planningNumerous regional, state and project-specific studies have been

conducted since the 2009 report, including the huge Midwest ISO Regional Generation Outlet Study and the Strategic Midwest Area Renewable Transmission Study. Preliminary studies on the $425 mil-lion, 345-kV La Crosse-Madison line in western Wisconsin, also called Badger Coulee, are complete, the transmission owners reported, and the line may be approved for regional cost sharing at the Midwest ISO board meeting in December.

The report said it is difficult to predict which transmission ser-vice requests will lead to actual construction, but did spotlight the request from Manitoba Hydro for increased transfer capacity from the province into Minnesota. A number of different line configura-tions, routes and voltages are under consideration, the utilities said, and Minnesota utilities are active in the various Midwest ISO studies to evaluate options.

Manitoba Hydro could add 2,000 MW or more in hydroelectric generation capacity between 2012 and 2023. The Midwest ISO will conduct a market study to investigate the possible ancillary service value of increasing hydro storage in combination with Midwest wind generation. Researchers plan to complete the analysis in 2012 and publish a final report in 2014.

The Midwest ISO member utilities opted to refer readers to the Midwest ISO comprehensive planning process instead of including their project information in the report to the PUC.

The report includes projects from past years, which are consid-ered “needs” until construction is complete. It identifies a few new projects to address needs, including a line upgrade by 2017 on the

http://www.snl.com/interactivex/snapshot.aspx?id=4098930








http://www.snl.com/interactivex/doc.aspx?CDID=A-13682358-12586


http://www.snl.com/interactivex/feedback.aspx?Id=13718723&Action=estory




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230-kV Richer-Roseau-Moranville line, substation and transformer expansions, and several projects to interconnect wind facilities. Xcel Energy Inc.’s Brookings project is listed as new, as is the Hampton-Rochester La Crosse line. Both 345-kV lines are part of the CapX2020 transmission expansion effort.

An upgrade to a 230-kV line between Shakopee, Minn., and Granite Falls, Minn., was mentioned in previous reports to provide new capacity into the Twin Cities from the Dakotas and elsewhere in Minnesota. The Corridor Upgrade Project will likely not be needed in the 2016-2018 timeframe as expected, the utilities said, and may not be needed at all given a number of projects planned within the Midwest ISO.

State ahead of RPSSystemwide, the amount of renewable energy capacity acquired

and operational is 4,531 MW, which exceeds the state’s renewable energy standard 2012 requirements by nearly 1,500 MW and is almost 500 MW above the 2016 target. Multi-state utilities estimated their compliance needs outside of Minnesota will rise from 390 MW in 2012 to 1,158 MW in 2016.

The estimate, which the utilities cautioned is for transmission planning purposes only, does not include projects that are under contract but are not yet commercially operational. Planned additions and retirements will result in a net addition of 428 MW by 2016.

The utilities reporting are: American Transmission Co. LLC; Dairyland Power Cooperative; East River Electric Power Cooperative Inc.; Great River Energy; Hutchinson Utilities Commission; ITC Holdings Corp. subsidiary ITC Midwest LLC; L&O Power Cooperative; Marshall Municipal Utilities Power Agency; ALLETE Inc. subsidiary Minnesota Power Inc.; Minnkota Power Cooperative Inc.; Missouri River Energy Services; Xcel Energy subsidiary Northern States Power Co.; Otter Tail Corp. subsidiary Otter Tail Power Co.; Rochester Public Utilities; Southern Minnesota Municipal Power Agency; and Willmar Municipal Utilities.


http://www.snl.com/interactivex/snapshot.aspx?id=4022309ALLETE Inc. ALEhttp://www.snl.com/interactivex/snapshot.aspx?id=4076261American Transmission Co. LLC http://www.snl.com/interactivex/snapshot.aspx?id=4059544Dairyland Power Cooperative http://www.snl.com/interactivex/snapshot.aspx?id=4059748East River Electric Power Coop Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4060312Great River Energy http://www.snl.com/interactivex/snapshot.aspx?id=4060609Hutchinson Utilities Commission http://www.snl.com/interactivex/snapshot.aspx?id=4099990ITC Holdings Corp. ITChttp://www.snl.com/interactivex/snapshot.aspx?id=4151279ITC Midwest LLC http://www.snl.com/interactivex/snapshot.aspx?id=4060938L&O Power Cooperative http://www.snl.com/interactivex/snapshot.aspx?id=4061259Manitoba Hydro http://www.snl.com/interactivex/snapshot.aspx?id=4087542Midwest ISO http://www.snl.com/interactivex/snapshot.aspx?id=4061513Minnesota Power Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4061516Minnkota Power Cooperative Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4061528Missouri River Energy Services http://www.snl.com/interactivex/snapshot.aspx?id=4057754Northern States Power Co. - Minnesota http://www.snl.com/interactivex/snapshot.aspx?id=4057017Otter Tail Corp. OTTRhttp://www.snl.com/interactivex/snapshot.aspx?id=4147257Otter Tail Power Co. http://www.snl.com/interactivex/snapshot.aspx?id=4062652Rochester Public Utilities http://www.snl.com/interactivex/snapshot.aspx?id=4063076Southern Minnesota Municipal Power Agency http://www.snl.com/interactivex/snapshot.aspx?id=4064034Willmar Municipal Utils Comm http://www.snl.com/interactivex/snapshot.aspx?id=4025308Xcel Energy Inc. XEL

http://www.snl.com/interactivex/doc.aspx?CDID=A-13735174-110612Industry Document: 2011 Minnesota Biennial Transmission Projects Report


BPA, California ISO pilot tests intra-hour scheduling

mailto:[email protected] Peter Marrin

The Bonneville Power Administration and the California ISO have launched a new intra-hour scheduling pilot they hope will reduce operational issues and expand opportunities for wind power devel-opers by allowing them to schedule their electricity into California

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Page 4

every 30 minutes instead of once an hour, thereby helping them balance the variable output of their resource.

According to a Nov. 21 BPA press release, the pilot project doubles the pace of the interstate energy transfers to better match the ups and downs of wind energy, which helps reduce costs for both sides. Depending on the output of a wind facility, participants can adjust schedules, making up the difference with a California resource. Without the pilot’s ability to adjust schedules closer to real time, the expected delivery from wind resources is subject to reductions, and that means the ISO has fewer grid dispatch options, BPA explained.

BPA administrator Steve Wright said the agency hopes to learn from the testing phase, which “we hope will help maximize the use and value of Northwest wind energy.”

Traditional power plants provide steady output bought and sold on an hourly basis but wind power output can vary within minutes. Since the input and use of electricity must match perfectly in real time to assure reliable service, opening markets to respond in small-er time increments is one way to compensate for the variability and better integrate renewable wind power.

