Tory price freeze costs as much as $3.4m an hour in February

Posted on March 8, 2003 by energyprbe

Fred Vallance-Jones
Hamilton Spectator
March 8, 2003

The Eves government’s decision to freeze electricity prices for consumers and small businesses has now cost close to $900 million, and the bill just keeps climbing.

Soaring demand during February’s frigid weather pushed prices in the wholesale power market to highs not seen since late summer. That forced the government to dig deeply into its pocketbook to keep its promise to hold rates at 4.3 cents a kilowatt hour.

The freeze cost the government as much as $3.4 million an hour last month, according to data available from the Independent Electricity Market Operator (IMO). The government covers the difference between the open market price and what consumers pay.

“It’s not pretty,” said Bruce Sharp, an analyst with Aegent Energy Advisors of Toronto. “Prices were just horrendous.”

He estimates the subsidy for February at about $240 million. In some ways, the price freeze is turning into a bit of a financial nightmare for the government, which hastily introduced it last November in the face of voter anger over sky-high bills.

Prices soared after the government created a free market in electricity just as the province was hit with its hottest summer on record.

As part of the consumer bailout, announced by Premier Ernie Eves in an elaborate news conference in a suburban kitchen, the government froze the price starting Dec. 1. It also promised to give back every cent consumers and small businesses paid over 4.3 cents since the market opened May 1.

Rebates have cost $395 million so far, and the numbers aren’t all in. Add that to the approximately $485 million in subsidies since December, and the bill is at $880 million and climbing.

Part of that will be covered by money set aside to cover rebates by Ontario Power Generation, but not all of it.

The shortfall was estimated by the IMO to be $90 million even before February’s financial bloodbath and not including rebate amounts yet to be reported by local hydro utilities. They could be tens of millions more.

One question now is whether the financial losses will result in any electoral damage to the Conservatives in the election widely expected this spring. Some doubt it.

The government is maintaining its position that by the time the price-freeze-plan ends in 2006, the rebate and freeze will have a net cost to taxpayers of zero.

“When the premier announced the plan on Nov. 11, it was a plan not for two months, or six months or 12 months, it was a plan for the long term,” said Dan Miles, press secretary to Energy Minister John Baird.

The government is counting on the much delayed return to service of mothballed nuclear reactors, and cooler summers, to bring prices down. It is also offering incentives for the construction of new generating plants.

But critics say breaking even is a dream.

Tom Adams of the lobby and watchdog group Energy Probe, says it’s mathematically possible the government is right, “but the track record so far and the outlook going forward is for drastic taxpayer impacts.”

That said, Adams believes the government’s freeze was successful in ending the voter revolt that threatened to unseat the Tories in the coming election.

“My understanding is that immediately after the (Nov. 11) announcement the Tory polling numbers, which had been just tanking, went up.”

Sharp agrees that the freeze halted the short-term pain for voters, and “from the public’s perspective, most of them are probably just happy with just getting the protection they have.”

That’s certainly true for Edward Partito. The Stoney Creek resident, who saw bills approaching $1,000 last summer, says he stopped paying much attention to hydro issues once the freeze was imposed. A Tory voter in 1999, he says Eves’ decision to freeze rates and offer rebates was enough to return him to the Conservative fold for the coming vote.

But the NDP opposition believes there’s still a great deal of hydro anger to be mined.

It is making a return to publicly controlled electricity a major part of its policy platform.

“The cap and the rebate was a short-term solution by this government to get them through the election,” said Nickel Belt MPP Shelley Martel.

The government, in the meantime, will shortly announce what rebates will be available for large volume and industrial users who make up about 53 per cent of electricity customers. Sharp expects the government will decide those users should get the original rebates established when the market was opened, which are less generous than those since given to consumers and small businesses.

Eves promised in November large users could have the 4.3 cent frozen price if they wanted it, but the government later backed off that and began a consultation process with industry that will culminate in the coming announcement.

 

Posted in Reforming Ontario's Local Electrical Distribution Sector | Leave a comment

Ontarians warned to cut back on hydro use

Posted on March 4, 2003 by energyprbe

Robert Benzie
National Post, with files from CanWest News Service
March 4, 2003

The province of Ontario plunged perilously close to a power shortage yesterday after record cold temperatures collided with artificially cheap electricity, forcing the agency overseeing the hydro industry to urge immediate conservation.

As the mercury dropped to -35C in Southern Ontario, the Independent Electricity Market Operator (IMO), which regulates wholesale electricity, was forced to issue a rare “power warning” to prevent service interruptions, such as brownouts.

“It’s record-setting cold and record-setting demand. Because of the cold weather and the high demand for electricity and some of the limitations we’re seeing on our system today, there’s a need for people to cut back if they can,” said IMO spokesman Terry Young.

Mr. Young said industrial and large commercial power users, who pay a market rate for electricity, voluntarily made adjustments when prices rose as high as 39.29¢ per kilowatt hour.

“Some of the big customers . . . have actually shifted their load because of this, shifted their production because they’re paying higher prices, so obviously they want to reduce their costs.”

But homeowners and other retail consumers, who pay 4.3¢ a kilowatt hour for electricity since the Tory government froze prices last November, have no financial incentive to conserve electricity.

Ernie Eves defended his controversial decision to cap retail prices, but admitted the power-shortage threat underscores a need for new generation sources.

“In the long term, there has to be incentives for more generation of power in . . . Ontario. We are moving as quickly as we can move. You can’t build a new facility overnight in terms of generation of power,” the Premier said in Windsor.

Hydro One spokeswoman Anne Creighton confirmed late last night that there were no rotating power cuts, as “the power never stopped flowing.”

Howard Hampton, the NDP leader, blamed Conservative mismanagement for the crisis.

“[The IMO] is essentially saying that they may schedule rolling blackouts on one of the coldest days of the year. This shows again the failure of this government’s strategy of hydro privatization and deregulation,” Mr. Hampton said.

“The reality is the price of private hydro is nine times what the government says it is. It’s nine times 4.3¢ a kilowatt hour.”

Michael Bryant, the Liberal energy critic, said “this is yet another embarrassment for this government,” because no other Canadian province is coping with brownout and blackout warnings.

News of Ontario’s electricity woes overshadowed release of a $100,000 government report into clearing up confusion over consumers’ hydro bills.

Sal Badali, of Deloitte Consulting, concluded a streamlined, standardized bill should be developed consisting of just four standard line items: basic service charge; delivery charge; electricity charge; and the charge for retiring the debt of the old Ontario Hydro. Currently, some local utilities’ bills have up to 14 charges.

John Baird, the Minister of Energy, announced a pilot project in Hamilton is to be launched soon, with simpler bills being available province-wide perhaps next year.

Tom Adams, of Energy Probe, an industry watchdog, hailed the possibility of a consumer-friendly bill, but warned the sector has far greater problems looming.

“The customers may be reading their improved electricity bills by candlelight,” said Mr. Adams. “The whole system is financially and operationally unstable. To get on the road to stability, the first thing we’ve got to do is get off the rate freeze.”

 

Posted in Reforming Ontario's Local Electrical Distribution Sector | Leave a comment

Deep freeze, hydro freeze costs $640M

Posted on February 15, 2003 by energyprbe

Robert Benzie and Paul Vieira
National Post
February 15, 2003

The Ontario government’s decision to freeze hydro rates at artificially low levels has cost the province about $640-million since May 1, according to figures released yesterday by the Independent Electricity Market Operator (IMO), the provincial agency that monitors prices.

The decision to freeze hydro rates has cost Ontario $640 million since May, 2002, a report shows. Photo credit: Kevin Frayer, The Canadian Press.

Last month alone, the move to freeze rates at 4.3¢ per kilowatt hour for consumers and small businesses cost $135-million, up from $110-million in December. That cost – the difference between the price consumers pay for power and the market rate – will be swallowed by the public treasury.

There were 14.5 millio megawatt hours of electricity consumed in Ontario in January – almost 500,000 megawatt hours more than the previous mark set in July.

“It was an all-time record,” said Terry Young, director of communications for the IMO. “It’s largely affected by the weather. You had a cold January and a hot July. We’ve seen new peaks for electricity set in the summer and the winter and these are largely attributed to the weather, so you’re seeing a lot of the impacts from that.”

Mr. Young said it is difficult to say whether the high demand was in any way related to the government’s subsidized price, which some environmentalists and economists have argued discourages conservation.

“I don’t know whether you can argue that or not. It is a fixed price they’re paying, but I would say that at the moment a bigger factor is the weather because it’s been so cold.”

Last Nov. 11, Ernie Eves, the Ontario Premier, announced hydro rates would be frozen at the 1995 level of 4.3¢ per KwH for four years, with retroactive rebates sent to homeowners stung by soaring bills after the retail market opened to competition on May 1, 2002.

While consumer rates are capped, generators are paid the market price for the wholesale power sold to manufacturers and other large corporate users.

Since May 1, that price has averaged 5.68¢ per KwH. Because local utilities have to purchase power on the open market, the government must pay the 1.38¢ per KwH difference.

Speaking to reporters in Bolton, Ont., Mr. Eves insisted he was not worried the gap between the fixed and actual costs was rapidly escalating, noting the contingency fund overseen by the Ontario Electricity Financial Corp. is also increasing. That fund now contains about $1.1-billion.

