Friday, July 22, 2022

Exploring SaskEnergy's 22.7% Rate Increase and Impacts on Provincial Electrical Power Supply

In my last few energy posts (link 1, link 2) I've written about Saskatchewan's plan to transform our electrical supply away from coal and towards gas and renewables, both from an instantaneous generation (MW) standpoint, and total power delivered (GWh) standpoint. 

Where does the gas come from? What are some of the unique risks associated with gas? How does the Alberta oil & gas industry affect our utility bills? 

To learn more I read through SaskEnergy's 2021-22 (and 20-21) annual reports, located here. All page numbers mentioned below reference the 2021-22 report's numbered pages (not the PDF page numbers) unless otherwise indicated. 

This post will cover:

  • What is SaskEnergy? 
  • Visualizing Saskatchewan's natural gas usage 
  • Factors contributing to the recent 22.7% rate hike

Read on... 

What is SaskEnergy? 

SaskEnergy (Incorporated) is one of seven Crown Corporations owned by Crown Investment Corporation of Saskatchewan, which is the intermediary between the Crown Corps and the Saskatchewan Legislative Assembly. 

From p5

SaskEnergy is responsible for distributing natural gas, e.g. metering it out to homes, businesses, and large industrial customers. SaskEnergy has the "exclusive legislative franchise to distribute natural gas within the province of Saskatchewan." It also has four subsidiaries: TransGas (transmission and storage: the roots, trunk, and big branches, whereas SaskEnergy is the small branches and leaves), Bayhurst (a small gas producer), MIPL (interprovincial/state interconnections), and Call Before You Dig. 

Saskatchewan uses a lot of gas. 

Here are some stats from page 17 of the 2021-22 report with embellishments by yours truly. 

In the 2021-22 reporting year, SaskEnergy sold 6,329,000,000 cubic metres of natural gas. A cube with that volume would have edges 1.85km long. This cube would cover the entire University of Saskatchewan campus and a good chunk of the nearby fields and river, including the whole train bridge. The gas cube would be approximately 1,760 metres taller than Nutrien Tower, the tallest office building in the province (at 88 metres). 

(Photoshop request: Saskatoon skyline with a 2km³ gas cube in the background)

The average residential gas customer in SK used 2,677 cubic metres of natural gas in 2021-22, which is just over the volume of an Olympic swimming pool (2,500 cubic metres). 

Image source

The peak daily flow of gas in Saskatchewan was 1.65 petajoules on January 5, 2022, equivalent to about 44,000,000 cubic metres of gas. If you turned this volume into a perfect cube, it would be about 350 metres on each side, which is about 2.5 Costco stores (North Saskatoon location). 

Why is SaskEnergy is hiking rates by up to 22.7% over the next two years?

A multi-year rate hike was announced a few weeks ago. For many, this is a hard pill to swallow given concurrent SaskPower rate increases (covered in my last post), inflation, and everything else going on in the world. 

To understand the SaskEnergy rate hike - and the future of natural gas in Saskatchewan - we need to dive into a couple areas: 

  1. How Crown Corporations work
  2. Where gas comes from 
  3. Risks to SaskEnergy 

How Crown Corporations Work (at least in Saskatchewan) 

SaskEnergy, like other provincial Crown Corporations, is a subsidiary of Crown Investments Corporation (CIC). CIC is wholly owned by the Province of Saskatchewan: the Crown (province) is the sole shareholder of CIC. 

Wikipedia says, "Some Crown corporations are expected to be profitable organisations, while others are non-commercial and rely entirely on public funds to operate". CIC is expected to be more on the profitable side. On p14 of CIC's 2021-22 Annual Report, they state (emphasis mine): 

CIC is focused on providing a reasonable return to the Province. This priority must be balanced with its public policy initiatives, reinvestment in sustaining infrastructure, and providing high quality public services for the lowest possible cost.

Dividends from Crown Corporations go into the Province of Saskatchewan's General Revenue Fund (GRF). CIC targets a specific rate-of-return that balances costs, public access, and a target rate of return which is set to pay for public programs and reinvest in the Crown Corps for future growth and sustainability. 

