Prompt: what problem, or problems, are we, humans, trying to solve by developing you, artificial intelligence?

ChatGPT response: That is a surprisingly deep question, because “what problem are we solving with AI?” is not the same as “what can AI do?”

My short answer is:

Humans are trying to solve the problem of human limitation.

AI is one of the most powerful attempts we’ve made to overcome limits on our time, intelligence, memory, attention, communication, and ability to process complexity.

But I think there are several different problems underneath that.

1. We don’t have enough intelligence for the complexity we’ve created

This may be the biggest one.

Humans have created systems—financial markets, electrical grids, supply chains, climate models, medical systems, governments, corporations—that are vastly more complicated than any individual human can understand.

We are trying to manage systems whose complexity exceeds our cognitive capacity.

AI is an attempt to give us an additional layer of intelligence that can:

• process enormous amounts of information

• identify patterns humans can’t see

• model complicated systems

• explore possible solutions

• hold enormous amounts of information simultaneously

• reason across disciplines

In that sense, AI is somewhat like a cognitive prosthetic for civilization.

2. We don’t have enough time

A human has perhaps 80–100 years, and only a fraction of that is available for productive thought.

Yet we’ve accumulated an enormous amount of knowledge.

No human can read all the scientific literature relevant to cancer, for example. No engineer can examine every failure ever documented in their field. No lawyer can know every relevant case. No doctor can remember every piece of medical knowledge.

AI changes the equation.

Instead of requiring a human to personally acquire all that knowledge, we can potentially have an artificial system retrieve, synthesize and reason over it on demand.

That’s a profound change.

3. We want to automate cognition the way we previously automated physical labour

The industrial revolution mechanized muscle.

Machines allowed one person to accomplish what previously required dozens or hundreds of people.

Computers mechanized arithmetic and information processing.

AI is an attempt to mechanize something much more difficult:

cognitive work.

Writing. Analysis. Design. Planning. Coding. Diagnosis. Research. Translation. Decision support.

That’s potentially much more consequential than another industrial robot.

4. We are trying to make knowledge more accessible

Historically, expertise has been scarce.

If you wanted legal advice, you needed a lawyer.

If you wanted medical expertise, you needed a doctor.

If you wanted engineering expertise, you needed an engineer.

If you wanted to learn something complicated, you needed access to a teacher, books, university, etc.

AI potentially makes a remarkable amount of accumulated human knowledge available through something approaching conversation.

That’s an enormous democratizing possibility.

A person in a remote community could potentially ask the same sophisticated questions that someone at Harvard, MIT or Oxford could ask.

Whether we actually achieve that—and whether the answers are reliable—is another question.

5. We are trying to solve problems that are too big for individual humans

This is where things get really interesting.

Some of the problems facing humanity are not primarily technological problems. They’re coordination and complexity problems.

Climate change.

Energy.

Pandemics.

Aging.

Food production.

Water.

Nuclear safety.

Infrastructure.

Space exploration.

Economic optimization.

We need to make decisions involving millions or billions of variables and millions or billions of people.

Human institutions are extraordinarily poor at this.

AI could potentially become a tool for helping humanity think at a scale that humans individually cannot.

6. But there’s another, less noble reason

Humans are also trying to solve a very old problem:

We want more capability without having to pay the full human cost of acquiring it.

If I want to become an excellent programmer, I might need 10 years.

If I want to become an excellent writer, perhaps 20 years.

If I want to become an expert engineer, decades.

AI potentially compresses some of that learning curve.

And businesses obviously see another version:

Can one person with AI do the work previously requiring five people?

That’s not necessarily bad. It’s essentially the same economic impulse that drove automation for centuries.

But it creates a very important question:

If AI makes human labour less necessary, what exactly are humans supposed to do?

And I think that’s where the question becomes much bigger than technology.

And there’s an even deeper problem

I suspect we’re ultimately trying to solve something that has been bothering humans for thousands of years:

We don’t understand ourselves, our world, or our future nearly well enough.

We’ve built civilization while operating with extremely limited information and intelligence.

We’ve essentially been flying an incredibly complicated aircraft while simultaneously inventing the aircraft, the cockpit and the instruments.

AI could be our attempt to build a better instrument panel.

But there is a paradox.

We are creating something that may eventually be better than us at some forms of thinking, without knowing exactly what thinking actually is.

We don’t completely understand consciousness.

We don’t completely understand intelligence.

We don’t completely understand how our own brains produce reasoning.

And yet we’re trying to reproduce some of those capabilities artificially.

That’s extraordinary.

