Down the Drain: A Solution to Nepal’s Power Crisis

Photo: a vortex before the turbine is connected

A frequent contributor to this blog, the author proposes a compelling solution to power problems in a small and mountainous, beautiful but poor Himalayan Kingdom with streams and rivers in abundance. The solution isn't what you might think....

By David DuByne
Nepal faces a load-shedding crisis: each year at certain times, electrical authorities cut off electric current on certain lines when power demand becomes greater than supply. As Ratna Sansar Shrestha explains in Hydro Nepal magazine, large-scale hydro projects can’t keep up with 10.7% annual increases in power demand. This is because of Nepal Electricity Authority’s (NEA) delayed completion of projects, system mismatches in the seasonal variation of water and inadequacies in much of this mountainous country’s infrastructure. As a result, severe load-shedding will continue at least into the dry season of 2017.

Economic losses from these planned interruptions include liquid fuel shortages as households and businesses burn fuel in generators that was destined for the transportation sector.

Solutions
These are the problems. Where are the solutions? Perhaps the best way to answer the question is to pose another one: If large-scale doesn’t work, what about small-scale?”

I have worked with renewable energy concepts over the last several years, and I think Gravitational Vortex Power (GVP) is a solution that could work for Nepal. Let me explain how it works.

You will notice when you pull the plug from a sink that when the water gets low it starts to spin into the drain hole. It actually makes a mini-whirlpool as the last of the water drains out. Scale that round hole up from something that is 12 cm in diameter to something with a 5-meter diameter and you create a larger amount of spinning water with a larger amount of kinetic energy. Gravity does all the work as water flows. Now add curved blades to dig into the spinning water, attach an electrical power generator and you have GVP. The rotational movement of water in the shallow circular basin creates a stable continuous gravitational vortex, 24 hours per day, seven days a week.

Viktor Schauberger from Austria was one of the first to make use of vortex dynamics from 1929-1936, and his has work influenced others. Zotloterer’s current design needs a 0.8 meter water drop and two cubic meters per second of water flow. That doesn’t sound like a lot of water to produce power, but these GVP plants produce 57,000 kWh per year. For comparison, per capita usage of electricity in Nepal was 78.5 kWh per year in 2010.

How can GVP be a Solution?
Kathmandu faces its own set of challenges, while in the countryside another set of variables limits the availability and supply of power. So how does using small hydro affect change in the national power grid? It boils down to economics and scale of raw material input for targeted output.

Let’s look a single Large Scale Project first, the Upper Tamakoshi Hydroelectric Project. The project, which will have a maximum output of 456 MW per day during the monsoon, will cost an estimated US$441 million, excluding interest. Maximum output will drop by 60% or more during the dry season.

Additional costs will include 132 kV high voltage transmission lines for future grid extension: between $8000–10,000 per kilometre, rising to $22,000 in difficult terrain. Then there is the cost of sub-station construction and additional road building at $20,000 per km. So assuming that everything is on budget (unlikely, based on past performance), let’s round off to $500 million. And one more thing: most of the new lines will by-pass rural communities in Nepal as they wend their way to India to serve Power Purchase Agreements (PPA’s).

By comparison, small GVP plants can use local materials, can cost as little as $10,000 and do not need to dam the water to operate. The GVP plant merely uses the water for a few seconds as it flows on its way down stream. Just the environmental advantages to its usage warrant further investigation as a solution. GVP is designed to be installed in remote areas that would never see grid expansion into local villages and is designed to electrify a small community of up to 200 homes per plant under Nepali consumption patterns.

If we use the same figure of $500 million for one large project that provides diminishing electrical output as rains decrease from October to May each year, you could build 50,000 GVP plants. These plants generating 57 MWh per year would equal 2,850,000MWh or 2,850 GWh annually fed directly to the local communities in remote locations that need it most. Here is where the shocking part comes in: the forecast annual energy output from the Upper Tamakoshi Project is 2,281 GWh. You generate more power from GVP, save on the amount of construction materials and do not need to dam an entire river!