As a regulated utility, SaskEnergy is required to "not earn a profit or realize losses on the sale of gas to customers over the long term" (p32, SaskEnergy report). Furthermore, SaskEnergy can only adjust rates when approved by the Saskatchewan Rate Review Panel (SRRP). Rates have been frozen a while due to COVID. 

When natural gas prices go up or down, SaskEnergy can't immediately pass those costs (or savings) on to customers. Differences are captured in what they call the Gas Cost Variance Account or GCVA (p32). They are charged (or refunded) to customers as part of future rate adjustments. 

On March 31, 2021, the GCVA balance was $6 million owing from customers due to increasing commodity costs. One year later on March 31, 2022, now the GVCA balance was $15 million owing from customers, "a result of the AECO [Alberta Energy Company] daily index increasing commodity purchase costs" (p33) or in plainer English, gas being more expensive. 

(I looked back one more year: the 2019-20 report says the GCVA owed customers $13 million)

So, the rate increase is partially to cover this balance in the GVCA, but also to cover expected rising costs (keep reading).

Where does Saskatchewan get natural gas? 

The short answer is: we used to make it here, but now we buy it from Alberta. 

From 1988 through 2009, Saskatchewan was a net exporter of natural gas (see chart below). During this time of plenty, the gas demand curve increased quite gradually. In the mid-2000s, our production started to plummet and in 2009 - the inflection point of being a net exporter vs. a net importer - demand started to skyrocket. The difference between the blue line and the gray blob is the gas we import from Alberta. Today Alberta supplies about 75% of natural gas used in Saskatchewan. 

p30, 2021-22 Report

This increasing demand can be at least partially attributed to new natural gas generating stations coming online in the late 2000s and early 2010s (link), plus major industrial expansions (potash went crazy in the late 2000s and early 2010s; every site in the province expanded and new sites came online), plus other growth factors that are opaque to me. 

Production of natural gas in Saskatchewan is "more than 70% associated" with oil production according to SaskEnergy's 2020-21 report (p27), meaning natural gas is a byproduct of oil refining. SaskEnergy adds, "local [SK] supply [is] highly dependent on the volatile global oil market." In comparison, Alberta has fields which produce natural gas directly (source 1, source 2).

Now, here's a scary idea. Saskatchewan and Alberta are reasonably (but not completely) decoupled and sheltered from global energy markets, but that may change in the very near future (emphasis mine): 

Europe is facing an energy shortfall and increasing natural gas prices. Energy demands there may be met, in part, with increased shipments of liquified natural gas (LNG). Canada is still expected to enter the LNG export market when the LNG Canada export facility near Kitimat, British Columbia opens in several years. A smaller project near Squamish has also made progress with the final investment decision expected later in 2022.

Despite finite LNG export capacity keeping North America somewhat isolated from high global energy prices, growing export capacity and the uncertainty around the duration of Europe’s energy shortfall kept upward pressure on North American prices through the end of the fiscal year. (p30)

The United States are ramping up LNG exports to Europe amid the EU's current energy crisis. 

What this means for SK: the more coupled our energy supply is to the rest of the world, the more volatility Saskatchewan ratepayers will be exposed to, and the higher our energy bills will be. 

A simple way to grasp this is to think about this question: Will Sask natural gas prices go up or down if Alberta gains the ability to sell LNG to thirsty international markets?

An Aside: Humans Are Bad At Predictions 

I wanted to highlight the differences between SaskEnergy's future natural gas price predictions in their 2020-21 annual report... 

p28, 2020-21 report

... and the updated prices and predictions in the 2021-22 report: 

p31, 2021-22 report

The main takeaway of these two charts is that the gas market is volatile enough that a 5-year price forecast jumped by what looks like 70% in just a 12 month period. For more on predictions, read Nassim Taleb. 

Currently, prices are at 10-year highs, according to this Government of Alberta site

Risks to SaskEnergy affecting natural gas prices (and costs to ratepayers) 

These are SaskEnergy-identifed risks (p41) from the 2021-22 report with colour commentary by me:

  1. Government Climate Policy: "the most significant risk facing SaskEnergy." More regulation equals more compliance costs (note that I am not taking a stance, I'm just telling it like it is). Regulations bite SaskEnergy in two ways: direct costs of complying with regulations, and indirect costs of lost revenue due to customers complying with regulations (example: homes and industry reducing their carbon footprint by using less gas). 

