BC’s Electricity Conundrum – Politics, Profits, and Potential Partnerships

Posted in Uncategorized at 6:07 pm by Administrator

The electricity generation situation in British Columbia, Canada is both simple and complex. The simplicity arises from an abundance of hydro-electric generating capacity. The complexity comes from a somewhat disjointed ownership of generating assets compounded by government policies that have been confusing to both generators and rate-payers.

Starting in 2002 BC Government policy mandated that BC Hydro (the publicly owned near-monopoly) change the way it added new generation capacity. Updates to existing hydro facilities and development of new large-scale hydro facilities would remain with BC Hydro. However, integration of new renewable and small-scale hydro generation would have to be through long-term purchase contracts with Independent Power Producers (IPPs). The rationale provided for this decision was the desire to transfer the risk of investments in new generation to the private sector.  Given the guaranteed electricity rates, long-term locked in contracts (20 to 40 years) and “take or pay” provisions I don’t see much risk being transferred to the IPPs.  What I do see is guaranteed increases in power rates for electricity which might not be required or might be better provided through public sector investments.  As you might expect there has been a veritable stampede of IPPs bringing forward all manner of generation proposals.  Over-subscription is usually an indication that what’s on offer is a pretty safe investment.

There are two fundamental issues at the heart of BC’s push for additional generation capacity (and the resultant growth in IPPs) .

The first issue is the Provincial Government’s stated desire to make  BC “self-sufficient” in terms of electricity generation.  Just how to determine whether or not this condition has been met is a contentious issue.

As in every jurisdiction peak demand in BC lasts for only a few hours on a few days or weeks of the year.  At all other times and on all other days there is ample generation capacity already existing in the province.

So how do we handle those peak demand events which might be due to low water levels in hydro reservoirs or particularly hot days or particularly cold nights?

In the past BC Hydro had access to the 900 MW Burrard Generating Station (BGS) which could ramp up quickly to meet demand spikes.  It has performed that job admirably since its construction between 1962 and 1975.  In July, 2009 the BC Utilities Commission (BCUC) issued a report stating that “the Commission Panel declines to endorse BC Hydro’s proposal to reduce its reliance on Burrard for planning purposes” (page 115).  In other words the BCUC found it to be in the public interest to continue to operate BGS during demand peaks as required (typically less than 10% of capacity on an annual basis).

On October 28, 2009 the BC Government issued a press release over-ruling the BCUC decision and has subsequently not allowed BC Hydro to include BGS for planning purposes. This administrative decision effectively removed 900 MW of firm capacity from BC Hydro’s generation fleet and provided some justification for the acquisition of new generation from IPPs (as stated explicitly in the press release).

Another side effect of this decision was the rejection of any upgrades to BGS that could have substantially reduced the Greenhouse Gas emissions of the facility while show-casing relatively environmentally friendly CCGT technology – technology that is being aggressively deployed in many other jurisdictions.

Even without considering BGS there is considerable debate about whether or not BC is actually “self-sufficient” with regards to electricity generation.

The situation is made more complicated by the Columbia River Treaty between the U.S. and Canada.  This treaty, ratified in 1964, allocates up to 1.2 GW of generation capacity in Washington State to Canadian “ownership” in return for Canadian dams constructed on the Columbia River in aid of flood control in the U.S.  As a matter of practice BC Hydro has not taken this electricity in kind but has instead received the proceeds from the sale of this electricity to U.S. customers.

There are also two industrial concerns (Rio Tinto Alcan and Fortis BC) which own and/or operate hydro-electric facilities with approximately 1.3 GW of generating capacity. Both of these organizations have the ability to enter into electricity sales agreements that are not controlled by BC Hydro, including export sales.

More detailed analyses of the “self-sufficiency” conundrum can be found in studies by Sopinka and Kooten (2010), Hoberg and Sopinka (2011) and Sopinka and Pitt (2013).  A chart indicating the various sources of generation in BC as of 2011 is shown below.

The bottom line is that it would be very difficult to conclusively state that BC has insufficient electricity generation assets to meet domestic needs in the foreseeable future.

The second issue driving the need for additional IPP generation in BC is the forecast for future electricity demand.  This too, is a contentious issue.