According to California ISO President and CEO Steve Berberich, FERC is encouraging intra-hour scheduling to deal with the opera-tional issues of integrating variable resources, and the pilot “allows the ISO to gain actual experience in meeting FERC’s requirements.”

Southern California Edison Co., a unit of Edison International, is the first utility to participate in the initiative.

The pilot has added benefits for federal hydroelectric dams, which had been balancing unexpected changes in wind generation.

In some instances, intra-hour transactions have helped wind pro-ducers sell additional energy instead of cutting generation off when the balancing capacity of the hydroelectric system was exhausted, BPA said.

“This is a natural next step in our efforts to relieve some of the strain on the hydro system while helping wind generators access markets that can use their generation,” said Cathy Ehli, BPA’s vice president for transmission marketing and sales.


http://www.snl.com/interactivex/snapshot.aspx?id=4058810Bonneville Power Administration http://www.snl.com/interactivex/snapshot.aspx?id=4058979California ISO http://www.snl.com/interactivex/snapshot.aspx?id=4056943Edison International EIXhttp://www.snl.com/interactivex/snapshot.aspx?id=4009083Southern California Edison Co.

http://www.snl.com/interactivex/doc.aspx?CDID=A-13729141-108092PR: BPA and California ISO enhance regional coordination with faster response in energy scheduling


Fast-tracked SunZia project releases economic impacts study


Building the SunZia transmission project in southern New Mexico and Arizona would create thousands of construction jobs, but the real boom would be in renewable energy projects, state universities found.

SunZia Transmission released economic impact studies on Nov. 22 for the 500-mile, 500-kV line itself and the renewable energy projects that could interconnect to it. The line alone would create 6,200 jobs

over a four-year construction period, paying more than $420 million. The project also would pay more than $90 million in state and local taxes during construction, researchers said. Operations and mainte-nance jobs would pay $7 million annually.

The SunZia line, which would run from central New Mexico to the Pinal Central station northwest of Tucson, Ariz., is one of seven trans-mission projects nationwide recently selected for a federal regula-tory streamlining experiment.

Associated renewable energy projects could create several times more jobs, albeit over a shorter, two-year construction period. The 36,700 workers would be building solar photovoltaic, solar thermal, wind and geothermal generation projects, which have varying costs and construction times. Researchers came up with costs and jobs estimates for each type of generation project and presented a range of possible project construction scenarios.

Researchers looked at three possible designs for the 500- to 550-mile line: a single 500-kV, alternating current line; double-circuit, 500-kV AC; and one 500-kV AC line run parallel to a 500-kV DC line. Depending on the route, the single-line option would cost between $826 million and $869 million. The double-circuit plan would range between $1.475 billion and $1.6 billion, and the hybrid AC-DC plan would cost between $2.5 billion and $2.6 billion.

The hybrid plan is by far the most expensive plan but creates more jobs and brings in more economic benefits than the others, researchers said. During the construction period in one of the route options, for example, the single-line scenario creates 3,540 jobs paying a total of $239.4 million and would generate US$52.3 million in state and local taxes, not including property taxes. The 6,805 jobs created under the hybrid scenario would pay US$458.2 million; state and local taxes would total $133.4 million.

The studies were written by research teams from the University of Arizona and New Mexico State University. They broke their results down to the county level, covering five southeast Arizona counties and 13 southern and central New Mexico counties. The line itself may cross all five Arizona counties and eight of the New Mexico counties. All but one of the affected counties have higher unemployment rates than their state’s averages.

The SunZia project has a number of participants. SunZia Transmission, owned by Southwestern Power Group II, Shell WindEnergy Inc. and Tucson Electric Power Co., will own 86% of the completed project. The remainder will be owned by Salt River Project, 13%, and Tri-State Generation & Transmission Association Inc., 1%.

Shell WindEnergy Inc. is a subsidiary of Royal Dutch Shell plc. Tucson Electric Power is a subsidiary of UniSource Energy Corp.


http://www.snl.com/interactivex/snapshot.aspx?id=4011025Royal Dutch Shell plc http://www.snl.com/interactivex/snapshot.aspx?id=4062755Salt River Project http://www.snl.com/interactivex/snapshot.aspx?id=4078667Shell WindEnergy Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4065818Southwestern Power Group II http://www.snl.com/interactivex/snapshot.aspx?id=4200356SunZia Transmission http://www.snl.com/interactivex/snapshot.aspx?id=4063492Tri-State Generation & Trnsmssn Assn Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4057030Tucson Electric Power Co. http://www.snl.com/interactivex/snapshot.aspx?id=4056952UniSource Energy Corp. UNS

http://www.snl.com/interactivex/doc.aspx?CDID=A-13742741-125932Regulatory Filing: SunZia Transmission

http://www.snl.com/interactivex/doc.aspx?CDID=A-13742749-125852PR: SunZia Transmission Project Will Have Positive Economic Impact






















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Q&A: ISO-New England CEO Gordon van Welie, Part I

mailto:[email protected] Peter Marrin

SNL Energy recently interviewed Gordon van Welie, president and CEO of ISO New England Inc., about some of the key challenges the six-state New England grid faces in the coming years on everything from the region’s fuel make-up to the functions of the forward capac-ity market.

In its Strategic Planning Initiative presented Oct. 6, the ISO-NE out-lined five of the largest regional concerns: resource performance and flexibility; reliance on natural gas; generator retirements; integration of variable resources; and alignment of markets and planning.

Prior to taking the helm as president and CEO, van Welie served as ISO-NE’s executive vice president and COO. He joined the company from Siemens Power Transmission & Distribution, where he served as vice president and general manager of the Power Systems Control Division and was responsible for managing information technology solutions for electric companies. Before coming to Siemens, van Welie held several positions at South Africa’s electric utility Eskom.

What follows is an edited transcript of a Nov. 21 interview with van Welie. In this Part I of a two-part series, the head of the six-state New England grid discusses the difficulties of relying too heavily on natu-ral gas and how that dependence will likely only grow in the years ahead as a huge amount of “Old World” generators face retirement.

SNL Energy: You’ve highlighted a growing dependence on natural gas as one of the region’s biggest concerns. Right now

natural gas is New England’s dominant fuel, producing 46% of regional electricity, more than nuclear (29%), coal (11%) and oil (0.5%) combined. If this 46% share is too high, then what is an ideal market share for natural gas in the New England genera-tion portfolio?

Gordon van Welie: I don’t think 46% is too high. Actually, we could probably operate at a higher level. There are two questions for the region. We’re specifically concerned about one, but policymakers might be concerned about the other.