With Nepal’s special set of circumstances we must think in inverse terms. The usual train of thought is to electrify from major population centers out to the countryside, but in Nepal’s case it needs to be the opposite to reduce load-shedding. This country needs to electrify from the countryside back into the cities, as most cottage industries are located outside large urban areas. The economy is stagnating from lack of power in these areas. If rural communities can generate their own power locally off the main grid, then excess power not consumed in smaller outlying districts can be diverted back into Kathmandu or other cities languishing in the dark.

Another benefit beyond revitalization of the rural economy would be that materials used for local construction will be bought locally and those living close to the GVP plants can maintain and repair the generators themselves, not relying on German engineers being flown in to Nepal to work on a damaged large-scale generator. Under this system electrical lines are local, minimizing their cost. The can be bought from local vendors and strung up on already existing electrical poles. This means revenue circulates throughout a local area and the community sees a direct economic benefit.

These ideas sprang to mind while I was walking home and saw a sign that proudly stated “load-shedding solutions.” The solutions in this little store included batteries, inverters and so on.

No way. GVP is the solution to Nepal’s load-shedding crisis. My hope is that a Rotary Club or some other humanitarian organization will work with us to help lead the way.

David DuByne is Advisor and Director of Foreign Co-operation with Energy Research Nepal. He can be contacted at David.DuByne@ERN.org.np

Star Power

As fusion power progresses, the Alberta Council of Technologies urges the province to take a leading role in developing the power of the sun This article appears in the August 2009 issue of Oilweek; graphic from here

By Peter McKenzie-Brown
During the Second World War, celebrity physicist Albert Einstein suggested in a now-famous letter to American President Roosevelt that nuclear chain reactions in large masses of uranium could release “vast amounts of power and large quantities of new radium-like elements.” And, he speculated, “Extremely powerful bombs of a new type may thus be constructed.”

While America had only poor-quality uranium, Einstein noted, “There is some good ore in Canada.” The ore used to create the first atomic bombs came from a rich deposit of uranium and radium along the shores of Great Bear Lake, in the Northwest Territories.

During the long days of summer, a wartime mining company hired local Indian men to carry 40-kilo burlap bags of ore from the mine to the Mackenzie River. They carried those loads for long hours, for months on end. When the bags ripped apart, they shifted the spilled ore off the trail, but took the contaminated bags to their temporary village. Years later, the ore-carriers began dying of cancer, and the community now known as Deline became a village of widows.

Canada was thus an important contributor to the first nuclear age, which was born of the fission of radioactive elements. Within a decade, the United States had made tentative steps toward a different kind of nuclear age – one based on nuclear fusion. This system smashes together light atoms like those of hydrogen. As it turns lighter elements into heavier ones, fusion releases vast amounts of energy.

This is the principle behind the hydrogen bomb. It is star power – the fuel that keeps the Sun and the countless other stars alight. As a human invention, its only practical use has been as an unused weapon of violence and terror. Until now.

"[Fusion ignition] is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.”

On March 10, the National Ignition Facility at Lawrence Livermore Labs in California trained 192 high-power lasers onto a point the size of a couple of match-heads. The ensuing reaction generated more than a million joules of energy – enough energy to theoretically light up 10,000 100-watt light bulbs.

The American effort was costly, but its implications were huge. That step suggests the birth of a nuclear age in which virtually limitless amounts of inherently safe and environmentally attractive will be cheaply available.

Compared with carbon or uranium fuels, fusion generates little radiation and no greenhouse gases or air pollution. Since it uses small amounts of fuel, it is likely to have little impact on land and habitat. The day before this extraordinary American achievement, a standing committee of the Alberta Legislature met to consider a proposal by which Canada would become involved in these revolutionary technologies.

Canada would not supply ore, as we do for nuclear fission. After all, the fuels needed for fusion are abundant around the world. Instead, we would help develop technological expertise for the second nuclear age.