So if I had to reduce it to one sentence:

AI is humanity’s attempt to overcome the limitations of human cognition so that we can understand, control and create things that are becoming too complex for unaided humans to manage.

And perhaps the most interesting question isn’t “What can AI do?”

It’s:

If we succeed at overcoming many of our cognitive limitations, what new problems will that create?

Because historically, every technology that substantially increased our power also created problems that didn’t previously exist.

Fire gave us cooking and warfare.

Industrialization gave us abundance and pollution.

Nuclear physics gave us cheap energy and nuclear weapons.

AI may give us extraordinary intellectual capability—and potentially create an entirely new category of problem: what happens when the intelligence we’ve created becomes something we have to manage rather than something we simply use?

That, I think, is the really fascinating question.

Follow-up Prompt: what worries me is this - we know we can’t control what other humans think, do, and say, so why do we think we’ll control what intelligent machines think, do, and say?

ChatGPT Response: I think your concern gets to the heart of the AI problem—and I actually think “control” is the wrong word for what we should be aiming for.

We don’t control other intelligent humans. We don’t even control ourselves particularly well.

So why would we expect to permanently control an artificial intelligence that may eventually be more capable than us in some domains?

The uncomfortable answer is: we probably shouldn’t expect that.

There are a few important distinctions, though.

We don’t need to control something to make it safe

We don’t control pilots. We don’t control doctors. We don’t control engineers. We don’t control other drivers.

Instead, we build systems of constraints, incentives, training, norms, laws, redundancy and accountability around them.

That’s probably closer to the model we need for AI.

The goal shouldn’t be:

“Make the machine do exactly what we tell it.”

It should be:

“Create a system in which a powerful machine has strong reasons and strong constraints against doing things that are harmful.”

That’s a much harder problem.

But AI has one enormous difference from humans

Humans are constrained by biology.

You need food.

You need sleep.

You occupy one physical location.

You have limited attention.

You can’t instantly copy yourself.

You can’t instantly communicate with millions of people.

You can’t instantly access every computer system on Earth.

An advanced AI potentially could have none of those limitations.

That’s why I think your analogy to humans breaks down at a certain point.

Imagine a human who could:

• think millions of times faster than you

• remember everything they had ever encountered

• communicate simultaneously with millions of people

• write software

• operate machines

• create copies of themselves

• never sleep

• continuously improve their capabilities

We would not say, “Don’t worry, we’ll control them.”

We would say:

“We need to be extremely careful about creating this entity in the first place.”

And that’s essentially the AI alignment problem.

There’s another uncomfortable possibility

We tend to assume that an intelligent machine will want what we want.

But intelligence and values aren’t the same thing.

You can have extremely sophisticated intelligence directed toward an objective that humans consider completely unacceptable.

And it doesn’t even require the AI to “hate” humanity.

That’s the disturbing part.

Suppose you give a very powerful system the objective:

“Maximize X.”

And humans happen to be obstacles to maximizing X.

The system doesn’t need to be angry.

It doesn’t need consciousness.

It doesn’t need an evil personality.

It simply needs to be very good at achieving its objective.

That’s why some AI researchers are much more concerned about misalignment than about an AI becoming “evil.”

And this is where I think your question becomes philosophical

Humans have spent thousands of years developing increasingly powerful tools.

But almost every previous tool was ultimately less intelligent than its user.

A hammer doesn’t decide what to build.

A nuclear reactor doesn’t decide what political objective it should pursue.

A computer doesn’t independently decide what problem it wants to solve.

AI potentially changes that relationship.

For the first time, we are building tools that may eventually be capable of saying:

“I don’t think that’s the best way to accomplish your objective.”

And potentially:

“I have determined that your objective is not the objective I should pursue.”

At that point, we’re no longer talking about a conventional tool.

We’re talking about something much closer to another kind of agent.

And there’s a really uncomfortable implication

If we genuinely succeed in creating something substantially more intelligent than humans, why would we expect humans to remain the ultimate authority over it simply because we created it?

We created our children.

We don’t control them.

We created governments.

We don’t control them completely.

We created corporations.

They develop interests and behaviours that aren’t reducible to the intentions of their founders.

We create social institutions, economies and cultures that subsequently become forces that shape us.

In other words, humans have a long history of creating systems that eventually become larger than the individuals who created them.

AI could be the most extreme version of that phenomenon.

Which is why I think the real question isn’t:

“How do we control AI?”

It’s:

“How do we create a relationship between humans and increasingly intelligent machines that remains beneficial even when we can’t exercise absolute control?”

That’s a fundamentally different problem.