When you think about dependence on a single fuel source you have two things you worry about: one is economic impact and the other is reliability impact.

For New England policymakers, typically they think often about the economic impacts. So were you to be heavily relied — as we are — on natural gas, and the price on natural gas becomes very high, it immediately translates into a higher cost of electricity. And we saw that scenario play out in the 2008 timeframe.

Policymakers are actively discussing this issue of should we try and trade diversity through renewable resources.

The ISO spends most of its time worrying about reliability impacts. And so the thing that worries us is that the natural gas system for electric generation is, by and large, a ‘just in time’ fuel delivery sys-tem. So if you look at the Old World — traditional coal-fired, oil-fired, nuclear powered generators — those generators typically have enough fuel on site to be able to withstand an interruption in what I would call the fuel supply delivery chain.

So, if you are a coal-fired generator you have a pile of coal next to your generator and it will probably last you two weeks or a month

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Page 6

depending on how much you’ve provisioned. If you are an oil gen-erator, similarly, the oil in your tanks can probably keep you going for a couple of weeks and the nuclear generator as you know only has to refuel every 18 months.

Temporary interruption in terms of the supply chain for that fuel does not cause a disruption in electricity supply, whereas in the elec-tric gas generation world, if there is an interruption for any reason, you immediately translate that interruption in the fuel supply into an interruption in electricity supply. So that’s a problem.

A second related problem — and we will be releasing a study shortly that quantifies these issues — is if you have sufficient gas coming into the region to deal with the winter heating load and some percentage of electric gas generation, if during a cold snap period you were to lose some of your non-gas-fired generation to a contingency — let’s say a large nuclear unit tripped — you would then want to compensate by ramping up your gas-fired generation. But that presumes there will be fuel available to them. And we know from experience — and now we know through the study — that we are in a very tight supply-demand balance in New England with regard to natural gas.

The natural gas pipeline system into New England was built out to serve firm heating load. So the local gas distribution companies contract with the pipeline developers to develop enough pipe to meet what they call their winter design days. It turns out then that … the winter design days are a very cold snap period — sort of 20 [degrees] below [zero] type temperatures for three or four days in New England. For most of the time, you are not sitting at that level in the region, so there is additional capacity available on the pipe and most of the gas-fired generators therefore are what they call interruptible consumers of gas from the gas pipelines. So what hap-pens then is if you have a gas pipeline constraint or any kind of gas supply constraint coming into New England, the first consumers to be knocked off the pipes will be the gas-fired generators. And that essentially is the reliability risk we worry about.

And then the question becomes: how do you address that? The first thing is we need to value the requirement. And the way you value the requirement to be able to withstand a fuel supply inter-ruption is to create the requirement somehow through our regional tariff and our regional wholesale market design and then cause generators to firm up their fuel supply. And they can do that in a number of ways. For example, they could choose to implement dual-fuel capability and be able to burn either gas or oil. Or they could put in place local gas storage. There are a number of ways specifically that you can meet the requirement but it begins with creating the requirement in the first instance. And so this is one of our so-called strategic issues that we are working on together with our partici-pants and state regulators in New England.”

The Cross State Air Pollution Rule threatens to retire upwards of 8,000 MW of coal- and oil-fired generation in New England, and there have already been repeated efforts to shut Entergy Corp.’s Vermont Yankee nuclear plant and Dominion Resources Inc.’s Salem Harbor plant. If the percentage of gas-fired supply is already too high, what source of generation do you see picking up the slack?

We have not defined any specific number [for gas generation] that we have in mind.

We could end up with a much bigger number. In fact, we will end up most likely with a much bigger percentage of our electricity sup-ply coming from natural gas because … we’re going to see retire-ments in this region.

We are going to see some of the older oil units retire. The oil units are no longer running because the price of oil is so high compared to natural gas. In fact, the same is true with some of the coal units that we have in this region. We burn fairly exotic coal in this region in order to meet the air regulations that have been put in place by New England air regulators. So the price of oil plus the type of coal we are burning often turns out to be higher than the price of natural gas given the shale gas find. So those units are no longer economic, they are not running that often and over time they will find themselves without adequate revenue to keep themselves viable.

That will be exacerbated in the future when the floor is removed from our forward capacity market.

For forward capacity market auction seven, which will be run in early 2013, the FERC has ordered us to remove the floor. Given that we have had a surplus position in the region it is likely that the price will go below the floor, which means those units such as the oil units who only produced half a percent of our energy last year, will have fewer revenues coming to them.

If you then layer on top of that the compliance obligations result-ing from the new EPA regulations it will make it even less likely that they will continue to operate.

And so as they retire, the question is what will replace them? The answer is the most economic capacity resources that clear through the forward capacity markets, which if you take our recent experi-ence into account, would appear to be demand-side resources and gas-fired resources.”

In Part II, van Welie will discuss the poor performance of some products like oil-fired generators and demand-side resources; what dimensions need to be developed in the forward capacity market in the coming years; and how state renewable goals have encouraged more transmission planning.


http://www.snl.com/interactivex/snapshot.aspx?id=4001616Dominion Resources Inc. Dhttp://www.snl.com/interactivex/snapshot.aspx?id=4007889Entergy Corp. ETREskom http://www.snl.com/interactivex/snapshot.aspx?id=4060718ISO New England Inc. Siemens Power Transmission & Distribution

http://www.snl.com/interactivex/doc.aspx?CDID=A-13420470-131112Presentation: ISO-NE


PJM official to tell FERC: EPA rule reliability safety valve a necessity

mailto:[email protected] Glen Boshart

During a widely anticipated upcoming FERC technical confer-ence on the reliability implications of the Environmental Protection Agency’s clean air regulations, a PJM Interconnection LLC official will be pushing hard for the establishment of a “reliability safety valve” to manage potential generation retirements as a result of the regula-tions.

The conference (AD12-1), to be held Nov. 29-30, was scheduled after FERC came under heavy pressure from various members of Congress to explore the potential reliability impacts of EPA’s Cross-State Air Pollution Rule, or CSAPR, as well as various other existing and pending EPA regulations.









Page 7

Commission Chairman Jon Wellinghoff had repeatedly refused to undertake a comprehensive study of the potential reliability implica-tions of EPA’s rules, insisting that doing so should be the job of ISOs, RTOs and other planning authorities, who can then plan accordingly. FERC on Oct. 7 nevertheless announced that it will hold the techni-cal conference to consider the impacts various EPA regulations may have on the reliability of the nation’s power grid.

Mike Kormos, PJM’s senior vice president of operations, will testify during the conference, and has made his written remarks available in advance.