Visionaries: The proposal came from a small, minimally-funded and loosely-organized group of visionaries provincially chartered as the Alberta Council of Technologies. Clearly, the goal of the media relations surrounding the meeting with the legislature was maximum public awareness. In this, they certainly succeeded.

The idea is to prove that controlled nuclear fusion can become the world’s energy future. Theoretically, it could provide clean and nearly limitless electrical power for humankind, with everything that implies. It could mean a reversal of global warming and the reversal of policies by which agricultural products are transformed into fuel. According to Dr. Perry Kinkaide, the group’s chairman, his council was asking the province to contribute to a demonstration of fusion ignition.

Fusion ignition, he said, “is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.” When you get into the physics of this “imminent” technology, which talks about creating temperatures so hot (up to 100 million degrees Celsius) that they can only be enclosed by magnetic fields or lasers, it’s like tripping forward through a time-warp. Yet new technologies – demonstrated by the test at the Lawrence Livermore Laboratories – have changed the picture.

Adds Allan Offenberger, a retired University of Alberta engineering professor and another program proponent, it is the new technology of “inertial confinement” of the heat of fusion that is changing everything. Inertial confinement uses laser beams to quickly heat to ignition a “fuel pellet” of simple atoms like the commonplace hydrogen isotope deuterium and the much less stable hydrogen isotope tritium. Because this process rapidly induces fusion, you don’t have to confine the fuel at all. The advantage: a relatively simple reaction chamber design.

Even so, this is a long-term proposition. A demonstration project isn’t likely for 25 years, say, with commercial facilities following a decade after that. However, the promise is great. Once the bugs have been worked out, the fusion energy could be very cheap.

To begin to develop expertise in this area, the proposal suggested that the province pony up $4 million this year and commit to another $17 million, total, in the two fiscal years following. The proponents argued that if Alberta scientists don’t get in on the ground floor, they will fall behind in expertise. Joining the project later, they argue, will be more expensive Once the province got its foot in the door, the proponents call for an intensive program of R&D “to develop inertial fusion as a viable energy technology.”

This phase would cost perhaps $40 million per year. Eventually, according to the council, having expertise within the province could lead to commercialization of the technologies. Perhaps the province could become “a provider of high power lasers, reactor systems engineering and related technologies for fusion energy and other applications.”

According to Offenberger, the aim is to create a safe, relatively cheap and clean method of producing electricity based on fusion. One attraction of this form of energy, he says, is that huge amounts of energy could be created with less than a kilogram a day of two types of hydrogen fuel. Also, there is no chance of meltdowns from this form of nuclear energy, which produces no hazardous wastes. The only waste products are heat and, from the size plant the group visualizes, about a kilo of helium per day.

The proposal also points out that there could be huge savings on transmission costs “because (fusion) plants can be located close to electricity users.” Canada is the only major industrial country without a fusion research presence. Given the country’s energy wealth, proximity to the United States and trade surpluses, perhaps that’s not unreasonable. I put the question to someone with the broadest imaginable view of electricity supply and demand within Alberta.

Technological Dominance: At the time of our interview, Martin Merritt was completing his term as the Alberta government’s Market Surveillance Administrator. His job was to make sure electricity and natural gas markets within the province were free and fair. Although he was quick to say he had no expertise in nuclear fusion, he surmised that “The best place to do this would be in the US, where the problems of energy supply, environmental problems, worries about global warming and the need to remain technologically dominant are so powerful. Europe also has those problems. In that sense, the timing seems perfect” to be developing these technologies.

By contrast, he opined, “Alberta’s main reason (to become involved) is that as an important energy power, we have many reasons to have an oar in developing energy technology.” He added that “Alberta needs to get around the (environmental) brush we’ve been tarred with. Perhaps adopting this form of energy could earn us green credits.”