“I never said it would be done in a nine-month period of time. We said that we would look at this as a four-year project and we are confident that over those four years it will balance out,” the Premier said, blaming the weather for the spikes.

“Suffice it to say we could have been luckier. I mean, there won’t be the hottest summer on record . . . for last 55 years every year in a row. Over time, these things average themselves out.”

But Tom Adams, executive director of Energy Probe, an industry watchdog, said the numbers released by the IMO prove the government’s capped electricity price is not financially sustainable.

“It would never be revenue neutral. That was just trash talking from a bunch of loose-lipped politicians,” he said. “This is proof positive that the rate freeze was financially irresponsible.”

The IMO figures came out on the same day that Hydro One Inc., the Crown transmitter, reported profit for 2002 was $344-million, down by $30-million because of lower distribution rates. The Crown corporation said revenue from the distribution part of the business will be lower until at least 2006, when the 4.3¢ per KwH cap is scheduled to be scrapped.

The more money Hydro One makes, the more it pays to the province to help pay off the nearly $40-billion in debt accumulated by the old Ontario Hydro monopoly. About $21-billion of that debt is “stranded,” with taxpayers on the hook for its repayment.

 

Posted in Reforming Ontario's Local Electrical Distribution Sector | Leave a comment

No boom yet

Posted on January 26, 2003 by energyprbe

Wesley Loy
Anchorage Daily News
January 26, 2003

First of three parts

Halifax, Nova Scotia — The harbor of this Atlantic city has seen warships, slave ships and ships of commerce.

Now, increasingly, titanic drilling rigs are calling here, igniting Canada’s dreams of an economic boom fired by natural gas.

The drilling rig Eirik Raude was in Halifax last summer to be outfitted so it could begin its search for natural gas in the Atlantic Ocean off Nova Scotia’s east coast, where geologists believe much gas remains to be discovered.
(Photo by Marc Lester/Anchorage Daily News)

Other parts of the world are chasing the same dreams, including Alaska.

In many ways, Alaska and Nova Scotia are transcontinental kinsmen. Both fancy themselves as remote resource colonies, struggling for greater economic diversity and self-reliance.

Both see natural gas as the next big thing. And both are hoping for a pipeline megaproject to carry billions of dollars worth of gas to markets hungry for clean-burning fuel.

Nothing is assured. Just look at Alaska’s frustration. Drillers have discovered 35 trillion cubic feet of gas on the North Slope, a fabulous storehouse of energy. Yet for more than two decades, it has remained in the ground. Oil companies say they can’t justify the high cost of a long pipeline to carry it out.

In Nova Scotia, the main challenge is finding enough gas to fill its own big pipe. But already some gas is hissing in from offshore platforms. Geologists think much more remains to be discovered, and immense drill rigs are on site to find it.

If they’re successful, a major U.S. company stands ready to lay a 1,000-mile gas pipeline under the Atlantic Ocean from Nova Scotia south to New York.

It’s just one in a slew of gas megaprojects being contemplated around the globe, projects often involving the same companies that control the fate of Alaska’s gas.

For Nova Scotia, a fog-draped, lobster-shaped lobe dangling down by Maine, a gas boom could transform the province the way oil made over Alaska. Both places have roots in mining, timber, commercial fishing and federal largess.

“There will be prosperity in this province the likes of which has never been observed before,” Nova Scotia Premier John Hamm told a Chamber of Commerce crowd last summer.

Natural gas fever

In a limited way, Nova Scotia is already benefiting from offshore discoveries. Tuft’s Cove power plant in Dartmouth [right] uses bunker oil or natural gas, depending on the price, to produce electricity. (Photo by Marc Lester/Anchorage Daily News)

Alaska and Nova Scotia are hardly the only competitors in the global race to bring often remote natural gas reserves to market.

The fact is, the world has no shortage of gas.

From Arctic Canada’s Mackenzie River delta to the deep-water Gulf of Mexico to the Middle Eastern emirate of Qatar, which practically floats on the stuff, everybody is chasing the billions to be made from selling a cleaner fuel coming more and more into favor to generate electricity, power industry and heat homes.

Getting Alaska gas to market, while momentous to Alaskans, wouldn’t set the energy world on fire, says Dale Nesbitt, a California-based energy economist. In fact, it couldn’t supply even 10 percent of the gas needed daily today in Canada and the United States.

It will take many sources, he says, to satisfy gas demand in the world’s growth markets.

Big projects are busting out all over.

Last year, BP and its partners in Indonesia’s Tangguh natural gas project signed a 25-year deal to supply liquefied natural gas to China.

Also last year, Exxon Mobil announced that a 900-mile subsea pipeline to carry gas from the Russian Far East’s Sakhalin Island to Tokyo is “both technically and commercially feasible.”

Peru plans to export gas from its rain forests to the United States with the help of two Texas-based companies, Hunt Oil Co. and Halliburton Co.

And several companies, including BP and Conoco Phillips, are testing revolutionary technology to cheaply convert gas to stable liquids. Such liquids could flow through existing oil pipelines, potentially freeing up giant, stranded stores of gas around the world, including Alaska gas.

The dominant idea currently for Alaska gas, however, is to pipe it across Alaska and Western Canada to the Midwest states. It would be a multibillion-dollar project requiring 3,500 miles of steel pipe.

For Nova Scotia, the target is the Northeast, a prime growth region. Having that market for a neighbor is the big reason for the province’s excitement about its offshore gas.

Nesbitt says projected growth in natural gas consumption bodes well for both Alaska and Nova Scotia. His own model suggests that in 10 to 15 years, even the distant North Slope gas will reach the market.

One major factor, he says, is depletion of the traditional North American natural gas basins, including the Gulf of Mexico and the Alberta basin in Western Canada. Supply hasn’t risen as fast as expected despite “really high” prices of $5 or more per 1,000 cubic feet. Through much of the late 1990s the price hovered between $2 and $3.

“The drilling success hasn’t been what we’d anticipate at the prices we’re seeing – in fact, alarmingly so,” Nesbitt says.

Tom Adams, an analyst with Energy Probe, a Toronto research firm, suspects all the talk of huge new North American gas projects might be just hot air.

“Energy megaprojects have a way of making the politicians all starry-eyed,” he says. “I’m a little bit of a wet blanket on this. Exploiting new gas reserves is not a gimme.”

The U.S. Department of Energy’s outlook to 2025, however, forecasts a “growing dependence on major new, large-volume natural gas supplies,” including North Slope gas and Canadian imports.

Great expectations

Out in Halifax Harbor last summer sat a colossal drill rig called the Eirik Raude, soon to be drilling for gas in thousands of feet of chill Atlantic water. Haligonians, as they’re called, practically threw a party when the rig arrived for fabrication work at a local dock.

Inside the Split Crow, a popular downtown pub, the party never stops. The band 1749 (named for the year Halifax was founded) plays rollicking Scotch-Irish folk tunes that everybody sings. And when a drunk hollers SOCIABLE! we all hoist pints of locally brewed Keith’s.

The really big gas discoveries have yet to come, but some Royal Bank of Canada workers clustered around a bar table sound a little like Alaskans when they suggest their government hasn’t wrung all it could from the emerging petroleum industry. Things like royalties, jobs and other benefits.

“The perception is we’ve sold ourselves short,” says Peter Denton, 36, a computer systems worker. Yet he concedes that some people have overblown expectations, that “our ship has come in and we’re gonna cash out on it.”

Few will cash out until Nova Scotia achieves its main goal: finding a lot more natural gas.

Geologists say plenty is out there.

A new government estimate says as much as 41 trillion cubic feet of gas and 5 billion barrels of oil could reside under waters 650 to 13,000 feet deep off Nova Scotia. Additional deposits are thought to lie in the shallower waters of the Scotian shelf.

“Offshore Nova Scotia is expected to be a significant gas-producing basin,” Calgary-based Ziff Energy Group declared in August.

A string of apparent dry holes have dampened spirits in recent months, but Scotian officials note that only about 200 wells have been drilled on the shelf over 30 to 40 years, compared with tens of thousands of holes sunk in the Gulf of Mexico.

“It is a vastly unexplored basin,” says Paul Taylor, executive director of policy for the Nova Scotia Department of Energy, an agency created less than a year ago.

This year brings a flurry of new activity, with eight to 10 wells planned. Companies holding exploratory acreage have pledged more than $1 billion in drilling work over the next few years, Taylor says.

Momentum builds

Impetus for the new drilling came from a venture called the Sable Offshore Energy Project, named after a wisp of sand called Sable Island about 185 miles out in the Atlantic.

The island is famous for its wild horses and shipwrecks.

And now natural gas.

The project is a consortium led by Exxon Mobil. Three production platforms near the island gather gas and send it up a subsea pipeline to processing plants on the Scotian mainland. From there it’s piped to consumers as far away as Boston.

Sable began production on the last day of 1999 and is Canada’s first offshore natural gas development. It is expected to produce about 3.5 trillion cubic feet of gas over 25 years.

The Sable project proved Scotian gas could be developed and “led to a real land rush offshore,” Taylor says.

Now companies like Chevron Texaco, EnCana and Marathon are searching for bigger strikes.

“We think there’s substantial opportunity there,” says Alan Boras, spokesman for Calgary-based EnCana, which recently began drilling the McCovey oil prospect in the Beaufort Sea off Alaska.

