NO Grid North Partners – transmission f/k/a CapX 2020

Thanks to Xcel’s CEO, Dick Kelly, who opened the door to definitive proof that CapX 2020 is not needed. Use of electricity is plunging, not unlike the financial markets, and if this admitted 4-5% decrease this fall is an indication of forecasts, EEEEEEE-HA, no way is this needed in any of the Certificate of Need criteria. Sure, they’d still want it, but they don’t need it, and it’s NEED they’ve got to prove, remember?

That said, I fired off this Motion today:

Motion for Limited Discovery, and Motion to Reopen or Certify to the Commission

This divebombing use trend has got to get into the record/ Their forecasting was done in 2005, based on 2004 and earlier, and Earth to MARS, a few things have changed.

Who cares? Why is this important? DUH! Xcel’s Kelly says “full steam ahead, build build build” but others aren’t so fool-hardy:

Some feel that the drop heralds a broader change for the industry. Mr. Rogers of Duke Energy says that even in places “where prices were flat to declining,” his company still saw lower consumption. “Something fundamental is going on,” he says.

Michael Morris, the chief executive of AEP, one of the country’s largest utilities, says he thinks the industry should to be wary about breaking ground on expensive new projects. “The message is: be cautious about what you build because you may not have the demand” to justify the expense, he says.

If there’s a 3% drop, rather than a 1-2% increase, that’s a 4-5% difference that kicked them upside the head. And that’s what they’ve admitted to, in the residential sector. Other utilities have admitted to even greater decreses, 3.3%. 7.2% and even 9%! We may not need another power plant for decades, and we sure don’t need no skinkin’ transmission.

So let’s get this in the record. Xcel’s customers decrease use.

SNORT! We’ve just eliminated the need for Capx 2020. We’ve just demonstrated the power of conservation. Conservation is doable, now, in a serious way. Conservation is CHEAP. Conservation is the most cost-effective way to generate, because “if we don’t use it, we don’t have to generate it.” We’ve heard it a million times, and maybe people are finally starting to understand. Like the serious reduction in use of gasoline, we’ve got to keep on this, keep reducing use, as Program wisdom urges, “when you think it’s time to lighten up, BEAR DOWN!”

Before the CEC forum, and afterward in emails, there were questions as to why I’d say that utilities are overestimating use of electricity, and demand for electricity. Where would I get that idea? Well, it’s what they do!

Let’s start back in the 70s, when there was an intense frenzy of utility infrastructure construction, power plants, transmission, based on claimed demand, and voila, they way overbuilt, some plants even stopped mid construction with ratepayers holding bill, and we haven’t needed much more than peaking plants since. THAT’S overestimating. Check out Alfred kahn’s “The Economics of Regulation” for details, also Charles Komanoff’s classic “Power Plant Cost Escalation” for more.

The utilities are also known for exaggeration when they want something, like nuclear waste dry cask storage or uprate of plant, to panic us to believe that we’re going to freeze in the dark in an incubator without a job when in fact, it’s not all that needed — this is nothing new — when Xcel was whining and crying in 2003 until they got their Prairie Island bill through legislature, the NERC report issued covering that period reflects extreme overestimation of use in the MAPP/MRO region:

2005 NERC Long-Term Reliability Assessment

Take a look at p. 57, where the 2003 forecasts for 2004 are way way off:

Energy

The MRO tracks annual electricity use by both region and subregion:

• Annual electricity usage for the entire MRO region in 2004 (195,528 GWh) was 0.6% above 2003 consumption (194,286 GWh) and 3.0% below the 2004 forecast (201,605 GWh).

• Annual electricity usage for MRO-U.S. in 2004 (154,053 GWh) was 1.1% above 2003 consumption (152,310 GWh) and 3.7% below the 2004 forecast (159,932 GWh).

• Annual electricity usage for MRO-Canada in 2004 (41,475 GWh) was 2.7% above 2003 consumption (40,369 GWh) and 0.5% below the 2004 forecast (41,673 GWh).

