Crown Corporations -- Issue No. 15 -- Wednesday, May 28, 2003 a.m.

2003 Legislative Session: 4th Session, 37th Parliament
SELECT STANDING COMMITTEE ON CROWN CORPORATIONS
MINUTES AND HANSARD

Present: Ken Stewart, MLA (Chair); Harry Bloy, MLA (Deputy Chair); Pat Bell, MLA; Susan Brice, MLA; Daniel Jarvis, MLA; John Les, MLA; Barry Penner, MLA; Rod Visser, MLA; Dr. John Wilson, MLA; Patrick Wong, MLA

Unavoidably Absent: Harold Long, MLA; Joy MacPhail, MLA

1. Pursuant to its terms of reference, the Committee examined the British Columbia Utilities Commission (BCUC).

    Witnesses
    Mr. Peter Ostergaard, Chair and Chief Executive Officer, BCUC
    Mr. Jim Fraser, Manager, Strategic Planning, BCUC

2. The Committee met in camera to review its examination of the British Columbia Utilities Commission and the Insurance Corporation of British Columbia, examined at an
    earlier meeting.

3. The Committee met in public session.

4. The Committee adjourned at 11:59 a.m. to the call of the Chair.

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE
ON CROWN CORPORATIONS



CONTENTS

		Page

Review of Crown Corporations: B.C. Utilities Commission		213
	P. Ostergaard J. Fraser

Chair:

* Ken Stewart (Maple Ridge–Pitt Meadows L)

Deputy Chair:

* Harry Bloy (Burquitlam L)

Members:

* Pat Bell (Prince George North L)
* Susan Brice (Saanich South L)
* Daniel Jarvis (North Vancouver–Seymour L)
* John Les (Chilliwack-Sumas L)
Harold Long (Powell River–Sunshine Coast L)
* Barry Penner (Chilliwack-Kent L)
* Rod Visser (North Island L)
* John Wilson (Cariboo North L)
* Patrick Wong (Vancouver-Kensington L)
Joy MacPhail (Vancouver-Hastings NDP)

* denotes member present

K. Stewart (Chair): This morning we have on our agenda the review of the B.C. Utilities Commission. I think we'll just start right in with that. You have your agendas before you. We'll be following our regular pattern of an hour for presentation and an hour for questions. Then we'll go into other business and a review in the final hour.

The first thing I'd like to do is introduce the people who are with us today. We have a couple of committee members who are attending other meetings and will be in and out. We'll first announce all those that are here. You can see that everyone does have a name tag, so if someone does come in during the proceedings, we'll just go by that, and we won't stop for introductions.

K. Stewart (Chair): I'm Ken Stewart, the MLA for Maple Ridge–Pitt Meadows.

P. Ostergaard: My name is Peter Ostergaard. I'm the chair of the B.C. Utilities Commission. With me is Jim Fraser. Jim is the manager of strategic services with the commission staff.

Mr. Chair and committee members, thank you very much for the opportunity to brief you on the activities of the BCUC this morning. The staff and commissioners at the commission are proud of what we do, and we're excited about the many changes to our mandate that are upcoming. We're also looking forward to your feedback on how we might do things better.

This presentation is arranged to walk you through the topics you see on the screen. I hope you've had a chance to scan our service plan and last year's annual report. I am certainly not going to dwell on those in terms of reading them to you. Rather, I think I'll cover who we are and what public interests we serve and how we've anticipated and managed changes to make ourselves a more effective regulator.

The government has entrusted the commission with many new roles and responsibilities with New Era and Energy for our Future: A Plan for B.C. I'll go over some of these. To give you a sense of the kinds of decisions we make, I'll highlight a few of them. Goals of the recent service plan will be noted, and I'll review three or four areas where new legislation will affect us. Finally, I'll review what we've done to measure our performance over time and to measure our performance compared to other utility regulators.

Who we are — BCUC today. An overriding theme of regulators of monopolies is to balance the interests of those who pay for monopoly services with those of the monopolies' owners, the shareholders. One of our most significant roles is to set the revenue needs, usually annually, for the 25 or so utilities under our jurisdiction. The revenue requirement or cost of service is the sum of the utility's operating costs plus its cost of capital. Its cost of capital is, in turn, a function of its rate base, cost of debt and cost of equity.

The biggest five utilities in B.C. are B.C. Hydro; Aquila — which used to be known as UtiliCorp and, before then, West Kootenay Power; Terasen, formerly known as B.C. Gas; Terasen Vancouver Island, formerly known as Centra; and Pacific Northern Gas, both the west and northeast divisions. We don't regulate interprovincial pipelines such as Duke, formerly Westcoast, or the telephone companies or cable TV. Those are federally regulated.

Once the revenue requirements are known, the next step is to divvy them up according to the classes of customers. This often requires a cost-of-service allocation study, which functionalizes, then classifies and allocates costs to specific customer classes — residential, commercial and industrial, for example.

Utility additions require a certificate of public convenience and necessity from the commission before they can be recovered from customers. The largest ones approved in the last few years was B.C. Gas's southern crossing pipeline project.

Changes to the Utilities Commission Act about 15 years ago gave the commission the responsibility to review gas and electricity supply contracts. Gas utilities, in particular, are encouraged to precede these contracts with annual procurement plans and risk management plans — how much gas to hedge, how much to store and how much to buy at Sumas versus station 2 or AECO in Alberta.

We also adjudicate complaints. We had up to 2,500 complaints per year, particularly when gas commodity costs were increasing. Other services we provide include divestitures — for example, custom works being spun off from B.C. Gas Utility — and mergers and acquisitions — for example, B.C. Gas's purchase of Centra and Centra Whistler.

Our budget traditionally is around $3.3 million a year. This has been increased this fiscal year to $4.7 million, primarily in anticipation of ICBC regulation. We are fully cost-recovered based on a levy of the volume of energy sold. We do not dip into the consolidated revenue fund. Any end-of-year surplus is credited back to the utilities at the beginning of the next fiscal year as a reduction to their first-quarter levy payment in that year.

Our public-good mandate. Continuing with a balancing-of-interests theme, our mission is to ensure that all types of ratepayers receive safe, reliable and nondiscriminatory energy services at fair rates, that shareholders of those utilities are given a reasonable opportunity — and I stress the word "opportunity," not a guarantee — to earn a fair return on their invested capital and that the monopoly components do not frustrate competition.

Under the Utilities Commission Act, cabinet and the Minister of Energy and Mines can give special directions and exemptions. However, it's important to note that commission decisions are not subject to review by ministers or cabinet. This is unlike the National Energy Board, for example. They can be appealed to the Court of Appeal after a reconsideration process within the BCUC itself.

B.C.'s first energy policy was issued in 1980. At that time the provincial government set the domestic price of natural gas. Oil prices and the export price of natural gas were set by the federal government. Electricity rates were set by B.C. Hydro with cabinet's blessing, and electricity trade just wasn't on anybody's radar screen. Today we have natural gas prices set in the market by producers and buyers and electricity trade within a wholesale market framework.

Regulatory approaches are also changing from annual adversarial hearings, where the utility tried to convince the regulator of the prudency of its expenditures and customers tried to convince the regulator that the utility was padding its rate base. So we've moved to multi-year settlements in most cases to try to align the interests of the utility and its customers.

Now, these two fundamental changes are largely responsible for reducing our staffing and budget needs by at least one-third over the past 15 years, while we are maintaining and hopefully improving service.

These sorts of strategic shifts happen in steps. For example, in the move from no competition to full non-discriminatory access to the electricity transmission grid, we approved B.C. Hydro's wholesale transmission services tariff in 1998 and allowed Aquila's industrial and municipal customers to buy from suppliers other than Aquila but using Aquila's grid to wheel the power — something that will be available soon to B.C. Hydro's large consumers.

On customer choice in natural gas suppliers, most industrial and large commercial gas users have been buying directly from producers or marketers for over ten years. With the licensing and bonding provisions of the Utilities Commission Amendment Act, we will introduce choice to small commercial customers by the fall of 2004 heating season and probably all residential customers shortly thereafter.

B.C. Hydro's first request for proposals for non-utility supply was in the early 1990s. The energy plan calls for private sector development of new resources, with B.C. Hydro restricted to improvements at existing plants.

With respect to incentive regulation using negotiated settlements, we seem to be evolving into a pattern of four-year or five-year settlements with annual reviews and efficiency targets. But every four or five years most customers will want a full hearing where the detailed accounts and expenditures can be questioned with the utilities' witnesses under oath.

The BCUC has aligned its mission, goals and objectives with the vision statements in the New Era document and the policy actions of the energy plan. An overriding theme in New Era is promoting competition and choices through private sector investments. The BCUC will continue to contribute to making B.C. a competitive place to do business through its activities in promoting fair rates. The challenge will be to simultaneously protect consumers and create a favourable environment for IPPs and marketers of energy products. Our baseline regulatory requirement count is about 1,100. To date we've eliminated 220, and we hope to eliminate several dozen more.

Because our act limits our ability to consider environmental and social matters, government may need to issue a special direction under section 3 of the act if there is to be a price premium associated with clean and renewable resources.