EnCana this winter is using the Eirik Raude rig to drill an exploratory well near Sable Island, and by 2006 it hopes to begin producing 1 trillion cubic feet of gas from another offshore field called Deep Panuke.

As the oil companies hunt for big gas fields, the largest U.S. gas pipeline company, El Paso Corp., is seeking regulatory approval from both Canadian and U.S. officials for a 1,000-mile subsea pipe to beeline large quantities of gas to New York and New Jersey.

El Paso calls its proposed pipeline the Blue Atlantic Transmission System.

“It’s one of our premier pipeline projects under development, and the largest,” says El Paso spokesman Aaron Woods.

Stubbing toes

Brian Crowley is president of a Halifax think tank called the Atlantic Institute for Market Studies. He’s also owner of the Queen of Cups, a darling tea house in Dartmouth across the harbor from Halifax.

Nova Scotians, like Alaskans, have seen their share of bold visions and grand ideas, Crowley says. The Blue Atlantic pipeline might very well be built. On the other hand, he says, “when people show up and say ‘Have we got a deal for you,’ we say, ‘Oh, yeah.'”

The key challenge for Nova Scotia is creating something lasting from whatever natural gas is found, he says. That means parlaying it perhaps into an oil-field services industry that can compete for work around the globe.

As in Alaska, however, parochial demands threaten to gum up the works, Crowley says. For instance, some Nova Scotians demand that cheap gas be reserved for local homeowners and industries before any is exported, preferably at high prices.

If government makes rules to appease those voices, it could repel an industry taking enormous risks, Crowley says.

When a single offshore well can cost $50 million, “you’d better find a bleedin’ big lot of gas when you drill,” he says.

With about 940,000 people, Nova Scotia (Latin for New Scotland) holds the status of a poor province in a rich country, though it hardly looks needy.

The capital, Halifax, is a clean city of prim Victorian homes, five colleges and universities, and a tourist-packed waterfront. In the picturesque villages down the coast, lobstermen fearful of petroleum pipelines passing through their fishing grounds say they’ve never enjoyed better times.

Like Alaska, the province is heavily dependent on federal subsidies.

Nova Scotia craves homegrown industry and has stubbed its toe a few times trying to find it. Whereas Alaskans have mounted failed attempts at agriculture and seafood processing, Nova Scotians have had misadventures with heavy water plants and supercomputer manufacturing.

For now, natural gas accounts for less than 5 percent of Nova Scotia’s gross domestic product. The question is whether the province can step up as one of the world’s major natural gas players, the way Alaska and many others want to.

Taylor, the Scotian energy official, says: “Depending on the success with the drill bit, there is the potential for transforming our economy.”

 

Posted in Pipelines | Leave a comment

Prefiled Testimony of Energy Probe on DSM & SSM

Posted on January 23, 2003 by energyprbe

Norman Rubin

January 23, 2003

 

RP-2002-0133    Exhibit L, Tab 9

Ontario Energy Board

IN THE MATTER OF section 36 of the Ontario Energy Board Act, 1998, S.O. c.15, Sched. B, as amended;

AND IN THE MATTER OF an Application by Enbridge Gas Distribution Inc. for an Order or Orders approving or fixing rates for the sale, distribution, transmission and storage of gas.

Witness: Norman Rubin

2003 January 23

Q What is the subject of this evidence?

A This evidence addresses Issue 9 from the Board’s Procedural Order #2, “Demand Side Management (DSM) (A7/T1/S1)” and focuses primarily on the following sub-issues:

  • Issue 9.2, “Review of the Shared Savings Mechanism (SSM) incentive scheme”;
  • Issue 9.5, “Review of the DSM Audit Process”; and
  • Issue 9.6, “Recovery of SSM and LRAM for 2000 and 2001(subject of Dec/2002 SSM ADR Settlement Conference)(A8/T3/S1)”.

For convenience of presentation, I would like to deal with these issues in reverse order.

Q What are your qualifications?

A My Curriculum Vitae is attached to this evidence as Appendix A.<!–Don’t forget to do it.–> I have represented Energy Probe at several OEB hearings including EBO 169-III, and on the Demand-Side Management Consultative Groups of both Enbridge and Union since the conclusion of 169-III. In addition, I served as one of three independent members of the Audit Subcommittee that supervised the audit of Enbridge’s 2000 DSM activities, selected by the DSM Consultative Group. I also represented Energy Probe at the ADR settlement conference in the case RP-2001-0032.

Q Didn’t you, acting for Energy Probe, oppose utility-led DSM in EBO 169-III?

A Yes. We still love efficiency, but we still believe that there are better ways to achieve efficiency than with utility-led DSM programs. But since we lost that fight years ago, I’ve remained involved in the DSM process, attempting to ensure that the Board’s prescriptions are carried out as well as possible, in a way that advances the public interest. I have steadfastly resisted reopening the arguments we lost in EBO 169-III. I believe that my selection as a member of the 2000 independent Audit Subcommittee by the members of the DSM Consultative Group represent some public recognition that I’ve been carrying out that responsibility with some success. Indeed, I understand that I recently failed to be reelected to the 2001 Audit Subcommittee only after a tie-breaker vote, at a Consultative Group meeting I was unable to attend, so those views have apparently not materially changed in the past year or two.

Q Beginning with Issue 9.6, “Recovery of SSM and LRAM for 2000 and 2001” – how did this matter come before the Board today?

A In attempting to negotiate an ADR Settlement Agreement to resolve these matters as part of RP-2001-0032, pursuant to Procedural Order #6, settlement was not achieved. A partial Settlement Agreement, not endorsed by Energy Probe or by CME, was submitted to the Board on December 23, ten days following the deadline for settlement proposals specified in that Procedural Order. The Board wrote to the parties on 2003 January 8, indicating that the issues of recovery of SSM and LRAM for 2000 and 2001 will be considered in this case.

Q What are your major recommendations concerning Issue 9.6, “Recovery of SSM and LRAM for 2000 and 2001”?

A The following are my major recommendations on Issue 9.6:

  • The Board should ensure that the findings of the independent 2000 DSM audit are incorporated faithfully into the 2000 SSMVA clearance, and not ignored either in whole or in part. Specifically, it is not appropriate for the Company to suggest (or the Board to agree) that the year-2000 SSM — determined by audit to be a near-zero sum of two components, one positive and one negative — should be settled by including the positive part and excluding the negative part.
  • The year-2000 SSM clearance should result in $69,262 being returned to the ratepayer for 2000.
  • The Board should delay clearing the year-2001 SSM until the independent DSM audit process for that year has concluded. But we urge the Board to clearly endorse audit and SSM principles for 2001 and 2002 that are consistent with the principles of the independent members of the 2000 Audit Subcommittee, and to reject the Company’s principles where they differ. Those recommended principles are outlined below in the detailed discussion of the 2000 Audit results. If the Board establishes clear principles, we expect that the 2001 SSM claim will be easily resolved by ADR settlement according to those principles, following the conclusion of that independent audit process.
  • Finally, although the SSM for 2002 is not formally part of this hearing’s Issue 9.6, we note that that year’s DSM activities are complete, although not yet evaluated or audited. We therefore believe that its SSM clearance should also be guided by our principles, endorsed at this Hearing by the Board and carried forward through the Company’s 2002 evaluation report and tested and (if necessary) corrected by an independent audit.

Q How did you arrive at your recommendation for a negative $69,262 SSM for 2000?

A The recommendation flows from a series of adjustments to the Company’s claim, following the findings of the independent Audit of 2000 DSM activity. Those adjustments — mine, and also those of the other two independent members of the 2000 Audit Subcommittee — are laid out clearly in Kai Millyard’s July 31, 2002 Reconciliation Report, Table 2.

Q Does it bother you – and should it bother the Board – that the SSM is negative?

A In one sense no; in another sense, yes.

Q Please explain.

A On the one hand, the SSM was clearly and consciously designed from the start to be a symmetrical incentive, embodying both reward and punishment, the results to be determined by a mathematical formula that compares actual TRC results to “target” results. If putting the true results into the formula generates a negative answer, then that is the correct answer, and anything other answer is wrong.

On the other hand, it is clear that the Company generated significant positive TRC benefits with its 2000 DSM activities, and it seems churlish to penalize shareholders just because those benefits were slightly below some arbitrary “target”.

Putting these two reactions together, I believe the SSM formula itself is to blame, and should be changed in future — pursuant to the discussion in Issue 9.2 — to eliminate its most unfortunate effects.

Q Let’s come back to Issue 9.2 later. What were the biggest changes to the SSM from the Audit’s findings?

A According to all three independent members of the Audit Subcommittee, the largest single change flowed from the Audit’s revelation that roughly half of the gas savings that the Company claimed from large, one-of-a-kind, hand’s-on projects — so-called “custom” projects — were actually improperly attributed to the Company’s DSM activities, because the savings would have occurred with or without the DSM program.

Q Am I correct that these customers who would have made the savings without the program are called “free riders”?

A That is correct.

Q How much difference did the revelation about free riders make?

A The answer varied somewhat among the independent members of the Subcommittee, because we differed in the way we tempered justice with mercy. For Mr. Rowan (of CME) and myself, the net difference was a deduction of $4,499,694 from this one adjustment alone. For Mr. Neme (of GEC), the net difference was “only” a deduction of $3,588,762.