    This amplifies risks of aging infrastructure serving a very geographically dilute population: less revenue to maintain the same assets to the reliable service level we currently expect. 

  2. Interest Groups: essentially, NIMBYism. "Customers want a high level of service" - we all want our furnace in winter and our BBQ in summer - "but many do not want the associated infrastructure nearby, or through, their land." 

    "As a fossil fuel provider [...] SaskEnergy faces additional challenges due to growing opposition [...] with respect to the development of further fossil fuel infrastructure." 

    It gets harder every year to build infrastructure in any industry. One above NIMBY: BANANA = Build Absolutely Nothing, Anywhere Near Anyone. 

  3. Public Acceptance: "While the acceptability of natural gas use presently remains high in the local market, there is potential for a shift to occur with either a direct or indirect impact on SaskEnergy."

    Absolutely! If Saskatchewan deployed a fleet of nuclear reactors we could decarbonize our electricity sector and potentially begin transitioning building heating from fossil gas to electric heat. 

  4. Natural Gas Prices: SaskEnergy states "prices can change significantly, and often do over a short period of time," but (in this section) they don't draw a direct link to what we discussed above: declining provincial oil production (hence: less local natural gas production), Saskatchewan's dependency on Alberta gas for heating and power generation, and growing LNG demand globally coupled with Canadian LNG export ambitions that link the Prairies to the global gas market - and its pricing volatility. 

Get to the point already! 

Referring back to my other energy posts: Saskatchewan has committed to increasing Variable Renewable Energy (VRE) sources for electricity and is phasing out coal power plants by 2030. 

While some Manitoba import hydro capacity is planned, coal will largely be replaced with gas by 2030 (the Small Modular Reactor being commissioned "as early as" 2034) and VRE projects will be largely be backed up by more natural gas generation. 

So the formula is: 

+ increasing SK deployment of Variable Renewable Energy sources 
+ increasing SK gas demand for VRE backup and coal replacement
+ decreasing SK local natural gas production
+ increasing regulatory compliance costs 
+ increasing dependency on Alberta gas
+ increasing Canadian exposure/coupling to global gas markets
+ increasing global gas demand (as a so-called transitory fuel)
= higher gas and electricity prices for SK ratepayers (because most of our electricity will come from gas). 

Here's one final thought experiment: think about energy independence. From the late 80s to the late 2000s, Saskatchewan was energy independent. We mined our own coal, refined our own natural gas, built our own dams. Today, we are energy dependent: 75% of the natural gas burned in the province is from Alberta (which generates 40%+ of our electricity), and a growing chunk of hydroelectricity is imported from Manitoba. Which is the more precarious, less stable, more expensive situation? 

Possible solutions/mitigations? 

Contract every possible megawatt of hydro power from Manitoba for as long as feasible, for cost, carbon, and dispatchability. Push the SMR Roadmap forward. Increase diversity and independence in our electrical energy supply: build out a fleet of SMRs where 2 years' worth of super energy-dense fuel can be bought and stockpiled on site (compare to gas which is delivered just-in-time from a pipe at today's market prices). 

As always: open to constructive feedback and corrections! 

Tuesday, July 12, 2022

SaskPower's 2021-22 Annual Report: More Wind, More Coal, Higher Costs, Less Income... Rate Increases

SaskPower released their 2021-22 Annual Report last week. A lot can change in a year! 

Let's explore the data and the new information. All numbers in this post are from the five-year operating and finance statistics (last few pages of the report), and all page numbers reference the 2021-22 report unless otherwise noted. 

Electricity costs to consumers are increasing by 8% over the next year. 

On p9 of the 2021-22 report we learn we're in for two rate increases in the next ~10 months. A 4% increase this September and a 4% increase in April, pending approval by the Saskatchewan Rate Review Panel (SRRP). The decision should be confirmed (or not) this July. 