The four cornerstones of Energy for our Future: A Plan for B.C. are low electricity rates and public ownership of B.C. Hydro; secure, reliable supply; more private sector opportunities; and environmental responsibility and no nuclear power sources. The plan states that low electricity rates will be assured by entrenching the benefits of public assets, independently regulating hydro rates and outsourcing services where economic. Reliability standards are to be maintained, new supplies developed, and the BCUC is to be strengthened. To increase opportunities for the private sector, independent power will be developed, and ongoing support is to be provided for the oil and gas industry. Environmental responsibility is to be assured through a clean energy goal, new price signals for conservation and clean emission standards amongst other aspects.

There are 26 policy actions in the plan, and the BCUC will be directly or indirectly responsible for the successful implementation of about two-thirds of them. I won't go over these in any detail.

Policy 1. Our public inquiry into how to distribute the benefits of our low-cost hydro is underway with over 60 interveners.

Policy 7. The Transmission Corporation's participation in RTO West would need to be regulated by the BCUC, just like the participation of U.S. transmission owners would be approved by the Federal Energy Regulatory Commission in the States. Distribution utilities will be filing least- cost resource acquisition plans.

Policy 12. We've added the first of two new energy commissioners and hope to have the third on board in the fall. Contracts with IPPs will be reviewed by the commission.

Nos. 15 and 16. B.C. Transmission Corporation's rates, access policies and proposed reinforcements will be reviewed by BCUC. Natural gas marketers will be allowed to sell to commercial and residential customers and will be licensed to provide for consumer protection. There will be a voluntary goal for distribution companies to get half their new supplies from clean sources.

We're having a workshop on No. 21 with B.C. Hydro and large customers this week. The new section of the Utilities Commission Act will make it clear that utilities can earn a return on expenditures made to reduce demands for their product.

Recent decisions of interest. The old Westcoast Petroleum's intraprovincial — this is intra, or within the province — oil pipeline between Fort St. John and Kamloops broke in the summer of 2000. The new owners, Pembina, who had assumed ownership of the pipeline literally hours before it broke, did not want to reopen it, which would have left Husky's Prince George refinery stranded and B.C. oil producers paying more to ship oil to the west coast using Pembina's Alberta system and Trans Mountain's Alberta-B.C. pipeline system. After a long hearing and a commission decision that was unsuccessfully appealed in the Court of Appeal, the oil line is again operating.

PNG's line from Prince George to Prince Rupert and Kitimat has had a few difficult years. Last year, just as our hearing was winding down, PNG and Methanex came to a load retention agreement for a Methanex methanol plant in an effort to improve the plant's economic viability. That was subsequently approved.

As I indicated, we received about 2,500 complaints last year. Some require public processes to adjudicate.

In late 2001 we refused to allow UtiliCorp to sell its four dams on the Kootenay River to Columbia Power Corporation unless the sale was restructured to provide for sharing of the proceeds with UtiliCorp's customers. They paid for the projects. They deserve a little bit of the proceeds. UtiliCorp did not accept the commission's conditions, and the sale did not go through.

With respect to B.C. Gas, we held an oral hearing late last year on B.C. Gas's 2003 revenue requirements. We reduced the applied-for revenue deficiency by about half. We disallowed stock options as a ratepayer cost and directed B.C. Gas to come back with a multi-year, performance-based rate-making application, which they have subsequently done.

We just completed Centra's first rate design hearing. We hope to have the decision out shortly. We just approved, after a written hearing, a $70 million substation near Oliver, which wouldn't have been possible without B.C. Hydro and Aquila cooperating in coming up with the provincial solution that benefited the region as well. The alternative to this substation was a 200-kilometre high-voltage transmission line along the Highway 3 corridor which, as you can expect, would have raised all sorts of environmental and social concerns.

We have a busy summer and fall ahead of us with Terasen, a.k.a. B.C. Gas. The negotiated settlement process for a multi-year revenue-requirement application begins, I guess, two weeks from now. The report and recommendations by the commission to cabinet on the heritage contract is underway, and the report is to be delivered to cabinet by the middle of October.

The Duke Point project hearings start, as I indicated, in Nanaimo on June 16. We've had many workshops on gas commodity on bundling and customer choice in anticipation of a commission decision on business rules this summer so that the marketers can get underway to allow small commercial customers the choice of either going with Terasen or the marketers by the fall of 2004.

We expect revenue-requirement applications for the Transmission Corporation, Aquila and ICBC later this year. And a final point: we expect B.C. Hydro to file their revenue-requirement application in early 2004. A complicating factor will be the allocation of costs between the distribution and transmission entities. I expect we'll have interim rates in place by April '04, a public hearing in the late spring and a decision in the early fall. A rate design application would follow and, hopefully, a multi-year revenue-requirement application achieved by alternative dispute resolution starting in 2005.

We are able to be a little bit more efficient than we used to be. Until the mid-1990s, every utility lined up at the door every year to apply for a given rate of return on equity and deemed debt equity structure. Thereafter, we adopted a formula-based return based on long Canada bond rates plus a risk premium, if you're B.C. Gas, of 3.5 percent this year and higher if you're a riskier utility. B.C. Hydro's dividend to the province is calculated on B.C. Gas's pre-tax rate of return on equity, so currently putting it at around 15 percent.

Two years ago we established guidelines for gas utilities to file quarterly reports on their gas cost reconciliation account balances and their forecast gas commodity costs and revenues. Utilities are expected to file for a rate increase or decrease if their forecast costs and revenues for the following 12 months differ by more than 5 percent. This helps to dampen the wild fluctuations that we've seen in gas costs and in some jurisdictions where spot prices are passed through monthly. But this dampening also still sends price signals to customers.

If you've read the service plan, you've read the goals as well as the associated objectives, strategies and

performance measures related to each goal. We will implement these components of the energy plan for which we're responsible, and we will try to keep utilities viable and the customers satisfied. We will attempt to enhance the competitiveness of the province and keep our own costs in line and our client groups satisfied.

There are three pieces of legislation tabled in this session that affect the BCUC. Under the Utilities Commission Amendment Act, which I believe received third reading yesterday afternoon, utilities will be expected to file capital and resource plans and be able to receive a return on DSM investments, gas marketers are to be licensed and bonded, and it will be made clear that written hearings and alternative dispute resolution are legitimate review processes. There are also several other amendments to the act which…. Oops. I'm sorry. I went too far ahead.

Other sections, for example, repeal the commission oversight of electricity transmission contracts. As I mentioned, there are other less significant changes — housekeeping amendments, which we welcome.

Under Bill 58, starting in 2004, the commission would regulate ICBC's mandatory insurance function, but a review of optional rates would only be in the context of promoting competition by ensuring there's no subsidy of ICBC's optional rates.

Regarding the Transmission Corporation Act, the BCTC's role is to manage, operate and maintain the transmission grid to provide open access for all electricity producers, including B.C. Hydro and IPPs. The BCUC will continue to regulate the grid through BCTC as a public utility, and the legislation states that the commission can't review the policy decision to set it up.

Land and Water B.C. and the BCUC expect a government decision later this year on whether the rate regulation of water utilities not operated by local governments will be transferred to the BCUC or perhaps some other regulator.

How are we doing? I think it's a good idea to ask your stakeholders and client groups that question every two or three years. In 2000 we retained UVic to survey our three main groups: utilities, their customer groups and those who complain to us. Two years later a consultant was retained by the Ministry of Energy and Mines to interview our stakeholders as part of the ministry and agency core review process. Both studies were helpful in confirming that we were doing a good job, while identifying issues where we could improve our performance.

The next few slides serve as performance indicators tracking over time. These are in constant dollars. In other words, they're adjusted for inflation. We've been remarkably consistent at about $2.5 million over the last five years. Jim Fraser advises me the slight blip two years ago can be blamed on our legal fees in successfully defending a decision in the Court of Appeal.

We've gone from 30 staff and four full-time commissioners in 1990 to 19 staff and one commissioner in the late 1990s. So far this year we've added one regulatory accountant to increase our staff load to 20 and one full-time commissioner, Robert Hobbs.

Taking the total number of customers of all regulated utilities in that year and dividing that number into our expenditures in that year, we come up with a cost of regulation per customer. It's less than a dollar a year and a bit over half of what it was in the early 1990s.

Taking our annual expenditures and dividing that by the volume of energy sold by utilities in that year, the cost of regulation on a burner tip gas price of about $10 a gigajoule and a residential electricity price of about $16 a gigajoule is about half a cent a gigajoule — again, a bit more than half of what it was. Those dollar signs on the right-hand side of the bar should not be there. They should be cents. I apologize for any confusion.

Our indicators over time are generally favourable. How about comparisons with similar commissions in other provinces and states? One indicator is the budget approved for energy utility regulation divided by the population in that state or province.

B.C. ranks as the most favourable, at 81 cents per resident. Washington State is close, but the Washington Utilities and Transportation Commission doesn't regulate most transmission systems in the state. They're federally regulated — for example, the Bonneville Power Administration system. Municipal utilities like Seattle City Light are outside of the WUTC's jurisdiction. A couple of the Atlantic provinces are under a dollar a head, but don't forget they have little or no gas regulation in those provinces.

Being a low-cost regulator doesn't necessarily mean the BCUC's constituents are well-served. The remainder of this presentation takes all the applications that we've received over the last couple of years and calculates their cycle times — or time between the receipt of the application and a commission decision on that application. We've categorized them according to the four main ways the commission deals with these applications.