Q So even Mr. Neme’s smaller adjustment here eliminated over half of the $6,547,660 SSM claim the Company took from the Audit Subcommittee process to the ADR?

A Yes.

Q And why was Chris Neme’s adjustment smaller than yours and Malcolm Rowan’s?

A When the Auditors presented their raw results from statistically sampling the Company’s customers for “custom” DSM projects — a job that’ s normally considered evaluation, rather than auditing, and only fell to the Auditor because it became clear during the audit that the Company had not done it in its Monitoring and Evaluation Report — they were even more brutal than the results in Kai Millyard’s chart. On average, only 42% of the claimed savings survived the screen of free ridership!

After we all saw these raw results, we frankly started thrashing around, along with the chief auditor, trying to find ways in which the sample might have been artificially harsh for the Company, and trying to devise what we all called “generous alternative scenarios” and calculations. The auditor proposed a number of these “generous alternative scenarios” in Section 5 of the Audit Report, beginning at p. 5-16 and culminating in Table 5-18, “Suggested Ranges for Effective Free Rider Assumptions”. Given the discussion in the audit report, and my general intention to follow and implement the Audit Report’s findings, I adopted the middle of that table’s three alternative scenarios, or 49% overall average free ridership for custom programs. So did Malcolm Rowan. Chris Neme decided to give the company even more generosity than the Audit Report did, by treating the custom-projects free riders who dealt with Energy Services Companies (“ESCOs”) differently from the others, on the principle that the Company had less (or no) control over customers lined up by ESCOs. Specifically, I believe he recalculated the results assuming that these “ESCO-custom” projects showed the same rate of free ridership as the Company had budgeted, rather than the rate the Auditor had discovered. I believe it is within the power of the Company to require its ESCO partners to control free ridership — to line up customers for DSM subsidies who are not free riders — just as it can do so with its own staff. But we did not reach agreement on the point, and came up with different calculations as a result.

Q The Company says that the results of the Audit Report should not be used to revise actual free ridership rates for the year that’s under audit, but only used to revise budgets and plans for future years. How do you respond?

A First, I think it is perverse to use the SSM to reward miscalculations, rather than utility-induced gas savings and TRC benefits. Those free-rider savings are not attributable to the Company’s DSM programs, according to the independent auditor, and it is a misuse of ratepayer funds to pretend that they are, and to give the company a financial reward for having found so many of these free riders. Whether the mistake was accidental or on purpose, ratepayers should not be asked to reward it. Indeed, the SSM formula calls upon the company to “reward” the ratepayers for custom projects, because they fell short of their target.

Secondly, freezing these custom free rider rates at budget values significantly undermines the primary value of the audit and the audit process, and is inconsistent with the very purpose of the audit. Here are some quotes from the final revised Terms of Reference of the Audit, as distributed to candidates for the job by an Audit Subcommittee chaired by the Company:

“The ultimate goal of the independent audit is to make a determination of whether the Company’s claimed SSM amount is accurate and appropriate, and to give confidence to all stakeholders that the claim – as amended by the audit process if necessary – will be fair and justified.

. . .

“Possible Audit Activities:

“Review and verify the accuracy of all calculations leading up to the proposed SSM amount, and verify that the calculations are consistent with the OEB-approved prescribed methodology;

“Review Enbridge Consumers Gas’ procedures for tracking program participants and determine whether they lead to accurate counts, particularly for programs that do not provide customer rebates;

“Determine whether Enbridge Consumers Gas’ reported values for participation, costs, energy savings, free ridership rates and other key assumptions are accurate and adequately documented by program records, evaluation studies and other relevant data;

. . .”

I find it frankly impossible to read these terms of reference while trying to hold the Company’s stated view – that the auditor’s findings of inaccurate reported values for free ridership should not be used to amend the SSM claim, so that it is ” accurate and appropriate”. How can such an unamended claim, based on inaccurate values, possibly be “fair and justified”, and how can all stakeholders have confidence that it is??

Q Was it primarily the terms of reference that convinced you that the Audit results would generally change the SSM claim?

A No, also in our initial meetings with Dr. Goldenberg, the principal auditor for Xenergy, we continued to make audit suggestions that were consistent with our understanding – and the Terms of Reference’s understanding of – “the ultimate goal of the independent audit”. For example, we asked Dr. Goldenberg to concentrate on auditing and testing those parts of the DSM program that if changed would be most “sensitive” in affecting the SSM claim. As I recall, we all decided that attribution and related issues of free ridership in custom programs should be one priority.

Q Can you cast any light on the rest of the audit findings that led the independent intervenors to revise the Company’s SSM claim for 2000?

A The two other significant changes both involved Domestic Hot Water heating in residential markets. These involved significant changes to some of the biggest DSM programs — the biggest contributors to TRC and the biggest contributors to the SSM. Again, the specific numbers differed a bit between Chris Neme on the one hand and Malcolm Rowan and me on the other — not because of differences in “generosity” in these cases, but because of different positions on retroactivity in prescriptive programs.

Q What is “retroactivity in prescriptive programs”?

A Prescriptive programs are those programs that aren’t custom — like distributing or subsidizing low-flow showerheads, or getting service employees to lower the thermostats on customers’ hot water tanks, across the board. The measures are standard, and generally mass distributed. And retroactivity here means how we deal with revelations that one of our assumptions needs to be revised. Basically, there was no disagreement among the four of us that most of these factors are essentially out of the Company’s control, and therefore that they should not be penalized or rewarded for these changes. But there are two ways to approach such a change with that principle in mind: you can pretend that the revelation didn’t occur, “freezing” the assumption at budgeted levels. Or you can reflect the best number in the actuals, but pretend that you had the new number when you set the budget and the target, revising it, too. The former approach we called “no/no”, and the latter was the “yes/yes”. At least this year, the Company and Chris Neme generally prefer the “no/no” approach, and Malcolm Rowan and I prefer the “yes/yes”.

Q What do you mean, “at least this year”?

A Apparently both the Company and Chris Neme and his organization (GEC) have supported the “yes/yes” position in the past, but now prefer “no/no” for prescriptive programs.

Q Can you summarize the arguments for each?

A Yes. I believe this is certainly an area where reasonable people can disagree, because there are important competing principles. On the one hand, the “no/no” proponents argue that the purpose of the SSM is to give the Company incentive to do what we all — including the Board — agreed the Company should do, i.e., carry out the agreed DSM plan and achieve more than its targeted value of savings and benefits. If the world changes, or a new study shows that important assumptions were wrong, that should be changed for future years, but the Company should still be rewarded for over-achieving at its assigned task. The “yes/yes” proponents (including Energy Probe) like to remind people that SSM stands for Shared Savings Mechanism, and that it’s important that we “share” real savings and not just somebody’s misperception, or something that would have been a saving if only the world hadn’t changed. (In addition, “yes/yes” proponents often feel that the Company is in the best position to know what the right numbers are, and will have more incentive to do so under “yes/yes”.)

Q How does this differ, exactly, from the discussion we had earlier about the custom projects?

A In the custom projects, because the variables can be controlled by the Company, they must logically be part of the Company’s incentive scheme. Here, on the other hand, the variables are generally out of the Company’s control, so all four of us agreed that the Budget and the Actuals must use the same values for these variables. The disagreement here is only over whether those “same values” should be the new, best estimates or the old, now-obsolete values.

Q Now that we understand why the numbers differ a bit, can you go through these two examples?

A Yes. The larger of the two involves a stupid mistake. During the exercise, it was discovered that the calculation of savings from “DHW tank set point” – getting service people to turn down the thermostats on existing hot water heaters — stupidly assumed that the savings persisted for 15 years, the assumed lifetime of a brand-new hot-water tank! Since the tanks in people’s houses are, on average, half-way through their lifetimes, this mistake overstated the savings by a factor of two (really somewhat less because of discounting). Correcting that mistake — which even Chris Neme thought should be corrected on a “yes/yes” basis, because it was always stupid, and the Company should have fixed it — dropped $990,099 from the Company’s claim, for the independent members of the Subcommittee.

Q But not for the Company?

A No. We’re only discussing difference between the Company’s post-audit “revised” SSM claim and the recommendations of Energy Probe and the other independent members of the Audit Subcommittee. The Company apparently believes it is entitled to 35% of the TRC benefits that the over-budget hot-water tanks will not save in their 8th, 9th, 10th, 11th, 12th, 13th, 14th, and 15th years! The rest of us all disagree. And because the Auditor found that 12.6 years is a far better documented tank life expectancy than 15 years, Malcolm Rowan and I also reduced that 7.5 years to 6.3, on a “yes/yes” basis, so we came up with a slightly bigger reduction than Chris Neme did.

Q And the second one?

A The second one involves the distribution of low-flow showerheads. The Company changed the program — from one that gave low-flow showerheads to customers whose existing showerhead tested high-flow, to one that gave low-flow showerheads to virtually every customer visited. Since all or virtually all the showerheads for sale in Ontario now and for several years are low-flow, the market has begun to become saturated. The Audit Report gave a range of estimates for the saturation rate, with 32.5% as the middle estimate. Malcolm Rowan and I applied this change on a “yes/yes” basis, as if the Company had budgeted to distribute showerheads freely into a 32.5% saturated market. Chris Neme applied the change on a “no/yes” basis (the same as all three of us did for custom programs), on the basis that it was the Company’s change of program design that caused the change. This time Chris’s deduction was bigger than Malcolm’s and mine — at $1,142,805 vs. our $605,368.