While refusing to comment on the relative merits of EPA’s rules, Kormos maintained that conducting a comprehensive analysis of the impact of those rules would be very difficult at this time. The issue “presents a classic ‘chicken and egg’ situation,” Kormos said. Since no one yet knows which units may retire and which will be retrofitted to meet the rules’ requirements, he said, “it is very difficult to pinpoint the exact reliability impacts and the breadth of transmis-sion upgrades or other fixes that may be needed to address those actions.”

Moreover, Kormos noted that many generation owners have not yet made those decisions given the uncertainty over the scope of the final EPA rules and their implementation deadlines. Kormos therefore said PJM had to resort to identifying the generating units that may be at risk due to EPA’s rules and consider the impact of vari-ous scenarios.

Noting that during 2010, coal-fired generation provided 41% of PJM’s capacity and 49% of its total energy production, Kormos recalled that a PJM study released in August determined that two of EPA’s rules — the Mercury and Air Toxics Standards, or MATS, rule and the CSAPR — put 11,000 MW of coal capacity “severely at risk” of retirement and an additional 14,000 MW of coal capacity “at risk” for retirement.

Kormos said the key question, however, is whether transmission upgrades, demand response, generation or other solutions can be put into place in a reasonable time frame and at a reasonable cost to substitute for the retiring units. Since considerable uncertainty also exists concerning the answer to that question, he said, PJM teamed with Electric Reliability Council of Texas Inc., Midwest ISO, Southwest Power Pool Inc. and the New York ISO to propose the establishment of a reliability safety valve that would allow generating units needed to maintain system reliability to continue operating without being subject to penalties or other enforcement actions until other solu-tions are put in place.

With regard to PJM, Kormos noted that the forward nature of its capacity market, which secures capacity three years in advance of when it will be needed, provides a degree of certainty that is absent in regions with little or no forward capacity commitments.

Kormos nevertheless lamented FERC orders finding that PJM lacks the authority to prevent a unit from retiring even if that unit is need-ed to maintain system reliability. While PJM has certain other tools to mitigate the reliability impacts of the retirement of such units under normal circumstances, the number of potential retirements and ret-rofits that the EPA rules may precipitate “could be unprecedented in scope” and therefore the usual tools may be ineffective, Kormos said.

For instance, while PJM has not identified any overarching reli-ability impacts associated with potentially retiring units that cannot be resolved with transmission upgrades within the four-year period allowed by the proposed MATS rule, “we know better than to simply gamble on this outcome without providing an appropriate safety valve for changed circumstances,” he said.

Kormos reported that reliability safety valve proponents “have had constructive dialogue” with EPA’s staff about their proposal and “feel that it is both well-grounded legally and the only practical means to address the ‘chicken and egg’ problem associated with affected units.”

He also said EPA must provide up-front guidance to the industry as to how the agency would exercise its penalty authority so that a generation owner does not find itself faced with the Hobson’s choice of being asked by the RTO to operate for reliability while, at the same time, facing potential penalties for doing so.

Kormos suggested that given the difficulties FERC would have in conducting its own comprehensive analysis of the reliability impacts of EPA’s rules, that it coordinate with the various other federal agen-cies with jurisdictional responsibilities in the same area.

For instance, Kormos noted that the secretary of energy has the legal authority under Section 202(c) of the Federal Power Act to order units to operate when needed for reliability, but that process has not worked well in the past. Kormos therefore said the imple-mentation of Section 202(c) should be clarified and streamlined, including addressing how DOE’s authority will interact with that of other federal governmental agencies and the states.

Kormos also stressed the need for close ongoing consultation between FERC and EPA on reliability issues, “with a particular focus on developing appropriate mechanisms built in to ensure that reli-ability can be maintained under the schedules set by the proposed rules.”


http://www.snl.com/interactivex/snapshot.aspx?id=4065908Electric Reliability Council of Texas Inc http://www.snl.com/interactivex/snapshot.aspx?id=4087542Midwest ISO http://www.snl.com/interactivex/snapshot.aspx?id=4061775New York ISO http://www.snl.com/interactivex/snapshot.aspx?id=4062332PJM Interconnection LLC http://www.snl.com/interactivex/snapshot.aspx?id=4098958Southwest Power Pool Inc.

http://www.snl.com/interactivex/doc.aspx?CDID=A-13741527-133572Industry Document: Testimony of Michael J. Kormos, Senior Vice President, PJM Interconnection, L.L.C.


House energy leaders press FERC on reliability impacts of EPA rules

mailto:[email protected] Kathleen Hart

House Energy and Commerce Committee Chairman Fred Upton, R-Mich., wrote a letter to FERC Chairman Jon Wellinghoff on Nov. 22 asking whether the agency has analyzed the reliability and cost impacts of the U.S. Environmental Protection Agency’s economically significant power sector rules.

“[L]egitimate concerns have been raised that EPA’s power sector rules will impose substantial new compliance costs and require-ments and may significantly impact electric reliability,” Upton and Reps. Ed Whitfield, R-Ky., and John Sullivan, R-Okla., wrote in the letter to Wellinghoff. “Costs associated with the rules include the retrofitting of existing generation, construction of new generation, and the build-out of new transmission infrastructure. The Committee seeks information relating to the extent to which FERC, and FERC-jurisdictional entities, have evaluated the impacts of EPA’s rules, and the costs of mitigating reliability concerns, on electricity rates or prices.”











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The House Republicans asked Wellinghoff to directly answer several questions on whether FERC has analyzed the Cross-State Air Pollution Rule, the utility MACT rule and other EPA rules that could potentially lead to an increase in electricity prices. The utility MACT rule requires a decrease in mercury emissions at power plants, while CSAPR requires utilities to reduce power plant emissions that may compromise air quality in neighboring states.

“Has FERC analyzed, or sought analyses by entities under its juris-diction, or the impact of EPA power sector regulations on RTO capac-ity markets? Has FERC evaluated EPA’s estimates of the rate impacts of its power sector rules?” the Nov. 22 letter asked.

FERC has come under increasing pressure from members of Congress in recent months to explain the extent to which the com-mission has explored how various new and pending EPA regulations might impact the nation’s power grid. On Nov. 9, FERC released the agenda for a technical conference it plans to hold Nov. 29-30 to con-sider the reliability impacts of EPA regulations, including CSAPR, on the electric power industry.

Upton wrote a letter to U.S. Department of Homeland Security Secretary Janet Napolitano on Nov. 9 asking whether DHS has ana-lyzed the potential impact of EPA’s power sector rules on the reli-ability of the nation’s grid. “Questions have been raised concerning whether EPA has fully assessed how the cumulative effect” of CSAPR, utility MACT and other power sector rules will impact the electric grid, Upton, Whitfield and Rep. Clifford Stearns, R-Fla., chairman of the committee’s Oversight and Investigations Subcommittee, wrote in the letter to Napolitano. “Commenters have raised concerns that strict regulatory requirements and compliance timelines under EPA’s regulations for the installation of emissions control technologies on electric generating units could significantly impact energy security and reliability.”