Now we’ve got an even more blatant example, with Xcel admitting an extreme decrease in use. Remember how the utilities whined and cried and so many enviro yahoos who should have known better felt so smug and accomplished to pass legislation with a 1.5% conservation goal? Well, utilities admit we’re at 3% without even trying:

Dick Kelly, chief executive of Xcel Energy Inc., Minneapolis, says his company, which has utilities in Colorado and Minnesota, saw home-energy use drop 3% in the period from August through September, “the first time in 40 years I’ve seen a decline in sales” to homes. He doesn’t think foreclosures are responsible for the trend.

And note they’re WORRIED about it, not heralding the impact of conservation:

An unexpected drop in U.S. electricity consumption has utility companies worried that the trend isn’t a byproduct of the economic downturn, and could reflect a permanent shift in consumption that will require sweeping change in their industry.

Here’s the article in toto:

Surprise Drop in Power Use Delivers Jolt to Utilities

An unexpected drop in U.S. electricity consumption has utility companies worried that the trend isn’t a byproduct of the economic downturn, and could reflect a permanent shift in consumption that will require sweeping change in their industry.

Numbers are trickling in from several large utilities that show shrinking power use by households and businesses in pockets across the country. Utilities have long counted on sales growth of 1% to 2% annually in the U.S., and they created complex operating and expansion plans to meet the needs of a growing population.

“We’re in a period where growth is going to be challenged,” says Jim Rogers, chief executive of Duke Energy Corp. in Charlotte, N.C.

The data are early and incomplete, but if the trend persists, it could ripple through companies’ earnings and compel major changes in the way utilities run their businesses. Utilities are expected to invest $1.5 trillion to $2 trillion by 2030 to modernize their electric systems and meet future needs, according to an industry-funded study by the Brattle Group. However, if electricity demand is flat or even declining, utilities must either make significant adjustments to their investment plans or run the risk of building too much capacity. That could end up burdening customers and shareholders with needless expenses.

To be sure, electricity use fluctuates with the economy and population trends. But what has executives stumped is that recent shifts appear larger than others seen previously, and they can’t easily be explained by weather fluctuations. They have also penetrated the most stable group of consumers — households.

Dick Kelly, chief executive of Xcel Energy Inc., Minneapolis, says his company, which has utilities in Colorado and Minnesota, saw home-energy use drop 3% in the period from August through September, “the first time in 40 years I’ve seen a decline in sales” to homes. He doesn’t think foreclosures are responsible for the trend.

Duke Energy Corp.’s third-quarter electricity sales were down 5.9% in the Midwest from the year earlier, including a 9% drop among residential customers. At its utilities operating in the Carolinas, sales were down 4.3% for the three-month period ending Sept. 30 from a year earlier.

American Electric Power Co., which owns utilities operating in 11 states, saw total electricity consumption drop 3.3% in the same period from the prior year. Among residential customers, the drop was 7.2%. However, milder weather played a role.

Utility executives question whether the recent declines are primarily a function of the broader economic downturn. If that’s the case, says Xcel’s Mr. Kelly, then utilities should continue to build power plants, “because when we come out of the recession, demand could pick up sharply” as consumers begin to splurge again on items like big-screen televisions and other gadgets.

Some feel that the drop heralds a broader change for the industry. Mr. Rogers of Duke Energy says that even in places “where prices were flat to declining,” his company still saw lower consumption. “Something fundamental is going on,” he says.

Michael Morris, the chief executive of AEP, one of the country’s largest utilities, says he thinks the industry should to be wary about breaking ground on expensive new projects. “The message is: be cautious about what you build because you may not have the demand” to justify the expense, he says.

Utilities are taking steps to get a better understanding of the cause. Some are asking customers who reduced usage to explain what is influencing them. Xcel and other utilities, for example, have been running environmentally focused campaigns to urge consumers to use less energy recently, a message that might be taking hold.

Power companies are also questioning the reliability of the weather-adjustment models they use to harmonize fluctuating sales from quarter to quarter. “It’s more art than science,” says Bill Johnson, Chief Executive of Progress Energy Inc., Raleigh, N.C.

If the sector is entering a period of lower demand — which could accelerate further if the automotive sector collapses — many utilities will have to change the way they cover their costs.

Utilities are taking a hard look at the way they set rates and generate profits. Many companies are embracing a new rate design based on “decoupling,” in which they set prices aimed at covering the basic costs of delivery, with sales above that level being gravy. Regulators have resisted the change in some places, because it typically means that consumers using little energy pay somewhat higher rates.