Now, most straightforward and non-controversial applications are managed by a staff review and analysis, often supplemented by information requests and responses from the utility applicant, but without a formal public review process. We've calculated our turnaround times for this category of application and compared them with the only other regulator which provides these numbers; that's the National Energy Board.

More complex applications need a public process — either a negotiated settlement process, a written public hearing or an oral public hearing. We have comparisons from the NEB only for the oral public hearing group of applications.

We've reproduced, on this slide, the commission agenda from two weeks ago that has seven applications for a commission decision. All were handled without a formal public process, but all had been reviewed extensively in advance by staff before debate

by the commissioners. Briefly, these seven were changes to Terasen's bypass agreements with large industrials…. The second one was an exemption for B.C. Hydro for a short high-voltage transmission line. There was a new gas transportation rate in the Elk Valley. There was an attempt by B.C. Gas, which we denied, to transfer $4 million of tax savings from the utility to non-regulated businesses. There were new contracting and price-risk management plans for Terasen.

For these applications and others, our cycle times average out to around 25 calendar days. Some quarters are busier than others. For example, in the summer of 2001 and the last quarter of 2002, the number of applications in those quarters were 28 and 27, respectively, which are the numbers on the bar graphs. You can still see that the cycle time stayed below 30 days, on average. Compare that with the National Energy Board. Its so-called non-hearing section 58 applications take, on average, 50 to 80 days to review.

One advantage of the negotiated settlement process over an oral public hearing is the time line between the start of negotiations and the commission decision isn't as long as the time lines between the start of the oral hearing and the decision. You still need the prenegotiated steps, including public workshops, and time for information requests and responses.

As this chart of all the applications managed by negotiated settlement process over the last few years shows, all but two were handled in less than six months with some less than two months. One disadvantage, obviously, is that if negotiations fail, an oral hearing is the only way to resolve it. I believe these negotiated settlement applications averaged about 117 days to come to conclusion.

Written hearings involve the normal intervener registration, workshop and prehearing conference, information requests and responses of the negotiated settlement process and oral hearings. With written hearings interveners state their positions in writing, followed by the applicant's reply. Written hearing processes have averaged out at about six months — about two months longer than the applications settled by a negotiation.

Oral hearings are quasi-judicial and adversarial. There are often motions to adjourn to digest new evidence or developments, and these are often granted for reasons of procedural fairness. Panel decisions take longer to write in anticipation of a possible appeal.

Our turnaround times for applications disposed of by oral hearings often fall in the seven-to-eight-month range, and compare that with the NEB's oral hearing cycle times, which are considerably longer.

The BCUC has led Canadian regulators in adopting innovative regulatory approaches. For example, in the mid-1980s we were the first to unbundle natural gas rates and provide for industrial bypass rates. In the 1990s we were the first to adopt the return-on-equity mechanism and first performance-based rates through negotiated settlements. We also want to identify areas where we no longer need to have a role as we've done by getting regulations rescinded and sections of the Utilities Commission Act repealed.

K. Stewart (Chair): We have a little extra time for questions, so hopefully we'll get most of our questions through. We have a process here where we start and just go around in a clockwise way, one question at a time, until we run out of time. I would request that the members start with their most relevant question first, and then we'll move down through.

As I mentioned earlier, any questions or information that isn't gleaned out of today's questioning or that we need further answers or response to go through the Clerk's office, and we keep that process open until we basically get our final report done.

Any of the questions that you're unable to answer today or if we run out of time today, they will be answered and come through the Clerk's office.

I think this morning we'll start with Dan, as he had his hand up for the first question. Then we'll just move around clockwise from there. Thank you.

D. Jarvis: Thank you, Mr. Ostergaard. Good report. I can see that in the future you're going to be very busy.

D. Jarvis: I think you're going to have to add some staff on in view of what's coming up in the future.

I go back to your page 10 with regard to the policies that you're working on or will be coming to. I think the two main things that really will be of concern are the legislated heritage contract and where are, if any, instructions you have now as to how you are going to go about it. There is a great concern out there by the public that hydro rates are going to go screaming up. Can you give me any sort of satisfaction or answer as to where you think they're going to go? That's going to be a big thing.

The second thing with that was the customer's choice of gas suppliers on policy 19. I don't understand how that's really going to work out, and I think it needs some explanation. We only have so many gas lines coming into the lower mainland here, for example, and they're usually full. It's usually the ones that have a lot of money. So where's the choice coming from?

P. Ostergaard: I'll start on the heritage contract and the issue of where rates are going to go. On the issue of where rates are going to go, it entirely depends on what B.C. Hydro is applying for in early 2004. I hesitate to comment on that. It depends primarily on the water conditions and the forecast water conditions in the province at that time. It will depend on their anticipated revenue from electricity trade. To a lesser extent, it will depend on the amount of growth in the province, in terms of demand, that they've forecast.

However, the heritage contract exercise that will precede the revenue-requirement public hearing to set

rates for 2004 is designed to ensure that that low imbedded cost of electricity from the hydraulic system, paid for and owned by British Columbians, is transferred through at or close to cost, as opposed to pricing that commodity according to market prices that may be influenced by conditions outside the province.

I'll let Mr. Fraser speak a little bit to the process on the heritage contract, and then I'll try to address your question on gas customer choice.

J. Fraser: There is a proposal or a discussion paper from B.C. Hydro before the commission. That process is underway. In fact, there were meetings this week. There was a meeting yesterday to deal with the stepped rate. For part of that inquiry there will be meetings next week to deal with that.

Interveners and interested parties will be filing evidence on the heritage contract in June. There are plans for some regional meetings in late July on that and then an oral public hearing in Vancouver starting in late July.

We have the process underway for that. We're still gathering information. We're getting the information from B.C. Hydro. There were a number of information requests sent out from the commission staff and from other interveners a couple of weeks ago, and the answers to those are coming in. We're really in the process of gathering information.

As the proposal has been filed by B.C. Hydro, that heritage contract would bring the power to the B.C. ratepayers at cost, and that cost would be determined periodically through a revenue-requirement hearing very much in the way other utilities' costs are regulated.

P. Ostergaard: Perhaps I can address the issue of customer choice and gas, which was Mr. Jarvis's third question.

P. Ostergaard: Right now you, Mr. Jarvis, and all of us as residential customers of natural gas — you're in North Vancouver — have no choice but to rely on Terasen Gas to buy our gas for us. They contract with dozens and dozens of producers. They contract with storage facilities in the United States and northeast B.C. and Alberta. They arrange with producers for seasonal and peaking supplies.

You may not be happy with their decisions. You might say: "My commodity cost of gas is too high. I read in the paper that the Sumas spot price today is $8 a gigajoule or $8 per MMBtus, but my burner tip rate is more than that." Along comes Ontario Energy Savings Corporation, Direct Energy in Ontario and Sears, which was in the game for a few years, and says: "I'll sign you up for a five-year contract for natural gas at a guaranteed rate of $7 a gigajoule." Of course to do that, they would have to ensure that they had that amount of gas lined up at that price hedged. They literally go around your neighbourhood, knock on your door and say: "I can do a better deal than your gas supplier." Terasen would still bill you, but it would show on your bill that your gas was from Sears and according to the contract.

The commodity component of your gas is arranged by someone other than the utility. B.C. has been a little slow compared to Ontario and Alberta to introduce this, and for good reason. We were very fast to introduce it for large commercial and industrial. For example, Canfor in Prince George has been buying gas directly from utilities other than Inland or B.C. Gas since the late 1980s.

The problem in B.C. primarily is our lack of underground storage. For those of you who remember the underground storage in the Fraser Valley debates of the early 1990s, the utilities always try to get as much storage possible close to their major metropolitan markets. There isn't any in B.C. compared to virtually all other areas in North America. Portland has the Mist storage. Seattle has the Centralia storage. Ontario has Dawn, etc. Alberta has Eco. This doesn't give the marketers the flexibility they can often get where they would take your gas and store it close to your house underground and then be able to release it. Storage is an issue.

Another issue with respect to customer choice in gas for small residentials is that the margins just aren't there. Studies have shown that most consumers won't switch unless they can see real savings of 10 or 15 percent on their gas commodity costs. Many customers who do switch just don't like the utility and are trying to reduce the amount of expenditures to that utility.

Perhaps our main concern in introducing this to the small commercial and residential sector is consumer protection. There have been chronic problems in other jurisdictions of door knockers getting a wet signature from you. You don't quite know what you're doing, but what you've just signed for is a five-year contract with a marketer who may or may not stay in business for five years. This is why, under the Utilities Commission Amendment Act, we have adopted the licensing and bonding provisions that were introduced after the fact in Ontario and Alberta to attempt to ensure that these marketers are credible, that the gas they say they have is backed by a bond and that they are licensed to have a code of conduct for ethical behaviour in terms of consumer switching.

What the commission has decided to do on this issue is put in place by November 2004 customer choice for small commercials. Then if that goes well, we'll extend that to all residentials.

P. Bell: Going through your service plan, some of the performance measures, I think, are fairly subjective. Then others are, I think, reasonably objective. I just wanted to bring it to your attention and ask for some further input.