Q How do you answer the Company’s clailm that revising the SSM as the result of the audit — e.g., by correcting the share of free riders in custom projects — creates unacceptable business risks?

A There’s no doubt that being audited is a threatening to experience, in principle, and so it should be. I think that’s the purpose of audits, when they’re done properly. If they find mistakes, there should be consequences. I would be happier in a world without risks — at least to me – and I’m sure the Company would be, too. But removing these risks from the Company means imposing risks on ratepayers — and as innocent as the Company may claim to be, the ratepayers are more so, and deserving of protection.

Q Aren’t you tempted to show some mercy to the Company? After all, they did accomplish a lot of DSM, and created very large TRC benefits by doing so.

A Yes, I think there is a case for mercy, and that is why all the independent members of the Audit Committee showed mercy — e.g., in directing the auditor to examine “generous alternative scenarios” for free riders in custom projects and endorsing various moderate compromise scenarios among those generous alternatives that restored millions of dollars to an SSM that otherwise would have run into an enormous penalty. I believe ratepayers have also been generous in allowing the Company to pass through an amount of DSM costs estimated at over $790,000 in 2000, in the costs attributable to savings that either did not happen or would have happened without those expenditures. (See I/9/24, table at “C”).

Also, I believe that hindsight has made it clear that allowing the company to claim a 1999 SSM of ********* based only on the Company’s Monitoring and Evaluation report and an audit by an auditor hired and directed by the Company, was excessively generous to the Company by approximately $3 million (See I/9/24, table giving answer to sub-question D).

Finally, I believe we should show mercy by redesigning the SSM so that it is less volatile and more transparent, for the good of all involved.

Q Do you have anything to add to the discussion of principles of retroactivity concerning Issue 9.6?

A Yes. I believe there are two points that must be added about the principles of retroactivity. First, on prescriptive programs, there is ample room for compromise between “yes/yes” and “no/no”, both of which are defensible and principled views. Indeed, the Audit Subcommittee discussed several possible compromises, including the following: (a) treat the assumption as “no/no” but cap the SSM reward / penalty in order to avoid distributing non-existent benefits; (b) use an SSM mechanism with upper and lower bounds, i.e., an “S” curve; (c) use a set of “rolling averages” for high-leverage variables, especially avoided costs of gas (discussed below), or (d) use a simple arithmetic compromise between the calculations made using the two approaches. (Ref. I/9/26/p.41 f.) While I still generally favour “yes/yes” for prescriptive programs, a well-designed compromise might be preferable to either “pure” case.

The second point is this: a large change in the avoided costs of gas presents an extreme “acid test” of any SSM design that depends on TRC — and of either of the two “pure” positions outlined above. For example, applying the “yes/yes” approach when avoided costs fluctuate widely during the year introduces the real risk of unwarranted “windfall” rewards and penalties through the SSM — especially with the current high-leverage “35% of delta-TRC” design of SSM. On the other hand, applying the “no/no” approach in a year when avoided costs fell sharply and DSM performance was above target runs a real risk of distributing huge “savings” to the Company through SSM, when ratepayers actually did not realize any TRC savings at all!

The problem arises because the avoided costs of gas is a variable that is both absolutely beyond the control of the Company’s DSM activities and hugely “high-leverage” in its impact on the calculation of TRC benefits and therefore of the SSM. Unlike changes in other variables which are usually confined to a single program or even a single measure, the effect of a change to avoided gas costs is across the board, increasing or decreasing the value of every unit of gas saved.

This issue obviously has serious implications for Issue 9.2, “Review of the Shared Savings Mechanism (SSM) incentive scheme”, but it is also crucial for the years 2001 and 2002, already completed and (at least 2001) the subject of Issue 9.6. If the SSM mechanism were to continue unchanged for many years, usig our preferred “yes/yes” approach to prescriptive programs, years of “windfall” increases in avoided costs might well be balanced out by years of painful drops, in which the SSM formula might generate millions of dollars of penalties. Of course, that result might be unacceptable in its volatility, even if the average over many years was acceptable.

But in our situation, where it appears that the SSM mechanism may well be significantly changed after roughly 4 years, the volatility from a sharp rise in avoided costs may not have a chance to average out. Moreover, it is worth noting that changing avoided gas costs did not significantly affect the 2000 TRC or SSM calculation, but did significantly affect the 2001 calculation. As a result, the 2000 Audit Subcommittee was not compelled to resolve the issue, and avoided costs were not a factor that led to discrepancies between the supporters of the “yes/yes” position (CME and EP) and the supporters of the “no/no” position (GEC).

In addition to the principles and the possible compromises outlined above, Energy Probe believes there may well be merit in treating avoided cost as a unique variable, to be “frozen” (“no/no”) while other variables are not (“yes/yes” for prescriptive programs, and “no/yes” for custom). Indeed, we joined a large number of parties in advancing several possible settlements that reflected that compromise during the ADR settlement conference (although we certainly do not endorse the December 23d non-consensus proposal).

Q Can you summarize the principles you urge the Board to endorse, at least for the years 2000-2002?

A Yes.

  • In general, the audit results must be incorporated into the audited year’s SSM and LRAM calculations. Otherwise, the Board will be giving the Company a durable incentive to make errors in its Evaluation Report.
  • For “custom” programs, all input values except avoided gas costs should be changed in the actuals and not in the budget (“no/yes”).
  • For “prescriptive” programs, we believe that all input values except avoided gas costs should be changed in both the actuals and the budget (“yes/yes”), although we are receptive to compromises between “yes/yes” and “no/no”.
  • For avoided costs, we believe that “no/no” is probably the best approach, again, without ruling out a form of compromise like rolling averages or “smoothing”.

Q As long as you’re giving principles of SSM, how would you change them going forward — that is, what are your major recommendations concerning Issue 9.2, “Review of the Shared Savings Mechanism (SSM) incentive scheme”?

  • It is important that the SSM, past and future, give the Company an incentive to create net societal benefits through DSM, and not an incentive to profit from mis-reporting benefits that are either fictional or not reasonably attributable to the Company’s DSM activities. <!–. In the case of the 2000 evaluation and audit, from “custom” projects that are largely within its own control, that are subsequently found to be either fictional or not reasonably attributable to the Company’s DSM activities. –>We believe that an independent audit, whose findings immediately affect the SSM, must be part of such a structure. 
  • We are sympathetic to several of the Company’s stated principles in the design of its proposed SSM, but we nonetheless urge the Board to reject that design.
  • We are especially supportive of the Company’s desire to diminish the importance of the annual target-setting, but we would eliminate it entirely.
  • We are also supportive of the Company’s intention to substitute volumetric savings for part of the new mechanism (Ref. A7/2/2/pp.8-9) — which would be immediately and directly meaningful to the public and the Company’s staff as well — for the relatively obscure and indirect TRC. We also note that basing SSM on saved gas volumes is similar in effect (though not identical) to freezing avoided costs with “no/no” — an approach we have endorsed.
  • Nonetheless, we urge the Board to reject that design and to direct the DSM Consultative Group to devise an SSM that eliminates the annual negotiated target-setting exercise entirely, in favour of a more transparent and “self-regulating” mechanism, along the following lines: the Company should receive as an SSM a fixed share of allTRC benefits generated, and should cover its DSM costs out of that SSM. The percentage should be chosen to reflect an appropriate level of reward for expected performance, and may be reviewed from time to time before the Board.
  • The Consultative Group should attempt to devise rules for the treatment of avoided costs as a special variable, and entertain the notion of incorporating a volumetric component in the formula.

Q What’s so bad about having the SSM calculated as 35% of the difference between the target and the actual TRC?

A I believe that that present “high-leverage” formula has a number of unfortunate effects: it places incredible value on the target-setting exercise, which I believe is an ill-informed and poorly designed exercise; it creates incredible complexity in the evaluation and audit process; and it clearly and openly contemplates large negative SSM settlements (penalties), when it is not clear that the Board, the Company, or many of the intervenors actually have the stomach to see a large negative SSM.

Q Why do you call the target-setting exercise “an ill-informed and poorly designed exercise”?

A In my experience, these sessions involve two sides: one (the Company) claims that the markets are saturated, that last year’s savings were special and cannot be duplicated. The other side (led by the most aggressively pro-DSM environmental groups) heaps praise on the Company for its ingenuity, points out the Company’s history of exceeding its targets, and suggests ways the company could expand its efforts or its scope. In addition to being unseemly and unpleasant events, to my taste, they also bring together two parties with very different levels of access to the facts of the situation — not to mention very different levels of incentive to “win” the competition. I believe that it is worthwhile to “flatten” the incentive curve to a significantly lower percentage of TRC in return for eliminating this exercise, making the exercise much more transparent, and giving the Company an incentive to limit DSM costs where possible, rather than a “cost-plus” incentive to augment them or at least ensure that they are all spent.

Q What is your concern about the lack of transparency of the current mechanism?