In 2004 BC Hydro forecast that annual electricity demand would be 72-76 GWh in 2024 as shown in the chart below.  Without additional generation additions and with the loss of Burrard Generating Station a growing deficit in generation capacity was forecast.

Source for 2012 Forecast    Source for 2004 Forecast

Eight years later the 2024 Forecast should have been much better defined.  In fact, the revised forecast is for between 62 and 72 GWh.  Not only has the total amount moved down but the uncertainty has increased significantly.

Even this downward revision of demand seems to be too high.  Although the figures displayed in various BC Hydro publications are not totally consistent the “domestic” demand listed in the 2012 Annual report (page 91) was 52.197 GWh.  This is considerably less than the 57 GWh forecast in 2004.  All things considered it is very difficult to feel comfortable that BC Hydro projections are solid enough to warrant entering into long-term contracts for additional IPP generated electricity – electricity that is very significantly more expensive than that produced by existing legacy hydro facilities.

The impending development of some LNG facilities in Northern BC may lead to an increase in demand.  However, it is quite likely that these plants will generate their own power using natural gas.

So what is the optimal path forward regarding electricity generation in BC?  It seems to me that there is too much uncertainty around demand projections, the impact of conservation programs, LNG developments and most importantly Government policy regarding use of the Columbia Treaty allocation and other aspects of electricity “self-sufficiency” to be able to easily discern that path when considering BC in isolation.  However, if we broaden our perspective to include a more regional view I think there are some hard facts that may point us in the right direction.

The Alberta and Saskatchewan economies are growing relatively quickly and both provinces are heavily dependent upon coal-fired plants for electricity generation.  Alberta has also made a significant commitment to developing its abundant wind resources and has more than 1 GW of capacity installed as of the end of 2012.  More wind developments in both Alberta and Saskatchewan are planned but integrating this intermittent resource is proving to be a challenge. The Alberta Electricity System Operator (AESO) has undertaken a multi-year investigation into how this challenge can be overcome.

Hydro facilities have the ability to follow rapid changes in the transmission system because output can be varied in less than a minute.  As a result, using hydro to cushion output variability from wind farms is a very effective strategy.   In Denmark and Germany this is accomplished using hydro resources from Sweden and Norway.

So here is a proposal.

The Site C dam proposed for development by BC Hydro is currently undergoing environmental review.   It remains unclear if this additional electricity is actually needed in BC.  However, this dam, located as it would be only about 100 km from the Alberta border, could act as backup to a much expanded development of wind resources in Alberta and potentially Saskatchewan as well.

The current plan is to equip the dam with 1.1 GW of generation capacity.  But what if that was increased to 1.7 GW?  Production at that rate would deplete the reservoir and is therefore unsustainable over the long term.   But production at that level would be possible for many hours, possibly a few days – enough time to cover calm periods in Alberta when there was very little wind resource.

This over-capacity could work in conjunction with up to 2 GW of wind farm development in Alberta to reliably deliver emissions-free electricity to both provinces.  The amount of “firm” and dispatchable electricity would be the average output of the wind farms plus the average output of Site C – roughly 600 MW of wind (at a capacity factor of 30%) and 1.1 GW from Site C for a total of 1.7 GW.

In periods of high winds (> 600 MW) electricity would flow into BC and the Site C output would be cut back and the Site C reservoir would be refilled.  When Alberta wind farm output was low the excess generating capacity at Site C would be used to make up the difference, drawing down the reservoir.

Both Alberta and BC could be guaranteed a certain amount of electricity.  For example, if it turns out that BC does not really need all 1.1 GW from Site C then the output could be split with Alberta receiving 1.2 GW of the aggregate 1.7 GW and BC receiving 500 MW as shown in the chart below.  In that situation Alberta would be agreeing to purchase an average of 600 MW of output from Site C.

If it turns out that BC needs more than 1.1 GW from Site C then the output could be split differently with Alberta receiving perhaps 400 MW and BC receiving 1.3 GW.  In that situation BC would be agreeing to purchase an average of 200 MW of wind generated electricity from Alberta.

The split could be renegotiated from time to time.

This proposal would allow the two provinces to work co-operatively to develop emissions-free electricity generation to meet future requirements.  By pooling demand and negotiating a split of output that worked well for both provinces the risks associated with developing Site C and greatly expanding wind generation in Alberta would be minimized.  This approach could serve as a model for similar arrangements in different parts of North America.



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