I'll give you two examples. The one that I feel is fairly subjective would be relating to the goal: to enhance provincial competitiveness through discriminatory services. I believe that's goal No. 5 or 6 in your

service plan — something in that range. The performance measures and targets that you have are described as rates that are fair to each customer group as set out in timely commission decisions — for Centra, mid-2003; PNG, early 2003; B.C. Hydro, mid-2004. Then it goes on to say: tariffs that provide the same services to different customers at a cost that is fair and non-discriminatory under the circumstances. For me, that is a bit subjective in the sense that if ten of us sat down in the same room and all looked at it, I'm not sure we would come to the same conclusion.

Your next goal — I believe it's sequential; it's chart 1.6 in your service plan — is to enhance provincial competitiveness through the containment of cost-of-service increases. Your first performance measure is timely, clear and well-reasoned commission decisions, and you identify that as, if appealed, are upheld by the courts. Then you go ahead and list out the decisions.

You could put ten of us in a room, and we'd all look at that and, I'm sure, come to the exact same conclusion — or at least reasoned people would come to the same conclusion — that you had either achieved or not achieved that objective.

When I go through your service plan, though, I tend to feel that there are more subjective ones. Now, perhaps that's the nature of the business, because it is, I suppose, in some cases a balanced but subjective decision. I'd just maybe like some comments on that. Have you pursued that, tried to make it more measurable? If you have, or if you think there's an opportunity for improvement, how would you approach that?

P. Ostergaard: We've struggled with the same questions — agreed. This is our second service plan. I think it's better than the first one. Next year's will be better than this one.

I think it is the nature of a reactive regulator such as the BCUC that it's very difficult to have objective, quantifiable ways to measure your performance. I talk about this with the Crown agencies secretariat as well. Any ideas that you have to try to objectify these would be most welcome. I've raised it with my counterparts across the country. They see us leading in this area, so they're not of much help.

We could enhance provincial competitiveness through containment of cost-of-service increases, but we could also bankrupt the utilities at the same time. There is this balance we're talking about. Jim is responsible, primarily, for these targets,

J. Fraser: I think there is an element of the nature of the business that makes it very difficult. As Peter says, we've really struggled with this quite hard.

I think you hit on it very well when you were talking about fair, reasoned decisions and fair rates. If you have ten people sitting in a room, they may be unable to come to an agreement on what a fair rate is. It really is the nature of both the technical-analytical part of that business and the quasi-judicial nature of the commission that what a fair rate is, is usually the result of a lot of technical analysis that people may disagree with, and often do. Depending on which side of the fence you're on, whether you're on the consumer or the utility side, people may disagree on what a fair rate is. If you come from different customer classes, people will tend to disagree on what a fair rate is. There's a lot of debate either within the context of a hearing or in a negotiated settlement process to try and determine what a fair rate is.

It becomes even more difficult in trying to make that an objective benchmark for a service plan in that because the commission is a quasi-judicial tribunal, it can't really say in advance: "We're going to define a fair rate as this." Somebody may come back waving that and say: "You've prejudged the decision. You haven't actually listened to the evidence. You had a prejudgment in place, and therefore we're going to take you to court on that." I think there are a couple of elements of that. I think you've hit on it.

We've struggled and we continue to struggle with ways to come up with objective benchmarks. As I say that, there's a third issue that we struggle with in here as well, in that some of the benchmarks that we look at for the utilities…. Some of the things that relate to fair, safe, reliable service at low cost for consumers, we have to achieve through the utilities. When we've worked to implement, say, performance-based regulatory plans — multi-year incentive plans — what we've tried to do in those cases, for instance, is include benchmarks for the utilities to achieve in the areas of work around public safety — for instance, for reliability of service and those sorts of things, with some sort of modest but real incentive for the utility in that.

That's one step removed from being an objective that the commission achieves directly. These are all things that we're trying to come to grips with, saying: "How do we measure our own performance on these?" Peter, in his presentation, has talked about some of the things — our costs, our cycle time for applications, those kind of things — but to get to some of these other issues, we're struggling. I'm not sure we've got the answer yet, but we're trying to improve it as time goes on. It's a challenge.

J. Wilson: I had a question on your private water utility regulations. I guess my question would be that if it's a privately owned utility, the regulations that would apply…. Is that only in a case where there would be no other carrier or supplier in the area and people would sort of be at the mercy of the utility that was there selling the commodity?

P. Ostergaard: Yes. This is a function we currently don't have. Rate regulation of private water utilities is achieved through the Land and Water B.C. water controller's office. They have a small staff there that looks after setting rates for any water system that is not owned and operated by a local government.

The largest in the province is the city of White Rock, which is privately owned. The second one is

Breakwater up in the Parksville-Qualicum area. However, almost all the remaining 173 are very small. They are often anachronisms, holdovers from the days where local governments refused to take these rural systems in as part of regional district or municipal functions. The subdivision had been approved by Highways, but because the water system wasn't constructed or because local governments simply didn't want it, it had to remain in private hands. Many of these are in the Cariboo and Kootenays.

The core services review for Land and Water B.C. identified this function as one that would not be funded starting in the fiscal year beginning April 2004. Therefore, it's my understanding that Land and Water B.C. will be proposing to caucus this summer that the rate regulation function for these private water utilities be transferred to the BCUC. There are many similarities. The big concern we have, and I think government has, is to ensure that the larger issue of the integrity of water quality is not adversely affected by any such transfer.

I have a clarification and another question. You say that your '02-03 budget was $3.3 million. Was that just basically your full expenditures?

P. Ostergaard: That was our approved budget from a year ago. Our expenditures from this year were approximately $2.5 million.

K. Stewart (Chair): That's what I'd noted: the difference between slide 3 and 18. Just to clarify the process, then, the budget shortfall — which is, in a sense, a positive increase….

K. Stewart (Chair): Yeah. When you look at that from your forecast, what happens to that money, then?

P. Ostergaard: It is credited back to the utilities that pay for it in the first-quarter payment in the following fiscal year. We bill our utilities based on the volume of energy that they sold in the previous year. B.C. Hydro and B.C. Gas are by far the two largest funders of the Utilities Commission's budget. We bill them quarterly. Roughly speaking, we're billing them for about $3.7 million this year. There's a $700,000 credit, so basically there's no first-quarter payment this year. The surplus is carried over, and this year the surplus was so good that they will not be paying the first of the four quarterly levy payments for this year.

K. Stewart (Chair): So you have the same dilemma as the consumer does in the sense that you don't really know what the costs are going to be, so you try and forecast them over a period of time. Would that be correct?

P. Ostergaard: That's correct. Yes. We do not want to end the year in a shortfall situation, so we tend to be quite cautious when we submit our budget to ensure that all unanticipated costs do not result in that happening. For the last few years we've ended each year with a surplus ranging between $200,000 and $700,000, which is, again, credited back to the first-quarter payment.

K. Stewart (Chair): Just following up on the logic, this is part of the difficulty that you have in the long-term utilities cost that you have to give to the consumer and basically say is fair for the producers.

P. Ostergaard: Yes. We don't know what applications are going to be coming at us in the fiscal year starting April 1, 2004. We have a pretty good idea, but there may be a Pembina pipeline break again — I hope not — which comes at us, resulting in a lengthy hearing that has substantial costs.

Now, for those ones, we try to bill directly as well. The direct costs of a hearing are billed back to the applicant.

K. Stewart (Chair): So there's another source of revenue that you have where you charge for specific hearings.

K. Stewart (Chair): Okay. Then, basically, a high-volume producer, a high contributor from their percentage, is not subsidizing someone who is a higher user of your service in the way of applications, etc. That's a separate revenue stream.

The other question I had is with regard to comparatives. You used the NEB for your comparatives. Is there no one else out there that you can use? It just seems that if we wanted to make ourselves look good — in any agency, basically — we just compare ourselves to the feds with efficiencies, and we're probably going to come out okay.

Do you have any comments about some of the other organizations that you could go to? Other provincial jurisdictions? Comparatively sized American states with some of the areas that are similar?

P. Ostergaard: Yes, I can comment. I agree that the NEB is not renowned across the country as being an efficient, effective regulator. They are often accused of being very quasi-judicial, particularly with respect to upstream pipeline applications.

CAMPUT — the Canadian Association of Members of Public Utility Tribunals, which is a real mouthful — is an informal agency of commissions such as ourselves representing all provinces except Saskatchewan and has just hired an executive director. I will be pitching to him that every utility regulator in Canada should be developing these sorts of statistics so we can compare each other and come up with a better base for comparisons. I don't know if that will fly, but I'm sure some provinces will be quite keen on doing it. I do know that only ourselves and the NEB do it now. That's why these are the only two numbers that I was able to come up with for this presentation.

K. Stewart (Chair): I would hope that we could look at that for future presentations.

P. Wong: On page 20 you said that the cost of regulation per customer is 91 cents. Are you putting emphasis on the fact that your performance measurement in fact relies very much on the cost of each customer? Also, do you differentiate what type of customers you have — namely, commercial and residential?

P. Ostergaard: In terms of the second part of your question, there is no differentiation. What this statistic is, is that for each year, you take every utility that we regulate, all 20-some of them, and add up their total numbers of customers. Your household is probably a customer of Terasen and B.C. Hydro. Someone may have a seasonal residence, so it's also a hydro customer. They're your three customers. You take the total number of customers of utilities in B.C., you divide that into our expenditures in that year, and you come up with the 91 cents.