Perry Kinkaide’s Council of Technologies, however, sees an urgent need for Canadian involvement. In a document on the council’s website, the group argues that “The window of opportunity is closing fast for Alberta and Canada to participate in a global partnership for developing ‘fusion,’ the ideal solution for meeting the world’s primary energy requirements – forever! Participation will secure our position as an energy superpower as the world transitions to fusion, with significant socio-economic and environmental spin-off benefits.” In this compelling commentary, the organization addressed “the need for fusion energy and the prospects of a revolutionary new technology for its achievement.”

Citing significant environmental, health and safety implications, it also noted that “the strategic fit of fusion technology with the demands of North America’s coal-based electric power industry as plants reach end-of-service and require replacement.” What is needed immediately, they insist, is an action plan “to ensure Alberta’s and Canada’s place in the emerging fusion-energy economy.” While the notion of fusion energy is closely tied to the generation of electricity, perhaps it could meet an oilsands challenge which went untried during the optimistic early years of the first nuclear age.

Fifty years ago, Richfield Oil Company proposed an experimental plan to release liquid hydrocarbons from the oilsands through the expedient of an underground nuclear explosion. The company proposed detonating a nine-kiloton explosive device below the oil sands at a site 100 kilometres south of Fort McMurray.

Thermonuclear heat would create a large underground cavern and simultaneously liquefy the oil. The cavern could serve as a collection point for the now-fluid bitumen, enabling the company to produce it. This idea came remarkably close to actually taking place. The project received federal approval in Canada, and America’s Atomic Energy Commission agreed to provide the device. But before the pilot could take place, public pressure for an international ban on nuclear testing had mounted.

As the late Ernest Manning once told me, when he was premier the federal government withheld approval and thus killed the plan. Perhaps in the second nuclear age, energy from nuclear fusion could become a safe and realistic heat source for producing and refining the dense oils Canada is famous for. This idea may sound far-fetched until you consider that in Peace River Shell is already testing the use of electric heaters to refine bitumen carbonates in situ, deep inside underground formations. When you start talking about a second nuclear age, nothing seems impossible.

Keeping Electricity Competitive

Alberta’s Market Surveillance Administrator, Martin Merritt is head of an independent agency developed to ensure that the province’s electric markets operate in a fair, efficient and competitive fashion. The MSA also monitors the retail natural gas market. This article was carried in The Calgary Herald September 12, 2008.

By Martin Merritt A few weeks ago, The Calgary Herald carried an item reporting that Alberta had just set a new summer record for power consumption, eclipsing last summer’s record by 2.3 per cent. The good news is that we had plenty of supply to meet this record. The concern is that as we continue to post records we may not have the transmission to ensure that the lowest cost supplies reach us as consumers.

As a consumer, I get the best deal for myself if I can buy things – cars, groceries, gasoline and other forms of energy – freely on the open market. In a market economy, our choices as consumers give a great incentive for sellers to keep their costs low. If we were constrained to buy from only a few sellers, we would have less choice and prices would likely be higher.

I also wear another hat. As Alberta’s Market Surveillance Administrator – the guy responsible for making sure our electricity market functions competitively – I understand that constrained markets can prevent low-cost sellers from prevailing in the marketplace. In the case of electrical power, we need more than the supply necessary to meet Alberta’s needs. We need a system that allows electricity to flow freely around the province. That requires adequate transmission capacity.

Alberta’s electricity market provides consumers with secure supplies and competitive pricing, but the transmission system is becoming undersized for the job in some places. Whether for home appliances or running business operations, consumers will only get the best deal on power when the transmission system can transport electricity from (almost) any generator in Alberta to (almost) any consumer in Alberta. This is why I am concerned about the tremendous hurdles facing new transmission projects these days.

Electricity generators are like stores, and the transmission system is like the network of roads that enables us to get to and from the supermarket. If major roadways became so congested that we had to buy all of our groceries from the local convenience store we all know what would happen to our family’s food bill.