Get used to it Xcel. We’ve just eliminated need for CapX!

We had a good time last night at the Clean Energy Coalition (CEC) forum/debate about CapX 2020 down in LaCrosse. It was moi for the good guys, Tim Carlsgaard for CapX and Grant Stevenson for Xcel (both FOR CapX). Two TV stations, one or more newspapers, so they’re paying attention.

Dogs & Ponies:

No CapX 2020 – CEC Nov 20 2008

Xcel – CEC Nov 20 2008 (requested)

In the press:

Meeting to discuss CapX 2020

There’s a vidieo at the bottom of that WXOW but I can’t figure out how to attach it. Ahem… no more Haagen Dasz!

Some questions have come up since on issues raised there.

Purpose of MISO Midwest Market — where ever would I get the idea that the purpose of it is to displace natural gas with coal generation?

ICF MISO Benefits Analysis Study

Well, look at pps. 14 and 83:

RTO operational benefits are largely associated with the improved ability to displace gas generation with coal generation, more efficient use of coal generation, and better use of import potential. These benefits will likely grow over time as:

• Reliance on natural gas generation within the Midwest ISO footprint grows as a result of the ongoing load growth and a general lack of non gas-fired development over the last 20 years. This may increase the scope for potential savings from centralized dispatch in future years.

• Tightening environmental controls and the resulting greater diversity in coal plant fleet variable operating costs will make optimization of coal plant utilization more important in future years.

• Tightening supply margins throughout the Eastern Interconnect over the next three to five years increase the importance of optimizing interchange with neighbors such as PJM, SPP, and others.

• Transmission upgrades which could increase the geographic scope of optimization within the Midwest ISO footprint.

As to whether there’s coal waiting to be built, or as Carlsgaard put it, “There aren’t exactly people lining up waiting to build coal plants,” I suggest a look at the MISO queue, or easier, look at this NoCapX Information Request to MISO, entered as an exhibit in the MN PUC CapX proceeding:

NoCapX IR to MISO 4-8 + attachments

NoCapX 2020 Info Request to MISO Answers 3-8

5. Slide 7 refers to 3,741MW of coal/gas generation in MISO queue.

a. Of that 3,741MW, how much is coal?

Response:
3,441 MW.

b. Identify MW of coal in MISO queue, state by state for MN, SD, ND, IA and WI,
as of the date of your response to this question?

Response:

As of May 5, 2008, the cumulative total, by state, of the filed queue coal projects
that are proposed are:

MN: 726
SD: 600
ND: 1255.8
IA: 1378
WI: 280

That should help explain why i think there’s coal in them their wires… or at least should be anticipated, because it’s there.

There was another question about Tim Carlsgaard’s refernce to Xcel’s repowering of coal plants to natural gas. That’s MERP, Metro Emissions Reduction Project. I can’t get the settlement or the PUC order downloaded right now. But for more info, go to the PUC’s docket search CLICK HERE and then search for Docket 02-633.

So that’s all for now. If Tim sends his presentation, I’ll post it.

As I’ve been saying forever, there’s a lot of generation planned, and if even a small portion of this generation comes on line, there’s no need for new transmission that they want:

CLICK HERE: PJM’S RTEP (Regional Transmission Expansion Plan)

And look at what’s in the PJM Queue:

PJM GENERATION QUEUE

Why am I thinking about this? Because it seems the industry has discovered the obvious. Much of the transmission proposed is not needed. This acknowledges that much of the transmission proposed in PJM’s RTEP is not needed. Well, DUH! From the inbox today, second hand:

From: service [at] energycentral.com
Subject: Offshore Wind Riding a Wave
Date: Mon, 17 Nov 2008 06:29:00 -0700

Bill Opalka Editor-in-Chief Energy Central Topic Newsletters

While T. Boone Pickens has garnered much attention in recent months
with his well-publicized plan to create a massive infrastructure
for wind energy production in America’s heartland, offshore wind
energy is getting more attention in the heavily populated Northeast.