P. Wong: How are you going to account for that if you're going to include ICBC, say — another two million customers in the year 2004?

P. Ostergaard: I don't think that statistic will be relevant when we regulate ICBC. We will have to come up with some better indicator of energy utilities and ICBC.

P. Wong: One other thing is that you've reduced the number of staff from 30 to 19 in the last ten years. I understand that there's a lot of technical work — for instance, assessment of capital costs and all this kind of quasi-judicial function. Do you rely very much on outsourcing of expert advice?

P. Ostergaard: Generally, yes. We staff ourselves for the valleys and the peaks. We rely reasonably heavily on consultants. We retained, for example, a consultant to give us specialty advice on B.C. Gas's outsourcing of its customer works function relative to keeping it in. We retained a contractor to assist us with the regulatory accounting for the Pacific Northern Gas west and northeast hearings — sorry, negotiate a settlement process and written hearing, respectively — because we didn't have the in-house resources, given other things that were going on.

Having said that, I do think we are going to have to staff up by a few people once we begin with ICBC and bring Hydro fully back under commission regulation.

P. Wong: So you definitely have some comparative numbers of all these outsourcing costs in the last ten years?

P. Ostergaard: I don't have those numbers with me, but I can provide those to you.

P. Wong: Another thing is that you are the chair as well as the CEO of the operation. You said that you also hire a commissioner. I want to find out what are the distinctions and responsibilities between a commissioner, a CEO and also a chair.

P. Ostergaard: The Utilities Commission Act defines three types of commissioners. The chair of a commission is appointed by cabinet. The chair is also the chief executive officer of the organization. The CEO and chair are responsible for assigning work to the staff and ensuring the proper functioning of the organization.

Full-time commissioners are also defined under the Utilities Commission Act. To date, we have retained one new full-time commissioner. Mr. Robert Hobbs has been with us now for two months. He's the lead commissioner for the heritage contract.

The third grouping of commissioners are what are known under the act as temporary commissioners. They are generally part-time commissioners that are brought in, often on a term basis, to review a particular application. However, in reality, the four part-time or temporary commissioners we have now have been there for a few years. They tend to put in one or two days a week. They are put on specific panels to deal with specific applications, but they also help me with adjudicating the many applications that come before the commission that have undergone a staff evaluation but do not require some sort of public process.

J. Fraser: Can I add something? Mr. Wong, your first question about the staffing levels. I just wanted to clarify something or add something to Mr. Ostergaard's response.

Part of that decline in the staffing levels is not simply a result of outsourcing. In fact, I don't know what those numbers are, and I'd be curious to see. I think there are three procedural things we've done that have led to that. Partly why I mention it is because I think the commission's quite proud of them. I think it's a good story.

There are three things. One is that we've adopted…. Since I started at the commission in about 1992, we've adopted more of what we call generic proceedings,

proceedings where we can develop a mechanism to either deal with several utilities at once, rather than one hearing for each utility, or a mechanism that will operate over a number of years with relatively minor adjustments. The classic case of that is the mechanism for determining the return on equity. I think Mr. Ostergaard mentioned that earlier.

That used to be, I think, a proceeding that took place about once a year for each utility, and there were financial experts hired by the utilities and by the customer groups. They would get over and debate, to some extent, on how many angels can dance on the head of a pin and come up with a number, often, that was very similar. They would do that. The commission at one point…. I don't know if we were the first, but I think we were one of the first to say: "Is there not a mechanism we can do to determine the ROE in the first instance and then adjust that with some other economic mechanism that's easily observable?" We now do that, based on a formula that's based on long Canada bonds. There have been a couple of reviews periodically to make sure it still works or to make sure that it works in the context of sometimes changed economic circumstances. That's worked very well.

I think the other is that we've adopted negotiated settlement processes much more than we did in the past, as opposed to hearings. Those still occupy a fair bit of staff time, but I think they require fewer legal costs. They're shorter in terms of the actual process time, and they've gone a long way toward reducing the costs and the amount of staff that are required for those kinds of things.

If we can get people in a room for three or four days and those people get together and sort of beat it out and come up with an agreement, that agreement still has to go before a commission panel to be approved to make sure that all of the parties haven't come up with an agreement that hurts somebody or somebody who wasn't a participant, for instance. I think it's a very effective way.

The other is that we've adopted more performance-based regulation mechanisms that operate for several years. Those are essentially incentive mechanisms where the rates are set for a base year and then are adjusted annually with usually about a one-day annual review where the customers and commission staff get together and review the forecasts for the coming year and any anomalies in the utilities operation. Assuming that everybody is agreed that it's on track, they review the incentives, benchmarks, whether the utility met the benchmarks that it had for receiving any incentives under that mechanism to operate efficiently and what not and to control its costs. Then it proceeds on to the next year.

I think there are a number of ways in there that the commission has managed to get quite a bit more efficient over the past ten years as well.

K. Stewart (Chair): Barry, I know you were reporting out to cabinet, but I know you're up on this issue a bit. Do you have any questions for us?

B. Penner: Let me start by apologizing. Apparently, I was scheduled to be reporting out to cabinet this morning. But for whatever reason, nobody thought to tell me or allow me to schedule that into my calendar.

Forgive me if this question has already been asked. I know that extensive hearings are planned over the upcoming months to help determine the functioning of the new transmission entity and how independent power producers will be able to access transmission. What kind of funding do you see being made available to help third-party interveners participate in this very important hearing process, as we establish the ground rules for participating in the electricity market in British Columbia?

P. Ostergaard: The commission has guidelines for participative assistance, which every few years we bring out and ask for stakeholder comments on. The process, oversimplified, is that for any hearing or proceeding that warrants some sort of participant funding, the commission will publicize its guidelines and suggest interveners apply, according to the guidelines, by a certain date. This application is more in the way of a two- or three-page letter from an intervener, saying how they plan on participating and contributing to the process. We like to see them talk to other interveners with like interests to ensure that the proceeding is run efficiently — that you don't have two groups saying the same thing, asking the same questions. Then the staff will write back to the application and say: "Generally, we think the commission, at the end of the process, will award a certain amount of money to you."

Our upper limit is $1,200 a day for consultants and lawyers. The other general golden rule is one-day hearing, two days' preparation. That is considerably less than Alberta, for example. The Alberta Energy and Utilities Board last year spent $27 million on funding participants at AEUB hearings. That's nine times our entire commission budget. Twenty individuals in Alberta received participant funding of over half a million dollars last year. Alberta had lots of hearing days last year. There's an industry there. Our concern is to ensure that participant funding is helpful and constructive and genuinely needed.

With respect to the heritage contract…. I should also mention that the process is such that the commission panel, after the decision is issued, will receive final applications with receipts for participant assistance and make decisions and award costs after the fact. Most often, the panel will order that those costs be awarded and paid for by the applicant.

Now, in the case of the heritage contract inquiry, there is no real applicant. You could argue that Hydro has got its proposal, but in this case there is no real applicant. We budgeted a quarter of a million dollars this year for commission-sponsored participant assistance. It's my expectation that the panel that is hearing this will be able to award that quarter of a million dollars to participants at the heritage contract inquiry.

B. Penner: Thank you. I'll ask one more question, and then I have to duck back over to cabinet.

One of the criticisms I've heard is that it's very difficult for a potential intervener to make plans to participate, not knowing until after the hearing how much they're going to get compensated for the costs of participation. That makes some intuitive sense to me. I think that personally, I'd be very reluctant to embark on an undertaking if I didn't know how much I was going to get paid until the end of the undertaking.

I'll just leave that out there and let you respond, and I'll read your remarks in Hansard.

P. Ostergaard: Can I just, in Mr. Penner's absence, state for the record that this is the purpose of this letter that comes back from the staff early on. We will get requests for an intervener for $150,000, including two lawyers and three consultants at $5,000 a day. That is when we write back and say: "No. Our guidelines are $1,200 a day. We think that you're entitled to a lawyer for X number of days based on an anticipated hearing length of Y days. We think that we will fund you for a consultant for Z number of days for a total of approximately this."

It's been our position and the position of most participants in developing our participant assistance guidelines that if you're participating in a commission review…. The key word is "assistance" — participant assistance. It's not full participant funding, in the sense that there should, for many interveners, be some other source of funds to participate in a commission review. Otherwise, we're very fearful that we'll get into the situation that Alberta and Ontario are in, where they're trying to extricate themselves out of a participant assistance industry that leads to lengthy hearings and no negotiated settlement processes because there's no money in it for these interveners. It's a very difficult balance that we're trying to come up with.

S. Brice: I notice that on your "who we are" page, all of the bubbles focus down to: "Balance interests of utility ratepayers and shareholders." Of course, that includes not only the rates as such but the capital projects.

I wonder if I could just draw your attention to page 12 of your submission. I certainly don't expect you to make comment on particular projects, but I use it just because I'm interested in this particular one, and also to illustrate. With these hearings that will start in Nanaimo on the Duke Point project, what weight will the commission place on the fact that we're dealing with a geographic entity which probably, in the near future, has precarious power certainty, and if not this project, then what project? And so on.