This isn’t just theory. It’s already affecting us. Today we are moving a lot more electricity through the transmission system than we did when it went through its last major upgrade over 20 years ago. In constrained areas of our grid, this has dramatically pushed up the energy losses from transportation.

For example, between the Lake Wabamun area where about 40% of Alberta’s generation is located and the Calgary area, losses average over 10%. According to the Alberta Electric System Operator, additional transmission capacity would save enough energy to power half the City of Red Deer. Losses on that scale are pure economic and environmental waste. More recently, in the five years from 2002-2007, Albertans paid almost $300 million in subsidies to electricity generators for helping us get around our transmission bottlenecks. The subsidization rate is presently $40-$50 million annually.

Some advocate expanding this practice – paying generators to locate in sub-optimal places in order to avoid investing in transmission infrastructure that the province badly needs. This amounts to renting band-aids rather than fixing the root problem. This band-aid approach might work well for the band-aid vendors but it’s certainly not in the best interest of Albertans if we expect to continue to realize the larger benefits of a broadly competitive electricity market.

In Alberta today, the wholesale electricity market is worth about $5 billion a year, less than 10% of this represents the cost of transmission. The economic challenge of trying to avoid or defer transmission investment beyond what we have already realized is that you put the competitive efficiency of a $5 billion market at risk, in order to chase questionable savings in the 10% piece – penny-wise, but pound-foolish.

Allowing growth in demand to outstrip the capacity of our existing transmission system puts the benefits and perhaps even the reality of a competitive electricity market at risk. Experience in other electricity markets has shown that the practice of subsidizing generators to locate in particular places can have expensive and unintended consequences. Once generation economics start to hinge on capturing subsidies rather than on efficiency and low-cost, the broader benefits of the competitive market become compromised. Consumers expect and need generators to compete with each other on the basis of efficiency and generation cost. Transmission enables this competition to occur. Subsidized generation distorts it. Unless we invest in transmission, Albertans’ bills will continue to reflect the growing cost of rented band-aids, high losses and diminished competition. The longer we take to build the transmission we need, the more rent cheques go down the drain.

In southern Alberta, we have great sites for generating electricity from the wind. Investors are willing to build there, but we have a shortage of transmission. Similarly, northern Alberta is the logical place to locate fossil fuel generators. They are most efficient (both economically and thermodynamically) when they can be located at low altitude, in cooler temperatures and near a substantial supply of water. There too, we have a shortage of transmission. By bringing all electricity supply sources to all consumers across the province, transmission provides us with choice and forces suppliers to compete with each other.

Subsidizing higher cost, less efficient generators to locate in the middle does neither.

These are powerful realities. Some advocates of gas-fired generation in southern Alberta will soon enough be asking for subsidies – for without them their projects are unlikely to be able to compete. About half of Alberta’s residential consumers live in the transmission-constrained southern part of the province, but the case for reinforcing our transmission grid is not an argument for southern consumers alone. All Albertans benefit the most from the most competitive market possible. We must find ways to enable the fair and timely development of critical transmission infrastructure. We need more transmission capacity because that – not subsidized generators – is the best way to assure the competitive market that Albertans have come to expect.

Q&A with Marcel Coutu

Syncrude's Chairman of the Board delves into operations, the environment and the demise of oil around the world. This article appears in the July 2008 issue of Oilsands Review.

By Peter McKenzie-Brown
Canadian Oil Sands Trust owns the biggest single share of Syncrude (37%), and the firm’s CEO is also Syncrude’s chairman. Oilsands Review asked Marcel Coutu about operating and environmental issues at the oil sands giant. His edited comments follow.

OSR: Developing new technology has been part of the business from the beginning. To what extent is that still the case?