For its part, the Pickens Plan would require billions in transmission
lines needed to bring electricity from the wind-rich regions of the
central United States to population centers nearer to the coasts.
As for offshore wind — while by no means cheap — it would eliminate
the need to build transmission lines over hundreds,
if not thousands of miles inland.

According to the Department of Energy, the net incremental cost of
a project like the Pickens Plan would be $43 billion, enough to bring
wind energy to supply 20 percent of the nation’s electricity by 2030.

The coastal Northeast that runs from Massachusetts to North Carolina
could contain up to 330,000 megawatts of average electrical capacity,
according to a study from the University of Delaware.
This is a third of the Department of Energy’s estimate of the total
American offshore resource of 900,000 megawatts. There are about a
dozen projects overall proposed for this region.
The potential for projects exists nationwide.

With rapid progress made in several states, 2008 might be later
looked upon as the time when several projects took massive leaps
forward, after a slow and painful process slowed or even stymied
previous offshore wind projects. It is true that regulations for
permitting and siting projects are still being developed by the
Mineral Management Service. Cape Wind, at seven years old the
longest-running proposal and seen as the template for such
regulations, made some incremental progress. But several other
projects took important steps when states chose developers or
long-term power purchase agreements were negotiated between
wind developers and incumbent utilities.

After price shocks hit the state following electricity deregulation,
the Delaware General Assembly passed a law calling for the state to
generate more of its electricity. The Public Service Commission
solicited proposals from all electricity resources. The Bluewater
Wind Park proposal described a 200-turbine, 600-megawatt,
$1.5 billion offshore wind farm. In May 2007 the Public Service
Commission unanimously selected the Bluewater and ordered Delmarva
Power to negotiate a contract. Delmarva argued that offshore wind
would raise the average electric bill by $20 or more a month.
But by last summer the companies signed a power purchase agreement
with Bluewater Wind to build a scaled-down, 200-megawatt wind farm
off the coast.

Off the coast of Rhode Island, meanwhile, Deepwater Wind has
proposed a $1.5 billion project that would erect more than 100
wind turbines. The state picked the developer from seven bidders
following requests for proposals that were sought last spring.
Rhode Island expects the wind farm to provide about 15 percent
of the state’s electricity, generating about 1.3 million
megawatt-hours a year. The location has not been determined and
Deepwater has committed to building manufacturing facilities for
the project in Rhode Island. A formal development agreement is
expected to be completed by year’s end.

And Regulators in New Jersey in September awarded rights to build
a huge offshore wind farm in the southern part of the state.
The selection is part of the state’s Energy Master Plan, which
mandates 20 percent of the state’s energy to come from renewable
sources by 2020. The proposal by Garden State Offshore Energy
includes installing 96 turbines to produce as much as 346 megawatts.
The project, which would cost more than $1 billion, is between
16 and 20 miles off the coast of New Jersey. It would not start
producing electricity until 2013. Permitting from federal and
state agencies is the next step for Garden State Offshore Energy.

As for Massachusetts, Cape Wind Associates first proposed a wind
farm for Nantucket Sound seven years ago. But it has been mired
in controversy ever since. The 130 turbines are expected to
generate an average of 170 megawatts of electricity.
State regulatory agencies have weighed in, although the pathway
to successful completion is anything but assured. A final federal
assessment of the project’s environmental impact is expected
by the end of the year. There are also a number of lawsuits
surrounding the project that have yet to be decided.

Finally, the Long Island Power Authority is preparing to explore
wind power again, just a year after its previous attempt was
dropped due to high costs. This proposal would be lower in cost
and less visible, two objections the previous foray couldn’t
survive. LIPA in September said it would join with utility Con
Edison to study the prospect of a 300-megawatt wind farm 10 miles
off the coast of Queens. LIPA and Con Edison would split the
costs and divide energy from the project.

Building power-related facilities has always been contentious
and expensive. Off-shore wind farms are no different. But they
have the potential supply enormous of power and to avoid endless
miles of transmission lines on land. Several states think that a
worthy goal.

Are the utilities paying attention? Are the Public Service Commissioners across the county weighing transmission applications paying attention?

… and has been for a while — here it is. The direct uploading isn’t working so here’re the links:

Applicant’s Initial Brief

Applicants Proposed Findings of Fact

If WordPress starts working for uploads these will be replaced with the uploaded files.