How does that fold into the mix? And then how is the decision conveyed? Does the utility have a right to appeal?

P. Ostergaard: Thank you for recognizing that we will have to answer this question quite generally.

J. Fraser: I was just suggesting that perhaps I use the past commission proceeding into the B.C. Gas southern crossing pipeline project, in that it's difficult, and I don't think we can speak to that particular project, given that it's before the commission now.

The case of the southern crossing pipeline, if you don't know of it, was a pipeline from near the Alberta border in the southeast corner of the province through to Oliver. It was designed primarily as a way proposed by B.C. Gas to meet the peak demands of the lower mainland for natural gas supply. That was a proposal they brought forward to the commission.

The commission recognized in that situation, as it would with any kind of capital energy supply project like that, that there might be alternatives out there to that project. In fact, there was a number of proponents saying that they had other proposals that might work better. The commission, in that case, looked at all of the proposals with an eye to the fact that what it wanted was the proposal that gave the best service and reliability of supply to all of the consumers at the lowest cost, whether that was a utility project or a non-utility project. The objective function was to get the best service at the lowest cost, really.

In that case, the commission looked at it, and there were, in fact, two hearings, because it became a very close call. There was a number of proposals for LNG plants scattered along the lower mainland. There was a proposal for reinforcement of a pipeline north from the U.S. and proposals from what was then Westcoast Energy for reinforcement of its pipeline from northeast B.C.

The B.C. Gas proposal had some advantages but was probably not…. I'm going by memory, and I don't want to say something that's not true. It was on the cusp economically. It was amongst the lowest; I'm not sure it was the lowest.

One of the issues that really turned the balance on that was the ability to which it was going to be able to contract some of the capacity for that pipeline to other parties when it wasn't needed to serve the lower mainland. If there were opportunities for it to generate some extra revenue that would credit back to the ratepayers ultimately, then it looked good. If it wasn't able to do that, then it didn't look so good.

The commission, in that case, came down with the decision that said: "Yes, but if you can meet this benchmark…." During the hearing there were a number of statements made by the utility saying, "We're

very confident we can achieve contracts at these levels," so the commission basically went back and said: "Yes. If you can do that, then we'll rehear the application, and we think it has a good chance of going forward. If you can't do that, then you probably should go and contract with another lower-cost alternative."

S. Brice: Thank you. Had the decision been other than that, the process for appeal…?

P. Ostergaard: The process for appeal is quite straightforward. Under the Utilities Commission Act, an applicant can ask for a reconsideration of the commission decision. The commission will rule on that reconsideration — whether to — and if it feels that, yes, there is a legitimate point raised by the applicant, it may choose to rehear it. If that decision coming out of the commission on the reconsideration phase is not acceptable to the applicant, then it's the Court of Appeal that hears the request by the applicant. The Court of Appeal, depending on the case, may tell the commission to hear it again, or it may deny the request for an appeal of the commission's decision.

D. Jarvis: As somewhat of an extension to Ms. Brice's question, or the answer, there's always been somewhat of a question as to the validity of BCUC, what kind of strength they have, are they interfered with, and all the rest of it.

I'll give you two comparisons. One I was referring to was that I had been contacted by the Line Contractor's Association. Back in 1994 the commission ordered Hydro to come forward with a formal policy that would allocate targeting a certain percentage of work to the line workers association or the independents outside. They are contending that this doesn't seem to be forthcoming. What kind of influence are you going to have on them, or what are they required to do now?

Conversely, people have said that with B.C. Gas, they've been getting quite a few increases in their gas line. Have they got influence over BCUC, or how is it coming about in the sense of what are the specific requirements for B.C. Gas to get an increase in gas? If I can recall somewhere back there, they are allowed a certain percentage of their investment, and that's all they are able to charge. In other words, they are the milkman delivering the milk; they are not the ones that are producing the gas and/or the…. Can you sort of straighten me out on those?

P. Ostergaard: Why don't I start with B.C. Gas, and then Mr. Fraser can address the hydro contractors issue, which was before my time.

There are two components to your natural gas bill. One is the commodity cost of gas, which in a few years you will be able to contract with someone other than B.C. Gas if you feel you are paying too much, and the second is the milkman, the delivery charge. B.C. Gas makes no profit. There is no markup on the commodity cost component of your gas bill.

With respect to the delivery cost, yes, in the last few years, if you look at it, it has exceeded the B.C. consumer price index — the cost of living. Not by a lot, but it's been up, on average, 3 to 4 percent a year. The main reasons for that are the southern crossing pipeline that the commission, after two hearings, agreed that if there were a price cap on it, the utility could build and charge back to its ratepayers.

Another major cost was the consolidation of their lower mainland functions for long-term savings in their new building out in Surrey. They had to build a new Fraser River crossing because the old one was rusting out just underneath the Port Mann Bridge. That was a fairly expensive, directionally drilled project.

Another one is their transmission pipeline integrity plan project — primarily, again, in the lower mainland — where a lot of the pipes that were installed in the late fifties when the transmission system arrived in greater Vancouver are requiring some fairly significant rehabilitation work.

And the fifth reason for the capital expenditure increases of the last few years has been their contract with Accenture for the B.C. Gas customer works function. They've spent a lot of money on customer information systems that was not, in all cases, prudently incurred and eventually decided — and the commission agreed — to contract those services out to Accenture.

Those are all expenditures over the last few years that we do not anticipate them making over the next few years. The commission panel, in its instructions to its staff and B.C. Gas and interveners with respect to the negotiations that start in two weeks on a multi-year PBR, has dropped the very broad hint to the participants that the commission would like to see the delivery charges over the next few years below the B.C. CPI and are suggesting that the participants somehow incent the utility and ratepayers to make sure that that goal is achieved.

J. Fraser: With respect to the line contractors, that would normally be something that would come before the commission again if we had issued a direction to have B.C. Hydro offer a certain percentage of its line work to line contractors. That would be something that would tend to be reviewed in a revenue-requirements hearing.

We haven't done any revenue-requirements hearing for B.C. Hydro since that order was issued because of the rate cap and then the rate freeze. It is something that I would expect would arise when we do that. I can't say that that one is one of them, but when those sorts of issues have come up, I think a position that's been taken — I'm trying to be diplomatic here a little bit — is that the commission's responsibilities to rates…. To the extent that those sorts of internal issues at B.C. Hydro are management issues, under a rate cap

they don't affect rates, and therefore they're not the commission's concern under that situation. I expect that will come up again at the next revenue-requirements hearing, but it's been a long time since we've done one.

J. Les: Of course, I guess I need to start out by saying that I'd prefer the regulation of the free marketplace over the regulation by commission or by tribunal or what have you. However, I also recognize that the work of the Utilities Commission in this case is extremely important in that we don't happen to live in a society where we can find those immaculate conditions that we would sometimes wish.

However, in carrying out its work, it would seem to me that it's extremely important that the commission is impeccably impartial. I wondered whether you could tell us how that is assured.

P. Ostergaard: I alluded to that peripherally in my presentation — the concern amongst some of the stakeholders that the impartiality of the commission appointments and staff is assured. The main discipline is through the quasi-judicial process, where the interveners are very cognizant of the need for commissioners to be impartial and not influenced by government.

There have been cases, both in the BCUC and the NEB, where commissioners have voluntarily stood aside from a particular proceeding because they may have been unduly influenced in some form — not necessarily by government but by conversations with interveners that should not have taken place. The most celebrated one was Roland Priddle of the NEB, who had breakfast with an intervener of a process that had not yet been set down. The court found that that was not acceptable.

The Utilities Commission Act is quite handy in minimizing that from happening, and that is the use of special directions in section 3. For example…. I'll just quote section 3(1) for you: "The commission must comply with any general or special direction, made by regulation of the Lieutenant Governor in Council, with respect to the exercise of its powers and functions."

There have been many special directions over the years concerning the way that, for example, Hydro's exports are to be treated for revenue-requirements purposes. Another example was the Williams Lake wood waste plant in the South Cariboo, where the commission was directed to accept an environmental premium in the contract that was signed between that plant and B.C. Hydro.

Those are the mechanisms whereby government can legally convey its wishes to the commission instead of…. I suppose the alternative would be writing letters or phone calls to staff or commissioners.

K. Stewart (Chair): Just before we continue, we have approximately half an hour left, and one of our mandates is to clearly identify the benchmarks and indicators of the performance of the group before us today. If we can direct our questions towards that for the next half-hour, that would probably be helpful.

I know that when we have a group for the first time, it's nice to get out some of those general questions about operations. Certainly with Crown corporations, the fact that they haven't met with the group here of elected officials for 20 years or so, there are obviously some general questions. If we can concentrate for the last half-hour on the performance of the organization and some of the concerns we have with regard to benchmarking, then for the next appearance that would probably be helpful.

P. Bell: Since I asked my first question specifically on performance, I'm going to take a little lenience and move to a little more general question for my second one, so I apologize, Mr. Chair.

On page 11 of your service plan — and I'm just taking the one I printed out off of the Internet, so your page numbers could be different — is the objective "to enhance provincial competitiveness through non-discriminatory services." When I read the objectives, you've said, "Assess new institutional arrangements and promote reforms that are consistent with this goal. In the electricity sector this could involve membership in an RTO'' — and so on. It describes a number of things.