MC: The first few years of this business were about survival, because oil prices were low and costs were high. When oil prices were low and margins were thin the driver for this business was always lowering costs. That really hasn’t changed much. Both Syncrude and especially Suncor have been major developers of new technology. Suncor, for example, developed hydro transport – technology that enabled us to move oil sands ore by pipeline rather than truck. So all of a sudden we were operating satellite facilities, without having to truck ore to the processing site. That was a major innovation. The tailings ponds are a major challenge area. It’s an important functioning part of our operations, and enables us to recycle our water. It’s a major challenge. We need to find ways to separate clay from the water more rapidly. This will help us reclaim land better.

OSR: Oilsands inflation has been high in recent years. How has that affected you?

MC: The one inflation component that has dwarfed all the others is the price of natural gas, which has moved up in parallel with the price of oil. We buy eight-tenths of an MCF of natural gas for every barrel of light sweet product we produce. The rest of our costs are increasing by low double-digit to high single-digit numbers, and over the years those costs add up. Fortunately, oil prices have more than offset operating-cost inflation.

OSR: How much energy do you consume for every barrel of oil you produce?

MC: About 1.5 gigajoules (1.5 MCF of natural gas equivalent) per barrel. That’s higher than 0.8 MCF, the number I mentioned earlier; that refers to purchased energy. The total energy we consume in our operations includes energy we generate as a by-product to our upgrading processes. It is largely electrical energy, in which we are more than self-sufficient. We produce a lot of waste gas from our processes, and use that to fire gas turbines. We also have a lot of waste heat from our operations, and we raise steam with that heat and put that steam into steam turbines. This makes our operations more efficient. Beyond that we arbitrage against the price of electrical power around the clock, sometimes selling electricity into the Alberta grid, sometimes buying it, depending on how those conditions align. We arbitrage those markets in both directions. We do the same with natural gas. It’s one of the businesses we do to make ourselves as energy efficient as possible.

OSR: How are you managing carbon dioxide emissions?

MC: We’ve been reducing them from the time we opened the plant gate. Carbon dioxide emissions are all about energy consumption – they are exactly the same thing; reciprocals, if you will. You only create CO2 emissions by burning fuels. We have always been incentivized to keep our energy consumption as low as we can, and lowering consumption means lowering CO2 emissions. We have always been focused on reducing CO2 emissions because they represent a direct cost to us.

OSR: You are a member of ICON, the Integrated CO2 Network. Any thoughts on carbon sequestration?

MC: The plants at Fort McMurray are the largest collectible source of CO2, but it is an expensive proposition. You have three levels of major expenditure there. You could sequester a lot of CO2, but I’ve seen numbers that you are actually generating more CO2 than you are sequestering by going through this process. First you have to construct equipment to extract the CO2, then build a pipeline, then pump the carbon dioxide into the saline aquifers, salt domes, old reservoirs or whatever you use to host the stuff.

OSR: The notion that crude oil supply is about to peak or has peaked is gaining a lot of currency. What do you think?

MC: Natural gas is in vast supply around the world but oil is not. Crude oil production in most of the producing countries in the world is in decline. All OPEC can now do is raise prices by cutting production. They cannot lower prices by increasing production because they don’t have the capacity. We are in a very pure free market situation, with prices being set by supply and demand. When I look at that dynamic, I have stopped worrying about the demand side. No matter how much the US goes into recession, for any period that is important to any of us, any decline in consumption there will be offset by increased demand elsewhere – in China and India, but also in developing countries that produce their own crude oil. Those countries generally subsidize oil products, and subsidies accelerate demand growth. At these prices you are seeing some conservation somewhere, but it is being more than offset by increased demand somewhere else. Whether people are still going to be buying at $200 a barrel I don't know, but by the time we get to $200 it will be the supply side that will keep things tight and moving upward.

OSR: How serious a problem is maintaining global production?

MC: Very. World oil production is generally in decline. You can assume that out of global production of 87 million a day, productivity will come off by 5-10 percent every year, so you have to replace that production each year before you can even begin to satisfy global demand growth. So what we are seeing is the demise of the commodity, since we are never really going to be able to meet the demand. Prices will be volatile, but the trend in my view is that prices will continue to climb. The demand will be fully there regardless of anything that happens to the US economy. The decline is real and cannot be arrested, at least not in the short term. One hundred and fifty dollar oil is within striking distance.