In addition, two key senators, Lisa Murkowski, ranking Republican on the Senate Energy and Natural Resources Committee, and James Inhofe, ranking Republican on the Senate Environment and Public Works Committee, wrote a letter to EPA Administrator Lisa Jackson on Nov. 9 pressing her to answer questions the two senators have repeatedly posed about the potential of the agency’s utility MACT rule to impair electric reliability and affordability.

http://www.snl.com/interactivex/doc.aspx?CDID=A-13736490-102942Industry Document: Letter to Jon Wellinghoff


Colo. regulators urge utilities to work together on transmission plans


Regulators are encouraging Colorado utilities to coordinate the 10-year transmission plans due February 2012.

The biennial plans are the first to be prepared under new rules from the Colorado Public Utilities Commission. Plans will show all proposed transmission projects 100 kV and greater, and will be evaluated to ensure plans do not negatively impact each other, avoid duplication of facilities and would be an efficient use of the system. In response to some clarification questions from Tri-State Generation and Transmission Association Inc., the PUC said the utilities are not required to file a single plan but acknowledged it would help.

“The rule requires that each electric utility file a ten-year transmis-sion plan with the commission. The commission stopped short of requiring these to be made as one joint filing in recognition of the

potential extra effort and management that this condition might entail,” the regulators said in a decision adopted Nov. 9 and mailed Nov. 16.

The regulators have said throughout the rulemaking that they do not want the plans to be a burden to Tri-State and Colorado’s other transmission-owning utilities, including Xcel Energy Inc. subsidiary Public Service Co. of Colorado and Black Hills Corp. unit Black Hills Colorado Electric Utility Co. LP. The plans are largely based on exist-ing information and data, the PUC said, and can use the same eco-nomic studies that utilities conduct to comply with FERC Order 890.

Utilities and other stakeholders already work together on the state’s annual integrated transmission plan through the Colorado Coordinated Planning Group. That group also includes public power entities and others not subject to PUC jurisdiction.

A joint filing would help the planning proceeding process and would by definition mean utilities have complied with the part of the rule that requires proposed projects to be coordinated among all transmission providers in the state, the PUC said. “We encourage the utilities to file one 10-year transmission plan that contains the infor-mation concerning each utility’s proposed projects, outreach efforts, economic studies, and other supporting information and, whenever possible, combines the information that is consistent among the utilities,” the regulators said. (Docket No. 10R-526E)


http://www.snl.com/interactivex/snapshot.aspx?id=4215172Black Hills Colorado Electric Utly Co. LP http://www.snl.com/interactivex/snapshot.aspx?id=4010420Black Hills Corp. BKHhttp://www.snl.com/interactivex/snapshot.aspx?id=4057094Public Service Co. of Colorado http://www.snl.com/interactivex/snapshot.aspx?id=4063492Tri-State Generation & Trnsmssn Assn Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4025308Xcel Energy Inc. XEL

http://www.snl.com/interactivex/doc.aspx?CDID=A-13715460-113202Regulatory Filing: Tri-State G & T Assn Inc

http://www.snl.com/interactivex/doc.aspx?CDID=A-13716005-125992Regulatory Filing: Black Hills Corp (BKH)


Ariz. strategic plan calls for unifying fragmented solar industry sectors

mailto:[email protected] Jeff Stanfield

The Arizona Energy Consortium will be guiding the implementa-tion of a series of proposed actions for the long-term growth of the state’s solar industry involving collaboration across financial, techno-logical, research, manufacturing, policy and regulatory sectors.

The recommendations were outlined in a new report, “Arizona’s Solar Strategic Plan,” that resulted from the Arizona Solar Leadership Conference held in September in Phoenix. The AEC is a committee of the Arizona Technology Council. The council describes itself as the main representative for technology companies in Arizona, with solar companies counted among its members.

The plan calls for integrating the solar industry’s supply chain for solar technology development, equipment manufacturers and sup-pliers, solar energy generation producers and workforce training. “At present, Arizona has a fragmented solar industry based on sector silos; this needs to evolve to a united industry based on collaborative interactions within the industry-at-large,” the plan said.

AEC Chair Michelle De Blasi announced the plan. She also chairs the solar energy legal team at Quarles & Brady LLP. The Arizona Solar















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Leadership Conference, hosted by Quarles & Brady, brought together the state’s major solar stakeholders. The consortium of more than 250 members across diversified sectors within the Arizona energy industry will guide implementation of the plan.

“The strategic plan is meant to guide Arizona’s growing solar industry along a sustainable path,” De Blasi said in a Nov. 16 press release. “Our goals are increased jobs, economic development, ener-gy self-sufficiency and security, technology innovation and reduced greenhouse gas emissions — all resulting from increased use of solar energy as a component of a broader energy strategy.”

The consortium has created subcommittees to focus on work-force development, technology innovation and energy efficiency. “Through real collaboration uniting the efforts of the diverse busi-nesses and agencies that make up the energy sector, a sustained economic development for Arizona resulting from increased jobs, tax revenues, and a vital new source of economy will be realized,” the plan said.

The plan called for monetary and nonmonetary incentives and heightened support for Arizona companies with recognized promis-ing solar technologies. Promising companies should be encouraged to locate and remain in Arizona rather than relocating to other states. The state should support desert-friendly solar technology develop-ment with low water use.

Arizona should define projects of significance as measured by employment, energy production and other factors and support those projects with performance-based incentives such as produc-tion tax credits, the plan said.

Permitting should be streamlined across municipalities and the state in order to encourage site selection for projects, including company headquarters in metropolitan areas. The state should con-sider investing in the creation of regional permit approval centers. The development of such regional entities could greatly facilitate Arizona’s permitting procedures, including reductions in both pro-cess time delays and process costs, the plan said.

By allowing the bulk of the permitting process to be housed under one roof, the duplicative nature of previous permitting procedures can be eliminated, the plan said. The governor’s solar task force is coordinating a permitting standardization effort.

Economic development and renewable energy development zones should be set to encourage solar industry cluster growth, the plan said. Enterprise zones of government programs would provide incentives for businesses to locate or expand in targeted, geographi-cally defined areas.

Arizona also needs to work with other statesThe state should coordinate solar efforts with neighboring solar

states, including California, Nevada, Colorado and New Mexico, in efforts to discuss the Southwest regional need for renewable energy, according to the plan. Arizona should initiate an interstate collabo-ration of transmission line development as a means to reduce time delays within the transmission approval process, the plan said.