As a regulator, where is the line you draw between the management of the utility and the regulation of the utility? I'm not sure I'm describing this appropriately, although Jim's nodding a little so maybe I'm getting my question across. It's just the sense that I think it would be very easy to slip as a regulator from the notion of actually applying regulation and ensuring that utilities meet the standards, that the consumers are protected and that the returns on investment are applied back to shareholders. It would be very easy to slip from that into the physical management of the utility. I'd just like your comments on how you manage that. How do you try to stay away from actually managing the utility, or do you find at times that you have to slip into that mode?

We very much want to avoid slipping into the micromanagement-of-utility model. Utilities don't like it. There were decisions in years past which are celebrated by utility presidents as examples of commission micromanagement getting into individual salaries, getting into the number of aircraft hours logged….

We were reminded of this in the mid-1990s when B.C. Hydro took us to the Court of Appeal. Judge Goldie sided with Hydro, and one of his comments was: "The commission is not there to manage the utility." The fundamental issue at that time was that the commission demanded from B.C. Hydro a detailed, integrated resource plan, and Hydro claimed, quite rightly, that the commission did not have the jurisdiction to ask for that.

The way we try to manage it in our hearings and decisions is almost to group the expenditures according to generally accepted accounting principles, and

perhaps in our written reasons, we will talk around them. I'm using a hypothetical example here, but at the end in the commission determination we will say, "We think that this account is just a little bit too large, and we are going to cut that back by $200,000," without getting into specific detail as to where we're going to get that money from. We don't really care. We just think that account is a little rich, whether it's maintenance of compressor stations or whether it's charitable donations from the utility to charities.

J. Fraser: I think you've explained it pretty well. I was nodding. It's a really good question, actually, because it does come up. As Peter mentioned, we were taken to the Court of Appeal on it in one case, and the court found that we had strayed too far.

There's a real fine line between making sure that the utility is managed prudently and at least cost without the commission itself managing the utility. As you can imagine, it's always at the margin where the problems lie, where things are clearly within the commission's jurisdiction and within the purview of regulation. There's no issue where things are clearly in the purview of management. The issues always seem to lie in the area where it's a little grey and where there may be issues where we feel there are expenditures that aren't prudent or that perhaps transfer pricing between a regulated portion of a company and the unregulated portion, between the regulated utility and its unregulated parent. There can be issues there.

We often have interveners or parties coming to us with complaints that they don't like the way the utility is managing its business, for instance. Transfer pricing would be one that I can think of that came up in a recent hearing. That's a very tough call.

As I say, there are sometimes issues relating to the use of the utility name for promoting other activities of a parent company or a subsidiary. The name of the utility is the utility's name; that's the company's name, I think. Those seem to be the issues we get.

It's a good question, because it hits on, I think, a difficult line to demarcate. We do that as best we can. As Peter said, it usually comes back, in our minds, to: are the expenditures prudent? Can we tie that to prudent expenditures? If not, then the typical action the commission would take is to say: "You can do it however you want, but we're not going to let you collect all of that money, if it wasn't prudently spent, from the ratepayers."

J. Wilson: All of your clients, I would presume, would have service plans that you look at. I was wondering if you kept a report card on those things.

P. Ostergaard: Generally, they don't have service plans. What we do keep a report card on are the performance indicators that they say they will meet as part of a multi-year settlement over rates. For example, the fundamental approach to a multi-year settlement between customers of a utility and the utility is that its revenue requirements will be a function, in future years, of the consumer price index minus some sort of productivity factor. In other words, there's a productivity improvement component built into this agreement.

That's basically their service plan to us and to their customers. For that, they may be rewarded if they meet those targets — through a higher return on equity, for example — or penalized if they don't meet those targets.

I have a couple of very short questions. The first one is one that seems so good, I think I'll ask everyone as they come up. The new technologies that are out there now — computerization, all the new technologies that we're doing and, I suspect, in your area some of the geotechnical mapping and all that that's available electronically…. What type of innovations have you taken within your organization to implement those to help improve your performance and, I guess, the accuracy of the information that you contain and utilize within your organization?

P. Ostergaard: The main information technology decision that we have recently taken is to join the government's CITS system. We have found that our current Macintosh-based system is requiring too much work to integrate with the systems of our stakeholders and government, and we will be contracting out, in future, to CITS — at our request and with CITS's support — all information system technology improvements for the commission.

We are of such a size now, with only 20 staff, that we do not have any in-house support. We have two individual staff members that have an affinity for this, but occasionally our systems will crash for hours. That's no longer acceptable. We were directed by Treasury Board three years ago to negotiate with CITS, which we have done. Starting this year and phasing in, we will be thoroughly within the government's information technology system.

With respect to things like geographic information systems mapping, we don't do any of that. We rely on the utilities. We will encourage them to submit applications — as B.C. Gas has done, for example — for customer information and geographic systems — again, to ensure the expenditures are prudently incurred and offer real savings to the customers over the long term.

K. Stewart (Chair): I had a second question. I heard you mention a number of times this morning with regard to pegging things to the consumer price index. Given the fact that that's based on a lot of issues other than the specific commodities that come under your auspices for regulating, is that really a wise thing to do? If the price of wood goes up or the price of automobile costs go up or because of the house prices in Vancouver going up, is that really a good reflection or

measurement or way to judge whether the price of gas should be going up — or electricity?

P. Ostergaard: Good question. The component that is often pegged…. The CPI is quite often one component of a formula. There is often a CPI minus a productivity factor. That's just on the delivery margin component, which reflects the utility's labour, its borrowing costs and all the other costs that go into the cost of allowing that molecule of gas to be moved from the start of the B.C. Gas system to your burner tip. It's the same old issue. Yes, we're very receptive to better indicators than CPI or the B.C. CPI, but to date nobody's really come up with one that might be better. We know that it has its problems.

J. Fraser: One thing I'd add, too, is that these indicators — or the benchmarks that are the performance mechanisms that use CPI — are often developed through a negotiated settlement process. One of the key things that the parties all like about using CPI is that it's a highly visible known quantity. To the extent that there's uncertainty about it — I'm not sure if it's exactly the right phrase — it's probably offset by the negotiated aspect of how big the productivity factor should be. I think there's a real comfort factor, and I think people like having a known index like CPI, whether that's the Canada-wide CPI or the B.C. CPI. People like to use something they can find easily and find out what it is that's widely reported. That's the other reason we use it.

K. Stewart (Chair): The only comment I'd have with regard to it is that it appears that when people don't really have a good excuse for putting up the price of something, they'll use the CPI to put it up. If there's something happening in an industry or a marketplace that's of crucial interest to them, that's obviously the most paramount thing at the time so that if they have an issue, they'll use it. If not, then you fall back on CPI to get your three points or whatever it is.

Anyway, I'll just move the questioning on. Patrick, do you have another question?

P. Wong: On page 3, you have the mandate of balancing the interests of the utility ratepayers and shareholders. Do you mean the shareholders of the supplier?

P. Ostergaard: The shareholders of the utility only, not the shareholders of the gas producers or the shareholders of the independent power producers.

P. Wong: That includes both public and private suppliers and utility companies.

P. Ostergaard: It would include the people of British Columbia as the shareholders of B.C. Hydro, and it would include the shareholders of the investor-owned utilities that we regulate.

P. Ostergaard: How do you align the interests of the shareholders and the ratepayers?

P. Ostergaard: That's the essence of our support for negotiated settlements over many years.

Jim, do you want to give a couple of examples of how we can align the interests of shareholders and the ratepayers?

J. Fraser: Sorry. I'm not sure if you're saying how do we draw the line or how do we align interests.

J. Fraser: How we draw the line is always very difficult, and that's always done as a result of a negotiated settlement or a hearing. The commission hears from the interveners and the shareholders and has to balance the interests of both. I think that the commission's legislation requires that it give a fair return to the shareholders, which is the required return, which is essentially its cost of capital.

In some sense, in the long run, that is aligned with the interests of ratepayers. In some circumstances, if I remember correctly — and I'm going by a vague memory here…. I was reading quite a while ago that in the seventies, some utility regulators in the southern U.S. took a very hard line with the utilities, and the utilities responded by cutting service back to levels that were unacceptable and not investing in facilities that were needed.

I think the commission tries to find a level at which it allows the utility sufficient funds to operate it and to give it a fair return on its investment but not more than that. In terms of trying to determine what level of funds to allocate to a utility for its operations, one has to try and assess what's required to make sure that the system is safe.

Mr. Ostergaard was mentioning the pipeline integrity plan. As pipelines get older, there are more problems or issues related to stress — or maybe they're corrosion-related. As they get older, there are ways to monitor pipeline failure, but those are necessary expenditures so that one doesn't have pipeline breaks. One has to make sure that the utilities have sufficient funds to upgrade their equipment as necessary but not more than that.

It's a tough line. When we've gone to negotiated settlements or with performance-based regulation, what we have tried to do is align the interests of the ratepayers and the shareholders to say to the utility: "If you can meet certain benchmarks, if you can cut your costs more than what you've said you would, if you can find new efficiencies, we will allow you to keep some of those savings so that the shareholders and ratepayers will benefit." But it means trying to incent the utilities to be more innovative and more effective than they historically have been.