A During the discussions of the Audit Subcommittee, we often had the services of Kai Millyard, the designer of an Excel spreadsheet that duplicates the Company’s DSSStrategist software, to calculate TRCs and SSM. Several times, we got into conversations where Kai would kindly point out that the effect of some audit-driven change we were discussing would actually be in the opposite direction than the one we’d all assumed. For example, once or twice when a program became controversial, the Company representative offered to just remove it from the budget and the actuals. That sounded generous on the Company’s part, until Kai pointed out that the program had fallen a bit short of its target, and its withdrawal would actually increase the SSM! Similarly, our discussion about “yes/yes” and “no/no” principles in prescriptive programs was constantly complicated by not knowing which was the “generous” approach and which the “punitive”, because the answers kept changing. I believe that a linear mechanism, that rewards based on every saving, but must bear its own costs, would avoid most or all of these problems.

Q What are your major recommendations concerning Issue 9.5, “Review of the DSM Audit Process”?

A My major recommendations concerning Issue 9.5 are as follows:

  • The Board should ensure that the substantial benefits to ratepayers from the independent 2000 DSM audit exercise are carried forward to future years, by ensuring that future audits are independently supervised and high-value like the 2000 audit, and not Company-controlled and of limited value like the 1999 audit.
  • The Board should insist on a timely resolution of each year’s DSM evaluation and audit activities, not only to avoid unnecessary retroactivity in rates, but so that important lessons learned in the evaluation and audit process may be incorporated into the DSM process of future years as quickly as is reasonably possible.

Q What was so good about the 2000 audit?

A The 2000 DSM audit — the first supervised by an independent Audit Subcommittee — represented a quantum leap in useful findings and in value-added for ratepayers. Indeed, the difficulty of the discussions and negotiations around “retroactivity” or “the retrospective treatment of changed assumptions” is a measure of how many changes — corrected errors, in my view — the 2000 audit made.

Q Wasn’t the 1999 audit good, too?

A No. Most of us in the DSM Consultative Group were pretty disappointed with it at the time. It seemed as if almost everything that was discovered that year was discovered by Kai Millyard’s replication of the calculation, and not by the auditors. But as disappointed as we were with the audit at the time, that disappointment has mushroomed enormously now that the 2000 audit – as well as the independent Subcommittee discussions – has discovered some serious problems with the Company’s Monitoring and Evaluation work. And unfortunately, there are no solid reasons to believe that these problems weren’t there in 1999 as well. (See I/9/24, answer to sub-question F)

Q What do you think we should learn from this comparison?

A The disappointing audit of the Company’s 1999 DSM activities was done by an Auditor selected and hired and supervised by the Company, with only advisory involvement by other parties, primarily through the DSM Consultative Group. In contrast, the audit of the Company’s 2000 DSM activities was done by an Auditor selected and hired and supervised by an independent Audit Subcommittee composed of one representative of the Company and three independent members selected by the Demand-Side Management Consultative Group. Therefore, the Company’s current proposal to reject the audit-governance structure that prevailed for the impressive 2000 audit in favour of those that prevailed for the far less valuable 1999 audit, should be rejected as not in the best interest of ratepayers.

Q But the Company is concerned about the time and money spent on independent audits, and the loss of control by the Company. How do you respond?

A Although the audit subcommittee process was time-consuming, it is incorrect for the Company to suggest that the time was poorly spent — or to ignore the fact that the lion’s share of the delay was because of the Company’s acts, or omissions. For example, the Company introduced significant delays of its own during the process, several of which involved the failure to meet agreed-upon commitments and timelines. Perhaps most notable of these was the series of delays before a version of the Company’s 2000 Monitoring and Evaluation Report was available, on December 27, 2001.

Q Was that the Company’s main contribution to the delay?

A Probably, but another very significant source of delay was that the Monitoring and Evaluation Report, almost 15 months after the end of the fiscal year, still hadn’t actually monitored or evaluated the custom-project customers. Specifically, the Company had not actually contacted or sampled them to determine (a) if they had installed the measures that Company staff had reported, or (b) if they were actually influenced to do so by the Company’s DSM activities. Of course, if the audit’s initial samples had found that the Company’s claims were essentially valid, we could have proceeded more quickly. But they showed the opposite, so we had no choice (in my view) but to increase the scope of the Audit so the auditor could go back to the customers for a statistically significant Evaluation. Of course, all of this is time-consuming, as the timetable and the minutes show (Ref. I/9/26). But it is evidence of the independent audit’s value in filling embarrassing data gaps, not evidence against its value.

Q Wouldn’t the Audit Subcommittee have contributed more value to the process if it could have reached consensus on the issues that affect the SSM claim?

A Yes, of course. But we had a very large job to do, and we had to stop at the end of July (by ADR agreement) whether or not we had finished the job. Nonetheless, the three independent members of the Subcommittee — despite some important philosophical divisions — reached substantial consensus on the vast majority of important issues, and nearly reached agreement on the “bottom line” of the SSM. This substantial consensus – which to us seems consistent with the direction of the discussions during the meetings of the Subcommittee – stands in stark contrast to the Company’s final position, which to us seems extreme, unsupported by the Subcommittee’s discussions, and without merit.

Indeed, given the accommodation and rational discourse among the independent members in the last few meetings of the Subcommittee, it is my opinion that the independent members would likely have reached agreement within two or three additional meetings, except for an ADR-agreed deadline of July 31 for a final report. That agreement would, I believe, have been within the range of the final positions of the three independent members, and extremely remote from the position of the Company.

Q Weren’t the meetings difficult and time-consuming?

A Yes, they were. In addition to the complexity of some of the principles, and the enormous quantity of data involved, and the need to supervise a team of auditors, and the significant range of beliefs represented at the table, we had sharply conflicting personal styles, which occasionally caused difficulties and delays. Personally, I would have glossed over many details and principles and focused much sooner and much more on those decisions and principles I considered most important. My sense is that Chris Neme would have joined me — even though we actually disagreed on many of those decisions and principles — while Malcolm Rowan wanted to make sure that everything was done formally and properly and no steps were skipped. But even if we had the time to reach a consensus, I’m very sure that that consensus would have been among the three independent members of the Subcommittee, not including the Company. And the “bottom-line” SSM would also have been along the lines of our various final positions, as reflected in Kai Millyard’s Reconciliation Report — and nowhere near the Company’s final position.

Q Can you sum up the division between the Company and the independent members of the Subcommittee in a nutshell?

A Sure. In my view, we all agreed that the Company shouldn’t be held responsible for things that aren’t within its control. But I believe we couldn’t get the Company to agree that it should be held responsible for things that are within its control.

Posted in Natural Gas Utility Regulation and Commodity Deregulation | 2 Comments

The New Brunswick Market Design Committee’s First Interim Report

Posted on December 11, 2002 by Other News Sources

Tom Adams

December 11, 2002

Mr. Don Dennison
Chairman
New Brunswick Market Design Committee
c/o Energy Secretariat
New Brunswick Department of Natural
Resources and Energy
P.O. Box 6000
Fredericton, New Brunswick
E3B 5H1

email: info@nbmdc-ccmnb.ca

Dear Mr. Dennison,

Please accept the following comments on the “New Brunswick Market Design Committee – First Interim Report.”

Recommendation 1-1 states that “The MDC will pursue the development of a bilateral contract market for New Brunswick.” The MDC has suggested that physical bilaterals would be realized through “transmission rights between the injection and withdrawal points,” a phrase that suggests a contract path concept of physical transmission right. I urge the committee to reconsider its position on both these foundational market design questions.

As California and the UK are both experiencing now, bilateral markets make it very difficult for non-dispatchable but otherwise efficient generators to realize their full contribution to the system. Individual systems based on fuel cells, package cogeneration, or wind power need liquid, seamless real-time markets to optimize their value. In the absence of these markets, non-dispatchable generation options would all be at an artificial disadvantage relative to integrated, internally diversified portfolios of supply assets.

Adopting a bilateral contract model would limit the future prospects of any electricity market you might establish. The FERC is now in the midst of a process to develop a standard market design. That process is strongly influenced by the highly successful PJM model. One of the promising aspects of Ontario’s electricity market is its explicit effort to harmonize with neighbouring US markets. This effort is institutionalized through a Memorandum of Understanding between the IMO, NYISO, NEISO, and PJM. Unless New Brunswick’s market model is compatible with neighbouring markets, it will be much more costly than necessary to realize trading opportunities with neighbouring markets. Therefore, I recommend working toward the standard market design being advanced by the FERC process.

A bilateral market would limit buy-side competition to only large customers because it would be extremely difficult to administer for anything but a very few customers. A bilateral market cannot be scaled up to eventually accommodate all consumers unless heroic effort is undertaken. The multi-billion-dollar cost to build the UK’s NETA market is a recent example.

Physical transmission rights, which are suggested in the MDC report, can only be fictional because physical tranmission rights are not logically consistent with the operational reality of integrated AC transmission networks. The Ontario Independent Electricity Market Operator has had difficulties dealing with situations where its market rules are inconsistent with operational practices. Ontario’s decision to adopt a one-zone price for electricity by ignoring the effects of transmission congestion is an example. Based on this experience, let me urge that the committee try to ensure the proposed market rules match as closely as possible the operational requirements of your system.

In 1996, Energy Probe published a broader discussion of the relative advantages of a pool-based market over a bilateral or “wheeling” market specifically related to the circumstances in New Brunswick.¹

I would be delighted to assist your committee in any way I can. Best wishes to you and your committee in your challenging task.