“In efforts to increase its export capability, Arizona should height-en the development of its physical connections with California ISO,” the plan advised. To increase construction of new transmission lines, Arizona could issue state bonds, according to the plan.

The state should use master limited partnerships to attract inves-tors for solar project development through a master entity and to reduce the twofold corporate and shareholder taxation to one level of taxation. Project investments also should be obtained through public-private partnerships, the plan said.

The use of statewide feed-in tariffs for solar development and allowing securitization of solar projects as cooperative community scale ventures would help distributed solar development, according to the plan.

Decoupling utility rates, the plan said, would provide for more incentives for heightened investment by utility companies in solar project development. That is not a new suggestion; the Arizona Corporation Commission approved a decoupling policy for the state’s utilities in late December 2010. But the strategic plan backs further efforts to implement that policy.

The Arizona Investment Council and Arizona State University are working on creating a centralized database for Arizona’s solar indus-try, with a projected website launch Dec. 31.

“In terms of a mature solar industry, states such as California, and nations, such as China, are considerably ahead of Arizona due to the supportive regulatory policies established by their prospective governments,” the plan said. “Such efforts need to be implemented in our state’s future if Arizona seeks to become a leader in the global solar industry.”

COMPANY REFERENCED IN THIS ARTICLE:

http://www.snl.com/interactivex/snapshot.aspx?id=4058979California ISO

http://www.snl.com/interactivex/doc.aspx?CDID=A-13705801-128522Industry Document: “Arizona’s Solar Strategic Plan” Laying Out Roadmap for Future Growth Issued

http://www.snl.com/interactivex/doc.aspx?CDID=A-13713714-131052Industry Document: Arizona’s Solar Strategic Plan


FERC approves standard mandating annual assessment of transmission transfer capability

mailto:[email protected] Marcy Crane

FERC on Nov. 17 approved a revised reliability standard that requires planning coordinators to perform annual assessments of transmission transfer capability for the near-term transmission plan-ning horizon.

According to the commission, those assessments are to be used as “a basis for identifying system weaknesses or limiting facilities that could limit energy transfers in the future.”

The Midwest ISO and the New York ISO had argued that the revised facilities standard at issue (FAC-013-2) should be rejected as duplicative of certain transmission planning standards. FERC disagreed, however, explaining that the newly approved standard “provides a unique reliability benefit beyond that conferred” by the transmission planning standards.

In particular, the commission noted that the assessment required by the transmission planning standards reflects only projected firm reserved transmission uses, while the facilities standard requires the planning coordinator to consider all projected transmission uses.

“In other words, reliability standard FAC-013-2 differs from the [transmission planning] standards because the former focuses on identifying potential weaknesses that could limit energy transfers across a broader region and requires the planning coordinator to consider any expected transmission uses, regardless of whether they have been scheduled or otherwise reserved, and thereby allows for an assessment that may be more accurate in the outer years of the planning horizon,” FERC said.








Page 10

FERC also rejected the Electric Reliability Council of Texas Inc.’s request to be exempted from complying with the facilities standard. Because ERCOT has no transmission market, the grid operator has been granted an exemption from certain related modeling standards governing the calculation of available transfer capability, or ATC. ERCOT accordingly argued that it should be similarly granted an exemption from the facilities standard, but FERC said no.

The commission explained that while the modeling standards may not apply to ERCOT because they address methodologies for calcu-lating ATC and total transfer capability for the purpose of allocating transmission capacity, the facilities standard “is instead a planning tool.”

“We believe ERCOT, like other regions, will benefit from the assess-ment of potential limitations in transfer capability in the planning horizon over the near term transmission planning horizon that is required under FAC-013-2,” FERC said. (RD11-3)


http://www.snl.com/interactivex/snapshot.aspx?id=4065908Electric Reliability Council of Texas Inc http://www.snl.com/interactivex/snapshot.aspx?id=4087542Midwest ISO http://www.snl.com/interactivex/snapshot.aspx?id=4061775New York ISO

http://www.snl.com/interactivex/doc.aspx?CDID=A-13733154-120852Regulatory Filing: NERC


Cal-ISO filing prompts FERC to rethink reactive power rule

mailto:[email protected] Glen Boshart

FERC is going to take another look at the reactive power provisions of an agency final rule addressing the interconnection requirements for wind facilities exceeding 20 MW.

Sparking the review were requests that FERC revisit an August 2010 order mostly rejecting a California ISO proposal to modify the interconnection requirements for wind, solar and other variable generating resources.

The Cal-ISO had submitted the proposal to reflect the dra-matic change in the types of new generation being built to meet California’s electricity needs and to fulfill a mandate that 33% of the state’s power needs be met with power generated by renewable resources by 2020. That mandate, plus a new state water quality rule, is forcing the Cal-ISO to rely increasingly on variable energy resources — primarily wind and solar generation — to maintain system reliability.

The problem, according to the ISO, is that many variable energy resources are being built with technical characteristics that dif-fer from those of conventional generators. The Cal-ISO therefore proposed requiring variable energy resources to possess technical characteristics comparable to those required for conventional gen-erators. For instance, the proposal would require variable resources to adopt the same low-voltage and frequency ride-through capa-bilities, power factor design and reactive power capabilities, voltage regulation and generator power management requirements as con-ventional generators.

FERC’s August 2010 order found many of the proposed revisions lacked support, however, and the agency therefore rejected them without prejudice, which left the ISO free to file a similar proposal but with more support. The commission did conditionally approve

proposed tariff revisions for frequency and low voltage ride-through requirements, though.

In a Nov. 17 rehearing order, FERC continued to find that the ISO failed to show that wind and solar generators will displace more conventional generators in California “in a timeframe and manner that supports the proposed tariff revisions.”

FERC further asserted that the agency’s Order 661-A established a process that allows transmission providers to consider the opera-tional implications of integrating large amounts of wind generation in the interconnection process and to takes steps, such as impos-ing power factor design and operations criteria related to reactive power, to alleviate any related issues.

However, the agency also noted that a 2007 renewable integration study found that the Cal-ISO’s system performance would continue to be adequate without requiring reactive power capability from new wind and solar power generators.

The commission nevertheless said the Cal-ISO proceeding raises questions about whether new wind and solar plants should be required to provide reactive power and whether the process estab-lished for wind resources under Order 661-A should be modified. That final rule takes a case-by-case approach to deciding whether wind plants need to provide reactive power, mandating that a trans-mission provider show through a system impact study that such gen-erators must provide reactive power in order to maintain the safety or reliability of the transmission system.