OSR: What is the role of the oil sands in this environment?

MC: Oil sands production is close to a million barrels a day, a little more than 1 per cent of global production. It’s going to take a huge amount of effort, capital and time, maybe ten years, to double Canadian oil sands production. It’s true that the Canadian resource is huge, but accessibility is long and slow. Our impact will be very slow. One thing we need to bear in mind is that the size of our resource goes up with the price of oil; the higher world oil prices grow the greater our resources become. We have re-evaluated Syncrude’s leases, and that re-evaluation has taken us way up from 9 billion barrels, which was our traditional resource base. That’s good for Canada and Alberta and the rest of it.

OSR: How are you dealing with the labour shortages around Fort McMurray?

MC: To answer that, you have to think of labour as being in two buckets. The people in the operational bucket are there for the duration. They have great careers, pension plans and so on. Everyone puts their shoulder to the wheel, and we get the job done. We lose some people, but the situation is manageable. Then there is the contract bucket – construction workers, pipefitters and so on, who are mostly there to work on expansions. They are there on a temporary basis and they are hard to hold onto. They are the challenging part of the work force. The labour problems we face are focused in that area.

OSR: Having waterfowl fly into the tailings pond brought international attention to Syncrude. Do you want to comment on it?

MC: We’ve extended apologies to everybody. It was really a heartbreaking incident for us. Why did it happen? Because we didn’t have our equipment deployed before the ice thawed. It’s something we have been managing for decades with success, but we got caught by the weather. We didn’t have our deterrents in place.

OSR: What are some of the other environmental issues you face?

MC: In general, our environmental story has been glowing. Where we have done a poor job has been in telling the world about it. I’d like to comment in three areas – water, air and land. Let’s start with water. At Syncrude we consume two tenths of 1 percent of the water from the Athabasca River for our operations. We recycle as much as we can. If you extrapolate from that, the whole oil sands industry consumes less than 1% of the Athabasca’s flow. Air is a more serious issue. We reduce our CO2 emissions because it makes economic sense, as I said earlier. But there are nastier things that we have been managing for years and they cost us a lot of money, and the nastiest of them all is sulphur dioxide. Our SO2 emissions peaked at 250 tonnes per day when we were producing around 250,000 barrels a day. In our last expansion we moved from 250,000 barrel per day to 350,000 barrels per day, and we invested about $1 billion in SO2 scrubbing equipment. We not only stopped the growth of SO2 emissions but reduced them slightly from our peak levels. Now we are spending another billion dollars to reduce those emissions to about 150 tonnes per day. On the land side, in March we were the first company in the whole industry to get certification for land reclamation. We have returned that property to the province. It’s really impressive. You would never know there had been a mine there.

The Battery and the Charger

This article originated here.

B.C. and Alberta need each other’s power

By Martin Merritt
About 14 years ago, Alberta began to restructure its electrical system, and it’s been quite a journey to the market-based system we have today. Most people don’t understand what an important role British Columbia’s government-owned system plays in our market. From my perspective as head of the agency charged with making sure Alberta’s electricity markets are fair, efficient and competitive, I see our relationship with B.C. as mutually rewarding.

Alberta’s electricity market includes a host of buyers and sellers. At one end of the spectrum are small consumers like you and me who depend on electricity in our homes; on the other are huge industrial consumers mining the oil sands, operating pipelines and milling forest products.

On the supply side, generators range from wind farms east of Crowsnest Pass to huge coal-fired plants near Edmonton. The diversity of Alberta’s electricity supply has increased substantially. We now have more technology, fuels, locations, ownership, and maintenance diversity than in the past. Our system’s reliability, its cost structure and Alberta’s collective exposure to various risks are well-served by this diversity.