Sincerely,
Tom Adams
Executive Director
Energy Probe

¹New Brunswick’s Power Failure: Choosing a Competitive Alternative, 9 October, 1996, by Thomas Adams
Presentation to the New Brunswick Legislative Assembly, Standing Committee on Crown Corporations

Posted in New Brunswick Power | Leave a comment

Oilpatch prepares for life with Kyoto

Posted on December 11, 2002 by energyprbe

Chris Varcoe
Calgary Herald
December 11, 2002

After the most acrimonious battle with federal politicians since the National Energy Program two decades ago, Canada’s oilpatch is now preparing for life with Kyoto.

But that doesn’t mean the industry likes it.

The federal government passed the controversial Kyoto protocol Tuesday by a 195-77 vote in the House of Commons, committing Canada to reduce greenhouse gas emissions over the next decade.

The head of the Canadian Association of Petroleum Producers said the industry’s relationship with Ottawa has cooled, as Kyoto created “frustration and disappointment” in the sector.

“We feel many of the issues that are important to us are going unresolved,” said CAPP president Pierre Alvarez.

“We still don’t know (Kyoto’s) costs . . . and we still can’t calculate the competitiveness implications. While Ottawa may have taken a few baby steps forward, we still have far more questions than answers.”

Executives in downtown Calgary were equally unimpressed.

“I’m not satisfied. I don’t think we ever had a truly informed debate – lots of conjecture, no real analysis,” said Charlie Fischer, chief executive of Nexen Inc., one of Canada’s largest oil producers.

“I am still a long way from knowing what this will cost our company.”

The country’s energy sector opposes Kyoto, fearing it puts Canada at a disadvantage to countries not bound by the international agreement.

Canada was one of 160 nations that gathered in Kyoto, Japan, five years ago and signed the protocol to slash emissions to six-per-cent below 1990 levels by 2012.

However, Canada’s emissions rose steadily throughout the 1990s due to a booming economy and record energy exports to the United States.

Canada now needs to reduce emissions by 240 megatonnes, or more than 20-per-cent below 1990 levels.

The oil and gas sector – the lifeblood of Alberta’s economy – is responsible for about 18 per cent of all industrial emissions.

The energy sector is worried about the treaty’s impact, as man-made emissions are created mainly by burning fossil fuels such as crude oil, coal and natural gas.

Experts say any significant attempt to reduce emissions will drive up operating costs in the energy business.

“A lot will depend on how the accord is carried out,” said Lawrence Solomon, managing director of Energy Probe Research Foundation in Toronto.

“We’re already seeing some investor uncertainty” in oilsands ventures due to the accord.

Since summer, the Alberta government has fiercely fought Ottawa on Kyoto, saying the deal’s timetable is too aggressive and the targets are unattainable.

According to a provincial study, the deal could cost Alberta’s petroleum-rich economy up to $5.5 billion a year and result in 70,000 lost jobs.

Ottawa, however, says the impact will be moderate, with the price to produce a barrel of conventional oil rising by three cents.

Energy Minister David Anderson told reporters that implementing the protocol will be “painless and seamless.”

His department estimates forcing companies to reduce emissions and consumers to pay more for energy will cut economic growth by 0.4 percentage point between now and 2010.

Industry received some concessions during negotiations with the federal government this fall.

Ottawa has agreed to cap the amount of emissions reduction required by heavy industry – including oil and gas producers, miners and manufacturers, along with power generators – at 55 megatonnes.

Ottawa also said this week it would likely cap the amount of money industry would pay for green credits – the right to emit carbon – at $15 per tonne, minimizing the price risk.

Environmentalists say the industry won major gains, with the federal government bending over backward to accommodate business concerns.

“What a number of people in the oilpatch undertook was really just scare-mongering – trying to frighten people as a negotiating tactic,” said Robert Hornung of the Pembina Institute.

“At this point, any more industry whining or complaining about Kyoto, quite frankly, needs to fall on deaf ears.

“Every key point that has been raised has been addressed.”

With files from Bloomberg

Posted in Costs, Benefits and Risks | Leave a comment

Nuclear power a dinosaur

Posted on November 26, 2002 by energyprbe

Tom Adams
Hamilton Spectator
November 26, 2002

Power blackouts in Ontario are likely this winter or next summer. Last summer, we had barely enough power to scrape by, relying on emergency imports of power to make it through. The next time harsh weather drives up our need for power, the power system will be even weaker than it was in the summer.

The cause of our power problems is straightforward. Instead of promoting conservation and private sector investment in clean and inexpensive power plants, the government is betting our future on subsidized prices, expensive and risky nuclear power, and polluting coal power.

The worst threat to the reliability of our power supply is the four-reactor Pickering A station. These aging reactors became so dilapidated and dangerous that Ontario Hydro shut them down five years ago. Mike Harris then undid this sensible decision and we have been paying for it ever since. The Crown-owned Ontario Power Generation – successor to the old Ontario Hydro – initially promised that Pickering A’s overhaul would be completed by summer 2002. The overhaul is now four years late and 200 per cent over budget. Harris’s Pickering folly has created a shortage of power and driven up electricity costs.

Pickering has directly undermined our supply, but its indirect effects have been even worse. Unwilling to compete against taxpayer-subsidized nuclear reactors, almost no private power plants are being built anywhere in the province. Thousands of megawatts of private power plants – almost all environmentally responsible and small-scale – have been shelved.

As a result, electricity bills are up, and many people think deregulation is to blame.

There is a way out of this mess, but we need to act quickly.

First, we must stop throwing taxpayer money at refurbishing dangerously old nuclear dinosaurs. Nothing threatens Ontario more than being overwhelmingly reliant on this obsolete technology, which could shut down the entire province if a serious common fault emerges that requires us to shut down most or all of the reactors.

Second, we must restore the confidence of investors interested in generating power, not by offering incentives to a few token generators – the approach the government has adopted – but by genuinely letting them compete on a level playing field against coal and nuclear plants.

In electricity, real competition works. Thirteen years ago, the United Kingdom had a power system very much like the old Ontario Hydro – a bloated, debt-ridden monopoly enamoured of coal and nuclear power.

In 1989, it broke up the monopoly, privatized all but a rump of nuclear assets, and introduced competition. The result: A flood of new investment, mostly in gas-fired generation drove down prices, forced most coal and oil generation off the market, and dramatically cut overall emissions. Consumers now enjoy rates down 30 per cent from the old monopoly days. The quality of service has improved, particularly for the poor.

Nuclear power was exposed as grossly uneconomic. The privatized nuclear company called British Energy has been crushed by the market and is now being renationalized.

Ernie Eves is driving us back to the old Hydro by killing competition and reneging on promises to privatize. The result will be redoubled environmental and economic ruin, which was the legacy of the old Hydro. With news last week of Hydro One’s writedowns, it is clear that Ontario’s taxpayer-backed electricity debt is soaring again already. Our children are again being set up to pay our power bills.

The solution for Ontario is to switch to a system with a proven track record. The U.K. proves that, if politicians have the discipline to follow tried and true regulatory and economic principles, competition and privatization in electricity benefits the public interest.

Posted in Energy Probe News, Towards Shutdown | Leave a comment

Alarm over inexperienced Bruce operator

Posted on November 19, 2002 by energyprbe

Norm Rubin
Letter to the Canadian Nuclear Safety Commission
November 19, 2002

President Linda J. Keen
Canadian Nuclear Safety Commission
280 Slater Street
P.O. Box 1046
Ottawa, Ontario K1P 5S9
Fax: (613) 992-2915 (3 pages)

Dear President Keen,

We would like to comment on three related regulatory matters of great importance – one past, one present, and one future. We believe that each of these matters involves the recognition of an “obvious truth” concerning nuclear-safety regulation.

The past regulatory matter: We would like to commend you and the CNSC for requiring financial shutdown guarantees from Bruce Power (lessee-operator-licensee of the Bruce A and B Nuclear Generating Stations) and aggressively acting to ensure these guarantees as it became clear that Bruce Power’s majority owner — British Energy PLC — was approaching bankruptcy. By requiring that a nuclear operator have a minimum “depth of pocket” to care for its facility for 6 months without generating electricity or revenue, you have responded promptly and appropriately to protect the public from a threat that was essentially unprecedented in Canada. By doing so, you have also acknowledged an important “obvious truth” – that it takes more than an approved design, licensed operators, on-site regulatory inspectors and similar “traditional” regulatory requirements to ensure nuclear safety: it also takes financial solvency on the part of the operator. While this requirement has brought CNSC into the domain of financial regulation — a new and relatively uncharted domain for CNSC — we believe that the wisdom and necessity of this move is obvious, at least in hindsight, to any intelligent observer.

The present regulatory matter: Because British Energy remains insolvent except for a short-term emergency loan from the British government, expiring November 29th, active discussions are taking place about the post-November-29th future of British Energy, Bruce Power, and the financial guarantees that CNSC has required from Bruce Power. As you must know at least from published accounts, Cameco Corp. of Saskatchewan — currently a 15% minority partner in Bruce Power, and a CNSC licensee as a miner and refiner of uranium — has publicly stated its interest in significantly increasing its share in Bruce Power. According to reports in the business press, a consortium of Cameco, TransCanada PipeLines Ltd. of Calgary and Borealis Capital Corp. of Toronto is currently negotiating such a purchase with British Energy.