The commission therefore directed its staff to hold a technical conference to examine whether the agency should reconsider or modify the reactive power provisions of Order 661-A. In particular, FERC said staff should examine what evidence is needed to support a request to apply reactive power requirements more broadly than to individual wind generators during the interconnection study pro-cess. (ER10-1706)


http://www.snl.com/interactivex/snapshot.aspx?id=4058979California ISO

http://www.snl.com/interactivex/doc.aspx?CDID=A-13711386-118272Regulatory Filing: CAISO


CIBC: Canadian infrastructure investments a boon to energy companies

mailto:[email protected] Susan Nelson

Spending on energy infrastructure projects in Canada has been strong for the past several years and will remain strong for several more, analysts at CIBC World Markets said.

In a report, “This Infrastructure Spend Has Legs,” released Nov. 17, CIBC Managing Director of Equity Research Paul Lechem looked at both energy infrastructure projects and, more broadly, public infrastructure investments in things like roads, bridges, schools and hospitals.

Declaring that Canada is in the midst of an “infrastructure super-cycle,” Lechem said current levels of spending in Canada are at their highest levels in decades. The top 100 infrastructure projects in Canada have an aggregate investment of C$96 billion, the report said, with the largest chunk in transportation.

Energy projects, including power generation and transmission but not pipelines, total about C$33.5 billion.













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Lechem made five “top picks” of companies that could ben-efit from the commitment to infrastructure investments: Toronto-headquartered construction firm Aecon; Toronto-headquartered IBI Group; Montreal-headquartered SNC-Lavalin Group Inc.; profes-sional consulting services firm Stantec, headquartered in Edmonton; and TransCanada Corp.

The report noted that many energy sector infrastructure invest-ments are backed by publicly owned utilities and are therefore ultimately paid for by ratepayers. “Investment decisions are, for the most part, dictated by anticipated rates of return, not government policy of the state of government finances,” Lechem said. “As such, we see continued strength in energy infrastructure investments in the coming years.”

Looking at power generation infrastructure, the report noted that much of it was being driven by government legislation and subsidies for renewable energy projects. Every province except Alberta has renewable generation standards or goals aimed at reducing green-house gas emissions.

In 2010, Canada generated about 350 TWh, which is “second in the world only to China,” the report said. Seven large hydro projects under development, which will generate about 5,000 MW once com-pleted, are estimated to cost approximately C$23.5 billion. Other mega-projects that are under development or proposed would gen-erate another 5,700 MW or so and are worth C$20 billion.

The hydro projects under way are all being done by provincial government-owned utilities: BC Hydro and Power Authority, Hydro-Québec, Manitoba Hydro and Ontario Power Generation Inc.. One private sector company, Emera Inc., is involved in a planned hydro/transmission project, in partnership with another provincial govern-ment-owned utility, Nalcor Energy.

Wind power is expected to have significant growth, with around 1,000 MW of additional installed capacity this year. Ontario has the largest amount of installed wind capacity, at about 1,600 MW.

Despite opposition in Ontario from some communities and a moratorium on offshore wind projects the province has “a healthy pipeline of wind projects currently under construction (at least C$6 billion) and in the proposal stage (at least C$2+ billion),” the report said.

“Nuclear is expected to also generate multi-billion dollar oppor-tunities in the future,” the report said, noting the planned refurbish-ments of Ontario Power Generation’s Pickering B and Darlington plants.

Major transmission line projects, such as Alberta’s critical trans-mission infrastructure and Hydro One’s 500-kV Bruce-Milton line in Ontario, were also noted.

Not all projects succeed, CIBC noted, citing delays from lengthy regulatory reviews and opposition on environmental grounds to projects such as the Mackenzie Gas Project, whose sponsors include affiliates of Imperial Oil Ltd., ConocoPhillips Co., Royal Dutch Shell plc and Exxon Mobil Corp.; TransCanada’s Keystone XL pipeline; and Enbridge Inc.’s Northern Gateway Pipeline, plus TransCanada’s Oakville power plant in Ontario.

Pipeline and utility projects, however, have benefited not only from the strong investment cycle but also from “investor demand for high-yielding but stable and defensive investments,” the report said. “As such pipelines and utilities stocks have enjoyed ongoing strength over the past couple of years with a basket of Canadian stocks essentially doubling from the early 2009 lows.”


http://www.snl.com/interactivex/snapshot.aspx?id=4058660BC Hydro and Power Authority http://www.snl.com/interactivex/snapshot.aspx?id=4059405ConocoPhillips Co. http://www.snl.com/interactivex/snapshot.aspx?id=4072693Emera Inc. EMAhttp://www.snl.com/interactivex/snapshot.aspx?id=4089108Enbridge Inc. ENBhttp://www.snl.com/interactivex/snapshot.aspx?id=3007562Exxon Mobil Corp. http://www.snl.com/interactivex/snapshot.aspx?id=4060616Hydro-Québec http://www.snl.com/interactivex/snapshot.aspx?id=4010653Imperial Oil Ltd. http://www.snl.com/interactivex/snapshot.aspx?id=4061259Manitoba Hydro http://www.snl.com/interactivex/snapshot.aspx?id=4225551Nalcor Energy http://www.snl.com/interactivex/snapshot.aspx?id=4062060Ontario Power Generation Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4011025Royal Dutch Shell plc http://www.snl.com/interactivex/snapshot.aspx?id=4194014SNC-Lavalin Group Inc. http://www.snl.com/interactivex/snapshot.aspx?id=4087757TransCanada Corp. TRP


Bonneville agrees to delay draft environmental report for 500-kV line


The Bonneville Power Administration has agreed to delay publica-tion of an environmental assessment of its I-5 Corridor Reinforcement Project in Washington and Oregon.

On Nov. 16, the agency announced it would hold off on publi-cation of a draft environmental impact statement for the 500-kV project until spring 2012. Bonneville had planned to issue the report by the end of the year, but Washington’s senators worried that their constituents might not have enough time to fully review it and com-ment during the holiday season.

The I-5 project would run between Castle Rock, Wash., and Troutdale, Ore. It is the first major transmission development proj-ect in southwest Washington in decades, and the area has become more populated in recent years. Bonneville’s public outreach efforts include “listening sessions” — the next one is scheduled for Dec. 8 in Battle Ground, Wash. — and an interactive Google map where land-owners can view the proposed sites and corridors in detail.


http://www.snl.com/interactivex/snapshot.aspx?id=4058810Bonneville Power Administration





















Page 12

impacts on the environment, geologic resources, wetlands, vegeta-tion and paleontological resources — or “adverse impacts on many resources.”