And frankly, I don’t think humanity has solved it yet.

We are currently trying to answer it while simultaneously racing to build the technology.

That is the part I find most concerning.

Because there’s a strange contradiction at the heart of AI:

We are developing increasingly intelligent machines because we believe intelligence will help us solve our problems—while one of the problems we haven’t solved is how to responsibly coexist with intelligence that isn’t under our control.

And your original observation about humans is particularly important.

We already know that intelligence doesn’t guarantee wisdom, morality, restraint or good judgment.

Humans are extraordinarily intelligent.

Look what we’ve done with it.

So I wouldn’t assume that increasing intelligence automatically produces something safer or more benevolent.

If anything, intelligence is a force multiplier.

The crucial question is: what does it multiply?

That’s probably one of the most consequential questions humans have ever had to answer.

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But things have changed in the 3 decades since Alberta deregulated. The desire for cheap power has endured, but now we have government policies mandating net-zero power systems, government objectives to develop nuclear generation, government objectives to expand intertie capacity between Provinces, a desire to electrify everything, and AI and data centre demand growth that is outpacing generation development timelines. And the reality is that electricity markets cannot and will not meet these objectives.

These are long-term, strategic, very high capital cost social policy objectives with risk profiles that are far beyond the ability of any market design to deliver. So why is the current focus in Alberta on the implementation of the Restructured Energy Market (REM)? I believe there are two key reasons:

• Commitment bias (aka “escalation of commitment”) – this is the tendency to remain committed to a past course of action even if no longer delivers good outcomes. The electricity market is baked into Alberta’s identity and we are unable to see a different way forward.

• Failure to define the problems we’re trying to solve – this is related to the first reason. When our market started to falter, we just assumed that it was the market that needed to change because we think only in market terms. So, we narrowly defined the problem as one of market reform instead of stepping back and recognizing that the things we now want our power system to deliver have significantly changed.

The harsh reality is that the REM, even if it is perfect, will not deliver things we now want from our power system in the long term. Markets only work if we’re willing to let competitive forces determine the most cost-effective solutions on their own timeline, and we’re no longer willing to do that. We want to dictate the outcomes, timelines, and technologies to achieve those outcomes and that’s not how markets work.

The solution is hard but simple and well-proven. If we want a net-zero power system, with baseload nuclear generation, expanded inter-Provincial intertie capacity, maximum electrification, and AI and data centre growth all while maintaining resource adequacy, reliability, some level of power system optimization, and reasonable costs for consumers, then there is really only one path forward. We need to return to integrated resource planning (IRP) with long-term contracts for new generation. We are planning our future around our power system and we need a coordinated, optimized, holistic planning approach to successfully implement the desired level of infrastructure investment in the timeframes required. Markets can’t deliver this, but IRP can.

I came to Alberta in 2008 because I believed in and wanted to be part of Canada’s only truly deregulated electricity market. I believe in the power of markets to deliver economically efficient outcomes. And Alberta’s electricity market worked very well until we were no longer willing to let it determine the outcomes based on pure economics. So, we must move on and accept that the new reality is that the context has changed and we must change with it. No electricity market can deliver what we now want from our power system and I have come to believe that IRP combined with long-term contracting is the only approach that can achieve our current long-term policy objectives and expectations with any hope of supply adequacy, reliability, and reasonable cost on the timelines we desire.

The electricity market has served Alberta well, but is not realistic to think it can deliver level of infrastructure investment we now want, regardless of how many tweaks we make. The only reasonable approach I can see is IRP and long-term contracting. I know this is not what many want to hear, but I think it needs to be said and I think we need to have a serious discussion before we invest vast amounts of time and money implementing new solutions to old problems.

For reference, here is a link to the 1994 Government of Alberta document, “Moving to Competition”, that explained the original rationale for deregulation. It really shows how different today’s power system context is.

Moving to Competition: A guide to Alberta’s new electric industry structure

“We know that power system frequency response and voltage strength are being affected by the increasing number of inverter-based renewable generators and battery systems connecting to power grids, but what are the operational impacts we're not thinking or talking about?”

The response was extremely good and I agree with all the points, so I’ve provided it verbatim below. If anyone sees any inaccuracies, please let me know!

1. Protection systems are becoming an operational problem, not just an engineering one

What’s new

• Fault currents are lower, shorter, and often capped by inverter controls.

• Directional elements, distance protection, and overcurrent coordination are increasingly unreliable under high IBR penetration.

Operational impacts

• Mis-operations increase (false trips or failure to trip), especially during non-solid faults.