Energy Probe is concerned that such a purchase would transfer control of Bruce Power, licensed operator of two nuclear generating stations, from British Energy — an experienced operator of several nuclear generating stations in the U.K. and the U.S. — to three companies with no experience at operating nuclear generating stations. We believe that prudence, public interest and common sense once again dictate that CNSC must intervene to ensure that high-level management decisions about the operation of the Bruce nuclear stations must be made with due attention to the unique demands of this inherently hazardous technology. Just as CNSC has recognized that even a well regulated and shutdown nuclear station cannot be safe in the hands of an insolvent operator, we would urge you to recognize that even a well regulated nuclear station cannot be safe in the hands of an inexperienced operator with no demonstrated competence in this field.

We have by no means determined exactly how an inexperienced operator with no demonstrated competence in this field could remedy that problem and ensure that top-level decisions are made with due attention to the demands of nuclear power, but in our opinion the range of approaches for a nuclear-safety regulator to consider includes at least the following:

  • CNSC could insist that nuclear licensees without prior experience be required to undertake an apprentice program — that no nuclear reactor licenses will be issued to operators without satisfactory prior experience in operating nuclear reactors;
  • CNSC could require the certification of a reactor licensee similar to the way CNSC now requires certification of individual reactor operators — with prescribed requirements for education and demonstrations of competence through examinations. The analogous requirements for a reactor licensee could include senior executive staff and board-level committees with responsibility for reactor safety;
  • particularly in the case of new licensees, the CNSC could adapt its general regulatory approach, away from the “top-level” and “collegial” and toward the “prescriptive” and “adversary” — in effect, treating an inexperienced licensee as if it is inexperienced.

We would of course be pleased to discuss these and other options with you or your staff or Commission, should you consider that desirable.

The future regulatory matter: In August of this year, Ontario Power Generation and CNSC discovered a station-wide violation of minimum safety standards for “environmental qualification” of safety-critical equipment throughout the Darlington station – specifically, that “steam-proof” rooms containing steam-sensitive equipment (whose continued operation would be necessary to ensure the post-accident safety of the station) had holes in their walls. That violation clearly had the potential to prompt the shutdown of Canada’s largest generating station at a time when the Ontario power grid was already perilously close to collapse even with Darlington operating. We do not know whether the grid’s shortage of reserve capacity was a factor — consciously or unconsciously — in the CNSC’s decision to allow OPG to continue to operate that station in violation of its license conditions while finding and plugging the holes in the walls. And we note with relief that the holes have now been plugged, and that we did make it through that month of calculated risk (as well as the previous years of unknown risk) without experiencing one of the postulated accidents that created the requirement for steam-proofing those rooms.

But the incident raises a general nuclear-regulatory problem that we believe CNSC must address as soon as possible, and to our knowledge never has: The CNSC may be placed in an untenable position where the continued operation of unsafe nuclear stations is essential for the ongoing operation of an entire nuclear grid. While the holes in the walls at Darlington were arguably a small, temporary, and “survivable” safety violation, there is of course no guarantee that the next problem discovered will be. Faced with the discovery of a serious “new” risk — comparable to or more serious than, for example, the discovery of pressure-tube embrittlement in 1983 or of “fuel string relocation” in 1993 — CNSC might be faced with a practical choice between perpetuating an unacceptable reactor-accident risk on the one hand, and bringing the Ontario electrical system down on the other hand. We would submit that CNSC would be wise and prudent to ensure in advance that it is never forced into making such a choice.

Unfortunately, the present state of the Ontario electricity grid and marketplace may already make this vital flexibility unattainable this winter and next summer. Further, the planned return to service of the four shutdown reactors at Pickering-A and two of the four shutdown reactors at Bruce-A will likely make that situation worse, not better, by increasing the Ontario grid’s reliance on reactors of essentially identical design.

We suggest that CNSC should recognize that no nuclear reactors can be considered acceptably safe, or adequately regulated, if they cannot be taken out of service without thereby creating catastrophic or unacceptable consequences. We believe that recognition of this “obvious truth” would naturally lead CNSC to require minimum reserve levels (planned and actual) and maximum grid shares of nuclear power, or at least maximum grid shares of power provided by essentially identical nuclear reactors. We realize that these activities, like ascertaining the financial solvency of a licensee, would bring CNSC to examine matters that have traditionally not been considered part of a nuclear regulator’s job. But we believe that it is unacceptable not to do so.

Thank you for your attention to these important matters. We look forward to your response and are always available to discuss these matters further. I myself will be in Ottawa on Thursday November 21st to testify on bill C-4, should that time and place be convenient for you or your staff.

Sincerely,

Norman Rubin
Director, Nuclear Research
and Senior Policy Analyst

Posted in Energy Probe News, Nuclear Safety | Leave a comment

Probe of Pickering nuclear restart slammed

Posted on November 13, 2002 by Other News Sources

Canadian Press
Toronto Star
November 13, 2002

A government investigation into costly delays in restarting several nuclear reactors at Pickering, Ont. – shutdowns that helped create a supply crunch and soaring power prices – will offer little more than finger pointing, critics of the probe said Wednesday.

The inquiry will only further delay work on the project, which would bring about 2,000 megawatts of power back into the province’s supply – about 8 per cent of what’s needed at peak demand times, an electricity consultant said.

“By holding an inquiry, you’re essentially distracting the attention of management and the other people who are involved with the actual work and arguably, you’re delaying the return to service date as a result,” said Jan Carr, with Barker Dunn & Rossi in Toronto.

“To me, the important thing would not be to hold an inquiry, but to get the job done.”

Ontario Energy Minister John Baird will release details in the next few days on how the province plans to proceed in an independent investigation into delays at restoring power at the Pickering A station east of Toronto, said the minister’s spokesman Dan Miles.

The “significant initiative,” Miles said, will also find out why total costs to retrofit four nuclear reactors at the station – which has been out of service since 1997 – are estimated at $2.5 billion, more than twice the original budget estimate.

The restoration is intended to bring units built in the 1960s and 1970s to today’s standards. But Miles said progress reports on the revamp gave the provincial government a “gross underestimation” of the project’s scope and cost.

The stations were originally supposed to be back on line in time for this past hot summer, when rising air conditioner use helped create shortages and forced Ontario to import higher-cost electricity to meet demand. Combined with electricity market deregulation that began May 1, those shortages produced soaring prices that created a political backlash by consumers against the government.

Last month, Ontario Power Generation – the Crown-owned company that owns the Pickering plant – announced a third major delay of the restart. It said that one of the four A units would reach the “commissioning” stage in the first quarter of 2003, a testing process which the utility says could take one to three months.

The remaining three units are to be reassessed once the first unit is back online.

OPG spokesman John Earl said the big power producer isn’t commenting on the proposed investigation, announced Monday as part of a broad plan by Ontario’s Conservative government to cap soaring electricity prices, promote alternative energy and attract more private power producers to the province.

Last month, OPG chief executive Ron Osborne said the delays and higher expenses were from “overly optimistic” early budgets, too much outsourcing of project management and lengthy environmental assessments which create higher salary and other costs.

That’s about all an inquiry would reveal, said Jonathan Dickman-Wilkes, a senior analyst at Navigant Consulting in Toronto.

“It’s kind of more of a finger-pointing exercise than anything else,” he said, noting that it would be unfair to suggest retrofitting the decades-old stations is an easy task.

“This is 1970s technology,” he said. “They need to sort of overhaul a 1970 Chevy. That hadn’t been done before.”

This week, the Tory government of Premier Ernie Eves blamed rising prices partly on Ontario Power Generation’s failure to get the nuclear plants running again. OPG is the electricity producing successor to the former Ontario Hydro and accounts for nearly three quarters of electricity generated in Ontario.

Others blame the provincial government for not being more directly involved in the Pickering project.

“The government is blaming everybody but themselves and they are responsible for putting this (market) together,” said Arthur Dickinson, president of the Association of Major Power Consumers in Ontario, which supported energy market competition but only if it lured more suppliers.

Private power producers have said that confusion over when the huge reactors would come back online left them unable to predict whether it would be worth it for them to build new plants in Ontario. New plants would reduce supply concerns and in the long term lead to more stable prices.

Dickinson said that in retrospect, the May 1 opening of Ontario’e energy market to competition should have been held off until the Pickering A reactors were back on stream.

“Why were they asleep at the switch?” he said of the government. “It’s not good enough to say, ‘that’s not what we were told.'”

“When the delay was repeated, why didn’t they get more interested then?”

Tom Adams of Energy Probe – whose group claims nuclear energy is too costly and unreliable – said the Pickering project should be cancelled. He said the government “should never have bet on Pickering in the first place.”

He also said the probe would reveal that problems were discovered during Pickering A’s retrofit, partly because there were discrepancies between on-paper designs of the station drawn up decades ago and the actual reactors. That left federal safety regulator officials asking more questions.

“We know that the scope of the project has been steadily expanding,” Adams said. “But I don’t suspect that there’s a lot of wrongdoing here.”

Dickinson said a panel of politicians at an inquiry would provide little insight into OPG’s problems.

“Running a nuclear station is highly technical. If they have a panel of MPPs, what are they going to know? The easiest thing in the world is to snow MPPs on something as technical as this,” he said.

“You need people that understand nuclear facilities to have any chance at reasonable analysis.”

Posted in Nuclear Plant Security | Leave a comment