Less known is that Alberta and British Columbia are buyers and sellers of each other’s power. We Albertans buy from B.C. during our peak hours. B.C. buys from Alberta during the night. This arrangement confers tremendous benefits on both provinces.

There’s a misconception among some Albertans that the relationship between Alberta and B.C. is parasitic: we’re the host and they’re the parasite. According to this argument, our western neighbour is pulling a fast one by preying on a weakness in our market design.

The facts do not support those ideas. The power-exchanging relationship between the two provinces is symbiotic, and the symbiosis is based on geography. Alberta has lots of coal and natural gas, while B.C. has big mountains, long valleys and lots of rain. It makes perfect sense that B.C. based its system on hydroelectric power while we constructed one that primarily burns hydrocarbons. Because of these basic realities, over the years the two provinces have evolved a mutually beneficial relationship – somewhat like a battery and a charger.

The power we get from next door perfectly complements our own – and vice-versa. Alberta’s electrical demand varies substantially throughout the day and across the seasons. When we are fixing supper and using our home appliances our demand for power goes up, as it does during heat waves and cold snaps. It tapers off during spring and fall. Like other mechanical devices, generators fail unexpectedly from time to time. If they are wind-powered, their output is quite variable and difficult to predict.

Whether for reasons of temporary high demand, short supply or both, we’re fortunate to be able to buy electricity from our neighbour. Last year B.C. sent us as much as 465 megawatts for brief periods. What we have in B.C. is a standby generator that can provide us with significant amounts of reliable power on short notice.

Could Alberta make do without B.C.’s hydropower? Sure, by over-building generation capacity in the province. It’s worth noting that we don’t just buy power from B.C. because we can’t supply it ourselves. We buy it anytime that they are willing to supply it for less than it costs in Alberta. Every hour of the year Alberta generators have to compete with B.C. for the right to serve Albertans. If we had built a generator of our own just to supply the power that B.C.’s government-owned generators sent us in 2007, it would have run only 742 hours over the course of the year, or just 8 per cent of the time. This would make as much sense as buying an additional family car to avoid the odd cab fare.

Like cars, generators have costs that are largely fixed. Investing over $500 million plus ongoing maintenance in a generator that would run infrequently would be a very poor use of capital in any market. At the end of the day such power would cost far more than the power we buy from B.C.

Mutual self-interest has evolved a smarter way. We sell electricity to British Columbia at night when we have surplus capacity, so they can recharge their hydroelectric reservoirs. We buy electricity from B.C. at suppertime or on cold days or when a larger-than-normal number of our own generators are down for maintenance.

Our neighbour buys electricity from us when we least need it, and provides it to us when we need it most. This enables both provinces to make optimal use of their generating and storage capacity and use assets more efficiently. This keeps power prices lower in both provinces than they would otherwise be.

This arrangement has evolved naturally because of the physical differences between our electrical systems. It depends very little on differences in our market models. Yes, the market models are different. Alberta has developed a system in which markets determine prices and the pace of investment, while B.C. has a regulated, government-owned power system. British Columbians are justifiably proud of their hydroelectric system, although today’s B.C. taxpayers do not appear as keen to invest in publicly funded generation as their parents were. As a result, B.C. has become a net electricity importer. Many Albertans might be surprised to learn that in 2007 we sold much more electricity to B.C. than we bought from them, though overall Alberta too was a slight net importer in 2007.

Despite the vast differences in our market designs and because of large differences in the mix of our generation assets, the electricity systems of Alberta and British Columbia enjoy a unique symbiotic relationship. The big battery next door provides a market for our night-time surplus and a peaking supply for our crunch periods. Combine this with an investment climate that has attracted a steady stream of investor-funded generation projects for the past ten years, and you have a system that has provided reliable, sustainable power to the most robust economy in the country.

Alberta’s Market Surveillance Administrator, Martin Merritt is head of an independent agency developed to ensure that the province’s electric markets operate in a fair, efficient and competitive fashion. The MSA also monitors the retail natural gas market.