Jolting TransAlta's Flagging Performance

Alberta’s power generators boasted fantastic Q2 earnings this past month on the back of extraordinarily high power prices. The average Q2 power price in Alberta was $123/MWh (12.3¢/kWh), compared to ~$65/MWh over the past two years and $40/MWh in Q2 2012. Growing power demand, planned and unplanned generator outages and higher prices for natural gas (an important fuel for Alberta power plants) drove the increase. While it’s unusual to see prices stay so elevated for an entire quarter, price spikes have become more and more common. Outages of increasing frequency from aging coal fired generation and increased wind power capacity have caused wild swings in the price of Alberta power – in 2012 the average monthly power price swung from a low of $29/MWh to more than $110/MWh. (Within 24 hours it is not uncommon for the power price to vary by more than $950/MWh). Price volatility in the Alberta power market is here to stay and is likely to grow. Using the Alberta Electric System Operator’s (AESO) 2012 Annual Market Statistics and BC Hydro’s Integrated Resource Plan we discover that with the right type of power plants, power companies stand to make big profits, even if power prices fall.

INTRO TO ALBERTA POWER

Alberta is the country’s 4^th largest consumer of electricity demanding on average 8,600 MW of generation in 2012. The Alberta power market has grown by 2.5% over the past three years, which represents roughly 200 MW of new demand (on average) each year. Since 2009, the average on-peak power price in Alberta has increased more than $25/MWh to $85/MWh (NOTE: 1 MW run for 1 hour = 1 MWh). Over the same time period, net 1600 MW of generating capacity was added. As Alberta was not blessed with the same large hydroelectric resources as many other Canadian provinces, it has built its power generating capacity on the backs of coal (43% of installed capacity), and natural gas fired generation (40% of installed capacity), with renewables like wind, hydro, and biomass representing 8%, 6% and 3% of installed capacity respectively.

Each type of generation does not provide the same type of support to the Alberta power market. In Alberta, coal serves as the base load generator, meaning that (in theory) it is supposed to generate all the time. Wind power on the other hand, is an intermittent source of power, meaning that it only provides power when the wind is blowing. Within natural gas fired generators there are three types: 1) base load, 2) peaking plants,¹ and 3) cogeneration.² Cogen and base load make up 72% and 16% of total natural gas generation capacity respectively while peaking plants make up the remaining 12%. The last important piece of the Alberta power puzzle is imports (and exports). Alberta imports 44x more electricity than it exports, roughly 86% of which is imported from BC. Alberta has become increasingly reliant on net imports, growing from effectively 0% a decade ago to ~5% of the total electricity supplied into Alberta.

WIND POWER AND MARKET VOLATILITY

The Alberta power market is deregulated – the power price fluctuates with demand. Generators let the Alberta Electric System Operator (AESO) know ahead of time how much power they are willing to provide from each facility at what price. The AESO dispatches power to meet demand by dispatching the lowest priced MWs first. The bid price of the last dispatched generator sets the price for all of the generators producing power. All wind generation is bid into the AESO at $0/MWh and because (as of August 2013) there was almost 1100 MW of wind capacity, how hard the wind blows can have very large effects on the price of power in Alberta. Not helping matters for wind producers and the AESO, most of the wind generation in the province is located in the same region: extreme SW Alberta. Therefore when one wind farm is generating electricity, almost every other wind farm is too. When the wind blows the supply of inexpensive power in Alberta explodes and the price for power can get crushed creating a “wind discount.” Wind power received about half the price average Alberta power price in 2012 because of the “wind discount”.

In addition to the 1100 MW of existing wind generation capacity in the province, there is 2500 MW of proposed wind power to be added by 2017. Though not all of the generation will be built, in a risked case about 1000 MW could be built (about 40% of risked proposed new generation by 2020), doubling the provinces wind capacity and further increasing the variability in the power price.