J. Fraser: Mr. Ostergaard may want to correct me, but I think there is an appeal mechanism beyond the commission with respect to questions of law. I think it is in the commission's legislation that questions of fact are up to the commission. If the commission decides factually that something is the case, then that's not appealable to the courts. If there is a question of whether or not the commission has exceeded its jurisdiction, then that's appealable to the courts.

If somebody disagrees with the commission's decision on a question of fact, then they would bring that to the commission for a reconsideration decision and say: "We think you have the facts wrong. We want you to rethink it."

K. Stewart (Chair): Actually, what I was going to say was at this point in time we've had a pretty long go at this. I was going to give it five more minutes, and then we'd have our recess. If anyone has got a burning question, we'll try and keep them as short as possible and the answers as short as possible — knowing full well that we can request further information in answering these questions through the written mode.

Peter would like to say something, and then I'll jump back to you, Barry, for questions.

P. Ostergaard: I'm sorry. I'll just add one more thing to Mr. Fraser's comments to Mr. Wong.

The single most frequently heard complaint across Canada by utilities is that the rate of return on equity awarded by Canadian regulators is too low. It's a chronic problem. Where do you put that balance? The regulator will go back to them and say: "Are you having trouble raising money? You're not. The capital markets will still provide you money." That, I think, is the one issue that is difficult in drawing the line between the interests of the ratepayer and the interests of the shareholder.

B. Penner: On page 8 of your PowerPoint presentation there is a bullet I'd like to ask you about — the last bullet on that page: "The commission may require a special direction to achieve the objective of promoting clean and renewable alternative energy sources, like wind, thermal, solar, tidal, biomass and fuel cell technologies." By "special direction," do you mean a special direction by government?

P. Ostergaard: Yes, special direction from cabinet under section 3 of the Utilities Commission Act. The best example is one I would have alluded to earlier. When Hydro, in the early 1990s, wanted to buy from the Williams Lake wood waste plant, the cost of electricity from that project was higher than the cost of electricity from gas-fired co-gens. Nonetheless, it was clearly in the public interest to allow the Williams Lake plant to go ahead. It had environmental and social benefits. From the perspective of the B.C. Utilities Commission, we're there for the ratepayer. We want to see Hydro contract the lowest possible costs, not trying to quantify the social and environmental benefits into the bottom-line cost.

I think the way the energy policy was ultimately worded will not cause this to be a problem. All I'm suggesting here is that the commission is quite limited in its criteria for which it would judge a contract between an IPP and B.C. Hydro.

B. Penner: You're suggesting, for example, that special direction may be required by cabinet to the Utilities Commission in order to encourage B.C. Hydro to be willing to pay more than the $55 per megawatt-hour they're currently offering under their green program in order to facilitate things like wind generation on Vancouver Island.

P. Ostergaard: It would be a special direction to the commission telling us to accept a contract, telling the commission to consider environmental and social costs notwithstanding its legislation to the contrary.

K. Stewart (Chair): Thank you. Any further burning questions out there in the crowd?

J. Fraser: I was just going to say that it's a bit of an open question. Where our thoughts from this come is that the issue of environmental cost was raised, I guess, in the mid- or late nineties. When it looked like the commission might try and add an environmental premium and say we wanted to encourage utilities to bring some clean energy on here, there was potentially a challenge from some of the interveners, who were saying: "We don't think you should do that. That looks like an environmental tax to us. We think that's outside your jurisdiction."

Rather than go to the wall on that one, we looked at the legislation and what the precedents were in other jurisdictions. The advice we got…. The legislation that was close to ours was from, I think, the public utilities commission in Massachussets. There, one of the courts had come down and said: "The commission here can look at environmental premiums to the extent that they look like they might be a real cost to ratepayers in the future. If the commission thinks that the government is about to put a carbon tax in place, and the utility is about to build a coal plant, then you have a right to look at those forecast costs of that power, using the carbon tax that you think may happen. To the extent that the commission was about to say: 'We're going to arbitrarily choose on our own to add a premium to some types of power or subtract a premium from the

That's tended to be the line that we have accepted. That's, I think, what we have thought probably would happen here, but it's not been tested. I don't know if that helps or not.

K. Stewart (Chair): That should be a pretty conclusive answer, given what we've got to work with.

P. Bell: I'm just wondering. One of the responsibilities you have is to adjudicate complaints. I'm presuming those come from both consumers and then perhaps utilities as well. Is that right?

P. Ostergaard: I think last year was a record — approaching 2,500. Almost all were from B.C. Gas customers complaining about the commodity cost of natural gas increases.

P. Bell: I guess, then, I have two questions. One, I'm curious what the settlement rate was in favour of the complainant. Two is: how much of the total resources of BCUC — of your roughly $3.5 million or $4 million budget, or whatever it is — is spent on dealing with those consumer-oriented complaints?

P. Ostergaard: I would classify our complaints into routine and non-routine. The routine ones, somebody's writing in complaining about the high cost of natural gas, to which we will send them an information package that we have developed at the staff level to try and explain the process to them.

Then there are other complaints dealing with disconnections, inaccurate billing — probably numbering several hundred a year. Those ones we will investigate…. I shouldn't use the word "investigate." With most of them we will get the complainant's permission to send to the utility to review. The utility will respond to us and the complainant, and then the commission will follow that up with some sort of closure, saying: "Yes, customer, you do have a point. The utility has admitted that it made a mistake and has settled by doing this." Alternatively, the commission will follow it up by saying: "We agree with the utility. Here is the tariff. It shows you, for example, the steps it takes in disconnecting you because you didn't pay your bill. It's followed a tariff, and your file is closed."

In terms of the resources we spend on this, it's not very much — probably one and a half staff positions, equivalent to maybe $140,000 or $150,000. We looked into the way that Quebec does it — where they actually charge a complainant $25 to enter the door of the Régie de l'énergie for the privilege of having their complaint investigated — and didn't like that idea. In Quebec, which is an exception, they will sometimes actually hold a hearing between a commissioner, a utility and a complainant, and then make a verbal decision.

P. Wong: Consumers are concerned about lower and stable rates. In respect of the protection of the consumer's interest, I understand that there are companies selling five-year terms for prearranged or an agreed rate in Ontario. You said that you anticipate this will happen in British Columbia. Is there any way that you can protect this? You said that this falls into your mandate. Would there be a possibility that would be under the mandate of the financial institution? The superintendent's mandate?

P. Ostergaard: The Superintendent of Financial Institutions? I don't believe so.

The key issue here, as I indicated, is ensuring that the marketer has the resources to deliver gas for five years. When we were looking at alternatives to legislation under the Utilities Commission Act to provide for licensing and bonding, we did not find that there were adequate protection measures in other institutions in British Columbia. That was the same thing that was found in Alberta and Ontario, where the utility regulator was given the powers of licensing and bonding marketers.

K. Stewart (Chair): Thank you very much for your presentation today. If there doesn't appear at this time to be any outstanding questions or issues.…

B. Penner: Subject to my comment about intervener's funding and what we could do to provide greater certainty so they could make plans about how to engage in the process. I know, of course, B.C. Hydro is able to recoup their costs of intervening by passing it on to ratepayers. Not so for the other third-party interveners.

K. Stewart (Chair): I think some of that was covered in the answer that will be coming forward in Hansard too. If there's any further information, we'd appreciate that.

I'd like to again thank you for your participation today. The process is that we will be going over a short review today. Then over the coming weeks we will be setting up a final draft of the report. Unfortunately, the report will not be available to you until the fall when we report out to the House, because this is a legislative committee and the reports are confidential until released

through the Speaker — just to make you aware. You can always go back to Hansard and see what you've said today. If in going over that, you have any further information that you'd like to submit to us prior to the formulation of the final report, we'd certainly be accepting of that.

Thank you again for your performance today, which we will be discussing shortly.

K. Stewart (Chair): We'll now go into a ten-minute break. At ten after eleven we'll come back and continue with our business.

K. Stewart (Chair): We'll now call the meeting back to order. There are a couple of issues I'd like to just go over with the agenda before we move in camera. I'd just like to ask: did we get the information back from ICBC, Audrey?

K. Stewart (Chair): Okay, so everyone has got that information. Any other business we'd like to discuss before we go in camera?

B. Penner: A comment, if I could, on the information we got back from ICBC. I would just like to indicate on the record my gratitude to ICBC for their

prompt and detailed response. It was more than I expected, and I'm quite pleased by it.

P. Bell: I, conversely, have a bit of a gripe. I had e-mailed — on the urgings not of Mr. Geer but the other gentleman who was here with ICBC, Bill Goble — about some issues identified, and I had to send a follow-up email yesterday because he had not replied in the better part of a month or even acknowledged the e-mail that was sent. Just on the record, the follow-up in that particular case was not very efficient.

K. Stewart (Chair): Moving on, are there any other items we want to discuss prior to moving in camera, where we will be discussing both ICBC and the group that was before us today?

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Witnesses:	Jim Fraser (B.C. Utilities Commission) Peter Ostergaard (Chair and CEO, B.C. Utilities Commission)

REPORT OF PROCEEDINGS (Hansard)

SELECT STANDING COMMITTEE ON CROWN CORPORATIONS

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE
ON CROWN CORPORATIONS