This is SaskPower's first rate increase since March 2018, so there's a fair argument to be made that we're overdue to pay more. 

But what are the costs driving this rate increase? Read on...

Provincial generating capacity has increased, mostly in wind. 

Golden South, Blue Hill, and Riverhurst Wind Energy Facilities have come online, delivering a combined 385 MW of generation capacity - when the wind is blowing, of course. 

Generating capacity includes SaskPower assets plus Independent Power Producers (IPPs) SaskPower buys power from. 

Due to the ramp-down of Unit #4 at Boundary Dam Power Station this year, 141 MW of dispatchable base-load electricity has been taken offline (p30). 

The result, which you can infer from the chart above, is we have less dispatchable, reliable base-load generating capacity than in the last two years. 

Generating capacity is somewhat misleading when it includes non-dispatchable sources that cannot be called online when needed. 

Generating capacity is growing faster than electricity supplied.

Intuitively, and as SaskPower makes clear in the report, this is due to intermittent renewables. Intalling intermittent sources means we build more dispatchable assets to ensure there is always capacity to meet peak demand (plus an operating reserve).

When the sun shines and the wind blows, we draw on renewable sources and ramp down dispatchable sources. When it's dark and still, we burn gas and coal. 

Question: In a province facing so many parallel challenges (healthcare and education to pick two), is the best use of scarce resources to build out intermittent generation capacity? Or would it be better to install dispatchable, on-demand base load? 

Hydro power was down significantly in 2021-22 due to drought conditions. 

The result was that SaskPower burned more gas, more coal, and imported more power from other jurisdictions to make up the gap. 

One takeaway from this graph is how one bad year can completely reverse a 3-year trend of declining fossil fuel use. Things can change in a positive direction, but quickly reverse when times are dire. 

Look at Germany, bringing coal generation back online in their current energy crisis. Will Saskatchewan even flinch thinking about keeping coal burning past 2030 if we don't have reliable replacement generation in place? 

In 2021-22, SaskPower ran their remaining coal assets harder than they've been run in years. 

When hydro availability dropped this past year, SaskPower ramped up their coal assets and ran them harder than they've been run in years. Peak-adjusted utilization (based on GWh delivered, MW capacity, and annual peak load) was over 100%, which means:

  • Assets were run above capacity, and/or 
  • Decommissioned coal assets were temporarily brought back online, and/or
  • My utilization metric (methodology on my previous post) isn't perfect, because of limited data supplied by the provincial utility

Some call-outs when reading this graph: 

  1. We might be able to ignore solar's abysmal 3.4% utilization in 2021-22, on the basis of it being the first year with any data. In my last post, the City of Saskatoon hinted at utilization of solar PV at ~26% (in reality, would be lower - search "solar capacity factor"). Utilization at one tenth of that is awful. 

  2. Does adding new wind capacity in 2021-22 also skew the reporting? Despite increasing wind generation capacity by 260% year-over-year, SaskPower reports electricity supplied by wind increased by just 180%. The 40% utilization this past year is within historical error bars, and could be due to curtailment, production being out of phase with demand, or just a calmer year.

  3. We have to demand better, more granular data from SaskPower so we don't have to have all these call-outs. (write your MLA, let's get more transparent data!)

SaskPower's Net Income fell through the floor. 

SaskPower's Net Income this past reporting year was just $11 million dollars, down from $160M last year. 

These "modest earnings" were "anticipated" (p9) due to "defer[ring] increasing customer electricity rates in the face of rising cost pressure due to capital spending and higher fuel and purchased power expense." 


  • Is the "rising cost pressure due to capital spending" due to the "major built-out of intermittent renewable energy," (p15) which are material-dense and energy-dilute? In other words, is the graph above a spurious correlation, or an indication we're accelerating spending capital on projects with poor economic value? 

  • Does "higher fuel purchased power expense" include the costs of renewables? Or, are private Independent Power Providers?

    SaskPower deleted a table that was on p4 of the 2020-21 report that broke out PPA (Power Purchase Agreement) capacity vs. SaskPower-owned capacity. The impact is we cannot calculate IPP-delivered energy vs. SaskPower-delivered energy (although, here is a fun fact: over 98% of wind assets in SK are IPP-owned) and related costs. 