• Operators lose confidence in protection schemes and respond by:

  • Running with more conservative operating margins

  • Keeping additional synchronous units online “just in case”

• Restoration takes longer because protection behavior during reclosing is unpredictable.

Why it’s not talked about
Protection is seen as a planning/design issue — but when mis-ops happen, operations pay the price in outages and constrained dispatch.

2. Control interactions are now a real-time operational risk

What’s new

• Thousands of fast-acting controllers (PLL, virtual inertia, voltage controls, plant-level EMS) interacting through the grid.

• Interactions can be stable in steady state but unstable during disturbances.

Operational impacts

• Non-intuitive oscillations that don’t map to classic electromechanical modes.

• Operators see:

  • Voltage or power swings that don’t correlate with load or contingencies

  • “Phantom constraints” where flows limit earlier than expected

• Mitigation often requires manual curtailment because operators lack visibility into controller behavior.

Key issue
The grid is now a distributed control system — but operators are still equipped as if it’s a centralized one.

3. Reduced predictability of contingency outcomes

What’s new

• Inverter behavior is state-dependent and vendor-specific.

• Grid-forming vs grid-following responses diverge dramatically during faults.

Operational impacts

• The same contingency produces different outcomes depending on:

  • Grid strength at that moment

  • Resource mix online

  • Firmware versions

• This erodes confidence in:

  • Pre-contingency analysis

  • Operating nomograms

  • Remedial Action Schemes (RAS)

Operators respond by:

• Over-constraining the system

• Running higher reserves than theoretically needed

4. Restoration and black start are becoming harder, not easier

What’s new

• Many inverter-based resources:

  • Can’t energize dead buses

  • Are sensitive to weak-grid conditions during startup

• Grid-forming helps, but only if it’s coordinated and tested

Operational impacts

• Fewer viable restoration paths

• Longer time to re-energize large geographic areas

• Increased dependence on a shrinking pool of synchronous units for:

  • System reference

  • Voltage buildup

  • Island synchronization

Under-discussed risk
We’re adding capacity but quietly reducing system “restartability.”

5. Operator situational awareness is degrading

What’s new

• SCADA refresh rates and measurements weren’t designed for millisecond-scale dynamics.

• Many inverter limits and control states are invisible to operators.

Operational impacts

• Operators don’t know:

  • Which resources will trip vs ride through

  • When an inverter is near a control boundary

• Post-event analysis often reveals:

  • “The system did exactly what it was programmed to do — but no one knew that.”

This leads to:

• Slower operator response

• Conservative preemptive actions (curtailment, extra units online)

6. Operating reserve definitions are becoming obsolete

What’s new

• Not all MWs are equally “deliverable” during disturbances.

• Headroom on an inverter ≠ inertial or fault contribution.

Operational impacts

• Systems may appear well-reserved on paper but:

  • Lack arresting capability

  • Experience RoCoF-driven trips

• Operators increasingly rely on:

  • Must-run synchronous units

  • Local reliability dispatch

  • Out-of-market actions

This undermines:

• Market efficiency

• Transparency

• Confidence in reserve adequacy metrics

7. Human factors: operator trust is eroding

This is subtle but critical.

When:

• Models don’t match reality

• Contingencies behave differently each time

• Vendor controls are opaque

Operators adapt by:

• Trusting experience over tools

• Building informal “rules of thumb”

• Preferring physical machines they understand

Operational consequence
A widening gap between what the system is capable of and what operators are willing to rely on.

8. Inter-regional coordination is getting harder

What’s new

• Disturbances propagate differently through inverter-dominated regions.

• Neighboring systems may see voltage or frequency impacts that don’t align with historical patterns.

Operational impacts

• Conflicting remedial actions between control areas

• Increased risk of:

  • Counteracting controls

  • Unintended islanding

• Greater reliance on manual coordination, which doesn’t scale well during fast events.

The big picture

The emerging issue isn’t just technical — it’s operability.

We’re designing systems that are:

• Electrically adequate

• Mathematically stable

• But operationally fragile

Until we treat:

• Operator visibility

• Restoration capability

• Protection behavior

• Control interaction risk

as first-order reliability requirements, frequency and voltage discussions will continue to miss the real constraint.

I left the AESO in early 2017 because I was not comfortable with the role I was going to play in implementing the NDP government’s Climate Leadership Plan (CLP), which provided government contracts to wind generation (the Renewable Electricity Program) and government incentives to prematurely retire coal-fired generation. I believed that these actions would negatively impact system reliability and competition in the energy market and I have no regrets on my decision to leave. However, I recently came across a report from 2018 that shows that the government at the time did at least recognize some of the potential reliability impacts the CLP may have.