At the same time as variable wind power capacity is increasing the reliability of Alberta’s aging base-load coal-fired power generation is decreasing.  The weighted average age of Alberta’s coal plants is 28 years; several plants have undergone force majeure events over the past couple of years. In 2011 and 2012, on average, one-quarter of all coal-fired capacity was offline – compared to less than one-sixth in 2008.

Alberta power prices should be depressed in the near-term as the Sundance A coal power plant is returned to service. Starting mid-decade more than 1000 MW of coal power will be retired. While that capacity is likely to be replaced by roughly the same (risked) capacity over the same period, cogen facilities have lower operating capacity factors (% utilization) than coal plants – a net loss of total generation is possible.

IMPORTS

Importantly, like wind power, BC imports are (often) bid into the Alberta power market at $0/MWh but unlike wind power, imports from BC are very reliable and serve as base load power. Imports represent the equivalent of 600 MW of average Alberta coal fired generation. Losing 576 MW of coal fired generation at the end of 2010 caused the difference between the average off peak and on peak power price to jump from a 24-month pre outage average of $36/MWh to $68/MWh.  BC imports play a very important stabilizing role in the Alberta power market, however the BC power market is forecast to tighten significantly by 2017.

British Colombia has built 10,000 MW of large hydroelectric power capacity which provides cheap electricity on demand for its customers. BC however is running out of new large scale hydroelectric locations, the proposed Site C dam (1100 MW) represents one of the last large opportunities in the province. Instead to meet demand, BC Hydro (a crown corporation which acts as the electrical utility for much of the province) has to buy electricity from independent power producers (IPPs). Because of the province’s green energy legislation, the power from IPPs tends to be from run-of-river hydro developments or wind farms – generation that is both expensive and intermittent.

OPPORTUNITY FOR ALBERTA PEAKING PLANTS

Robust economic growth, increasing wind capacity, coal retirements, and a tight BC power market all indicate to a more volatile Alberta power market at the end of the decade. Gas fired peaking plants are the ideal form of generation to take advantage of this environment. Even in the case of lower power prices caused by an overbuild of base load gas fired generators or a drop in gas price, a volatile market will enable peaking power plants to remain profitable. As Alberta switching from primarily coal-fired generation to natural gas, it removes fuel cost as a basis of competition between power plants. If natural gas prices change, it will affect peaking plants and base load generators the same, protecting these assets from adverse changes in the price of natural gas – fuel cost changes will be passed on to the consumer.

Any company with near term coal retirements and little to no existing year-round Alberta peaking like TransAlta would gain more strategic benefit from this move than other generators. TransAlta is one of the largest power companies in Alberta, owning over 6000 MW of generation in the province – roughly two-thirds of which is coal-fired generation. New natural gas peaking plants would adapt TransAlta’s generating portfolio to gain fuller exposure to times of high prices, especially in the winter.³

Currently TransAlta is in a financially constrained position: its share price is down 33% since the beginning of 2012, it’s in the process of spinning out most of its renewable power assets for net proceeds of $200mm to finance its capital program. In addition, TransAlta has entered into an agreement with MidAmerican Energy holdings in which MidAmerican will jointly finance (50/50) all of TransAlta’s future natural gas power plants in Canada (TransAlta received no compensation from the agreement). While these peaking plants would be subject to the partnership, the capital burden on TransAlta would be very manageable, and in a strong price environment would deliver a material pop to earnings.

Any player looking to add peaking plants should prioritize efficiency and location. Sites near load centres with higher local power demand than generating capacity and large quantities of underused transmission capacity are ideal targets.

Increasing structural volatility in the Alberta power market will present large opportunities for generators with the right assets and a tolerance for risk. Peaking plants will benefit from increased wind generation, as well as fuel switching amongst base load generators which makes them more competitive in this market. The Alberta power market, much like the Alberta economy is dynamic and growing. When the Alberta power market tightens and prices rise, investors will be looking for companies that stand to benefit the most. No doubt a strong fleet of peaking assets plus 6000MW of existing generation will put TransAlta atop everyone’s list.