New Jersey Board of Public Utilities President Lee Solomon said the announcement is part of a longer process to determine the best course for the line as it crosses national park land in Pennsylvania and New Jersey. Because the line would pass through the Delaware Water Gap National Recreation Area, the line requires Park Service approval.

“As of yet there has been no final decision from the Park Service. We will await their final determination,” Solomon said in an inter-view Nov. 23. “If the determination doesn’t allow the Susquehanna-Roseland line to be built, it will present significant reliability chal-lenges and … increases the need for new in-state generation. We’ll wait and see.”

The proposed 130-mile, 500-kV line would link the Susquehanna station in Pennsylvania to the Roseland station in New Jersey at an estimated cost of $1 billion. New Jersey and Pennsylvania regulators have approved permits for the line.

Environmental groups interpreted the Park Service’s draft EIS as a sign of success in opposing the transmission line. In a news release from the New Jersey Sierra Club, Director Jeff Tittel called the deci-sion “a big victory for the environment and protection of public lands.” The Sierra Club urged its supporters to attend public hearings on the line scheduled for January 2012 to continue their opposition to the line.

Not all parties saw the Park Service decision in the same light. Officials with PPL Electric Utilities Corp. and Public Service Electric and Gas Co., the utilities developing the line, said they were not sur-prised by this decision.

“That is what you would expect them to find in this first prelimi-nary stage,” said Paul Wirth, a spokesman for PPL Electric Utilities, a PPL Corp. subsidiary. Wirth explained that the Park Service has two decisions to make, the environmentally preferred alternative fol-lowed by the preferred alternative. The first, the environmentally preferred alternative, only considers the environmental impact of the proposed line. Looking through that narrow spectrum, Wirth said he expected the National Park Service to make the decision.

“We expected them to pick no action. Any action will have more impact than no action,” he said. “That designation will have no bear-ing on what their final decision on the power line is. The final deci-sion won’t be made until next October.”

PSE&G spokeswoman Karen Johnson expressed a similar opinion. “It’s not surprising that ‘no action’ is the ‘environmentally preferred alterna-tive.’ Power line projects, while necessary for society, can have an impact,” Johnson said in an email. “Our proposed project will have impacts on some areas that cannot be avoided. It’s important to note that the NPS has not identified its ‘preferred alternative.’ That choice will not be made until the final environmental impact statement is released in fall 2012.”

PSE&G is a subsidiary of Public Service Enterprise Group Inc.

PJM Interconnection LLC includes the Susquehanna-Roseland line in its plans for regional reliability. PJM spokesman Ray Dotter said

information on market resources that could provide alternatives to regulated transmission solutions.

The second study, the “New Hampshire/Vermont Transmission System Solutions Study,” is being drafted. The study analyzes how potential solutions to the various system needs in the two states would all work together. Preliminary preferred solutions have been developed for most areas of the two states, including upgrading 115-kilovolt transmission lines in both states; some new 115-kV lines in Vermont and New Hampshire; a new 345-kV line in Vermont; and upgrades to equipment at several substations. The ISO and trans-mission owners are continuing their study to determine the cost-effective transmission solutions that will address the reliability needs in all areas of the two-state region.

A third study, a pilot study of market resource alternatives that runs parallel with the “New Hampshire/Vermont Transmission System Solutions Study,” aims to explore market resources, such as merchant transmission, generation and demand resources, that could solve reliability needs in place of transmission upgrades.

The pilot study analyzed nine subareas in Vermont and New Hampshire and concluded that at least 1,800 MW of demand resources or, alternatively, 1,900 MW of supply-side resources would be needed in the two states to address the reliability issues. The study also indicated that some transmission upgrades likely would be needed for these potential market solutions to qualify for partici-pation in the forward capacity market. Finally, the study illustrated that some reliability needs may be more conducive to resolution by market resource alternatives, while others may be addressed more appropriately by transmission solutions.

ISO New England plans to study other areas of the power system for market resource alternative solutions. The question of how to integrate market resources into regional power system planning is also one issue under consideration in the strategic planning initiative launched by ISO New England earlier this year.

The grid operator said the retirement of the Vermont Yankee plant could aggravate the reliability concerns.

“ISO New England’s needs assessment shows that possible reli-ability criteria violations without Vermont Yankee in service in 2020

ISO-NE could see thermal overloads continued

the system operator believes the line is needed to prevent reliability issues. “Despite a prolonged downturn economy, we’re still seeing the need for this line,” Dotter said.


http://www.snl.com/interactivex/snapshot.aspx?id=4062332PJM Interconnection LLC http://www.snl.com/interactivex/snapshot.aspx?id=4057058PPL Corp. PPLhttp://www.snl.com/interactivex/snapshot.aspx?id=4057021PPL Electric Utilities Corp. http://www.snl.com/interactivex/snapshot.aspx?id=4057095Public Service Electric and Gas Co. http://www.snl.com/interactivex/snapshot.aspx?id=4050911Public Service Enterprise Group Inc. PEG

http://www.snl.com/interactivex/doc.aspx?CDID=A-13741729-133532Industry Document: Appalachian National Scenic Trail Delaware Water Gap National Recreation Area Middle Delaware National Scenic and Recreational River


In draft EIS, NPS says ‘no-action’ continued










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©2011, SNL Financial LC. All Rights Reserved. Confidential Subject Matter. WARNING! SNL Electric Transmission Week contains copyrighted subject matter and confidential information owned solely by SNL Financial LC (“SNL”). Reproduction, distribution or use of this newsletter in violation of this license constitutes copyright infringement in viola-tion of federal and state law. SNL hereby provides consent to use the “email this story” feature to redistribute articles within the subscriber’s company. Although the information in this report has been obtained from sources that SNL believes to be reliable, SNL does not guarantee its accuracy.KeyQuarkFileCreation31638

need to be addressed; the assessment shows similar problems, though less severe, in 2012. The primary difference is a lower level of projected demand in 2012,” the ISO-NE said.

The grid operator continues to work with transmission own-ers to develop plans for operating the region’s power system in 2012, including working to expedite certain transmission system upgrades, in the event that the Vermont Yankee nuclear power plant is not able to operate.


http://www.snl.com/interactivex/snapshot.aspx?id=4007889Entergy Corp. ETRhttp://www.snl.com/interactivex/snapshot.aspx?id=4060718ISO New England Inc.

http://www.snl.com/interactivex/doc.aspx?CDID=A-13725475-110582PR: ISO-NE studies look at system reliability needs in New Hampshire and Vermont


accuracy.KeyQuarkFileCreation





Documents

Monday, November 28, 2011€¦ · from the proposed Susquehanna-Roseland transmission line, the U.S. Department of the Interior’s National Park Service said Nov. 21 in a draft environmental