    However, we can look at costs aggregated by fuel source: read on. 

We have decent data on fuel and purchased power costs by source. We're missing capital and operating costs.

Using data on p80 of the 2021-22 report (and a similar table from the previous years' report), we can visualize the cost category "Fuel and Purchased Power". SaskPower says these costs include:

the fuel charges associated with the electricity generated from SaskPower-owned facilities, costs associated with power purchase agreements (PPAs), as well as electricity imported from markets outside Saskatchewan. This electricity is used to serve our company’s Saskatchewan customers, with surplus electricity being sold to markets outside the province when favourable conditions exist (p34)

Looking at the last two years, we can visualize the significant increase we spend in this category, and it's not all carbon tax: 

Gas is up, coal is up, wind is up (although its footprint doubled year-over-year), and imports are up. 

The above chart shows total fuel and purchased costs per year in millions of dollars. 

When the costs are normalized to the total amount of electricity generated by each source, a different story is told: 

Just for fun, here's the same dataset inverted to visualize how the amount of electricity we can generate for every million dollars of fuel and purchased power spend. 

The takeaway is it's terrifically expensive per unit of energy to purchase imported energy, buy from small IPPs, and buy from solar providers. 

(not that we shouldn't do any of these things. An example: the City of Saskatoon's landfill gas plant is a small IPP that valuably combusts waste gasses that are worse for the atmosphere than CO2, and is trending towards breaking even on its electricity sold back to the City) 

Caveats to this analysis:

  1. Fuel and Purchased Power does not factor in Operating, Maintenance, and Administration costs (which are another $700M, and are not broken out by generating source or plant). Where can we get this data? 

  2. Fuel and Purchased Power does not include any capital expended by SaskPower to build generating assets. Where can we get this data? 

  3. Numbers may be misleading for just 12 MW of solar capacity in the province in 2021-22. We will have to monitor this closely. 
I would love better data on capital and operating costs to understand what it costs to build, operate, and generate reliable electricity in this province. 

The question for the future is: What will Saskatchewan replace our cheap, dispatchable, stable, dirty, bad, base-load coal with? What happens to total fuel costs (and costs per kWh) when coal is off the table? If the solution is "more wind," what dispatchable source do we build up in parallel? How much more cheap hydro do we have access to? Do wind and gas costs rise or fall when they're more coupled  and interdependent in the future? 

What does the future hold for Saskatchewan and what does it mean for our utility bills - and the climate? 

Here are some more tidbits from the 2021-22 report and questions I'd like to learn more about: 

  • More gas incoming: Great Plains (Gas) Power Station will deliver 377 MW of generation capacity in 2024 (p45)

  • A 100 MW solar facility is planned for the Estevan area (p14 - no date given), built for SaskPower by a private sector partner. Three more 10 MW installations are planned (by IPPs) between 2022 and 2024 (p45)

  • Another 200 MW of wind is coming online in 2024: Bekevar Wind Energy Facility. 

  • 190 MW of additional hydro capacity from Manitoba should be online by 2024 (p45)

  • The Audit & Finance Committee notes mention SaskPower's "10-year generation supply plan" (p106). Where is this plan? Should it be publicly available? I've emailed SaskPower to ask for a copy. 

  • What are the dependencies and relationships between SaskEnergy and SaskPower? Topical this week was a proposed 17% customer rate hike over the next year and a bit. I have started reading and hope to have a post up in the next month. 

  • SaskPower is assessing the feasibility of a 300 MW Small Modular Reactor (SMR) for commissioning "as early as" 2034. 
    • Why not earlier? 
    • Why only 300 MW when there's 1200 MW of coal to be retired by 2030? 

I have another post in the works where I will start exploring possible answers to the question of what happens when coal goes away in this province. 

I'll give you a hint: think of an energy source that generates a zero-carbon, stable base load with a fuel can be stockpiled on a small generation site for years in advance. 

As always: open to constructive feedback and corrections! 
Data and calculations.