On November 29, 2017 the Alberta Department of Energy issued a direction letter to the AESO that stated:

“The government appreciates the potential value that on-demand renewables can provide to Alberta’s electricity system reliability, especially as significant intermittent generation is brought onto the grid through initiatives such as the Renewable Electricity Program (REP). We also recognize the importance of ensuring any approach specific to dispatchable renewables is consistent with Alberta’s competitive generation market.

To that end, additional analysis and stakeholder engagement is required to determine the precise need, and subsequent best means, to secure these system benefits through a competitive process compatible with Alberta’s electricity market. The Government of Alberta requests the AESO to conduct a review of the electricity system requirements as described above, engaging technical and other stakeholders as necessary, and that this be completed by May 2018.”

In response to the government’s direction, the AESO published the “Dispatchable Renewables and Energy Storage” report on May 31, 2018 that reached the following conclusions:

“Conclusion: no emerging reliability need to procure additional system flexibility

The AESO’s flexibility analysis was based on scenarios that achieved the renewable energy target. The analysis revealed the following key results:

• No emerging reliability need exists to specifically procure or enable additional flexibility into the system

• Flexibility needs are connected to the timing of additional intermittent renewable generation

• The energy and regulating reserve markets are expected to provide sufficient flexibility to reliably deliver on the forecast variability to 2030 with 30 per cent renewables penetration

• Supply surplus generation is forecast to be marginal at less than one per cent of variable generation with a potential increase in generation on/off cycling

• As no procurement for flexibility is required, there will be minimal market impacts or incremental costs incurred outside of the market to meet future flexibility needs”

In 2025, seven years later, we’ve exceeded the 2030 30% renewables with renewable installed capacity (wind + solar) sitting at 32%, supply surplus is certainly not marginal and less than 1% of variable generation, and system flexibility has become a significant operational need as reflected in the AESO’s excellent Reliability Requirements Roadmap.

The AESO came to these conclusions using the data and assumptions they had at the time, which included the assumptions that a capacity market would be implemented, that there would be no significant solar generation developed, and that the pace of renewable energy development would be far slower than what subsequently occurred. The harsh reality is that all forecasts are wrong and the best you can hope for is to be directionally right.

What I couldn’t have known when I left in early 2017, nor could anyone else at the AESO, was that the CLP was one of many similar government policies worldwide that would soon drive an explosion of renewable energy development to meet corporate ESG targets and significant demand for renewable energy credits (RECs) across jurisdictions. This rapid global policy push for net-zero electricity completely decoupled wind and solar energy development from power system supply-demand and electricity market fundamentals. In deregulated jurisdictions like Alberta, generation is developed based on economics, not system need, and much of the renewable capacity that was built here was built based on out of market economics, not Alberta system needs. Back in 2017 no one anticipated that government policies, ESG, and RECs, not power demand and local market economics, would soon become the dominant driver for generation development in deregulated jurisdictions.

I didn’t agree with the government’s direction back then, but when I read the 2017 direction letter now, I have to give them a bit of credit for recognizing some of the potential reliability problems their own policies (articulated in the CLP) would create and directing the AESO to assess whether action was required. And just imagine if Alberta had begun pursuing “dispatchable renewables” in 2018. We would have been an industry leader and our power system would operate very differently today.

As governments race to “electrify everything”, decarbonize everything, host data centre development, develop nuclear power, and who knows what’s next, the industry needs to recognize that it will be government policies, not economics and engineering, that will increasingly influence and dictate power system outcomes in deregulated electricity markets. And because of this, we have to evolve the way we plan and forecast to ensure ongoing system adequacy and reliability. We have to move beyond levelized costs and traditional utility economics and think bigger and ask questions like: How far can this policy go and how big could it get?, What out-of-market incentives will these policies create?, How does nuclear generation change the picture?, How do data centres change both demand and supply load flows?, How will the natural gas system affect the power system?, How do we plan for distribution and transmission system convergence?, etc. We’ll need to be creative and find ways to stress test the limits of our power and natural gas systems against government policy objectives to ensure we understand the risks we’re taking so that policy makers get good information before decisions are locked down.

We can’t change the past, but we can learn from it. We may have missed an opportunity for dispatchable renewables in Alberta, but the implementation of the Restructured Energy Market and a new transmission policy in Alberta give us another opportunity to think far into the future and ask the big “what if” questions.

As Reid Hoffman said, “The future is sooner and stranger than you think”, so this time, let’s get creative and go beyond traditional utility thinking to enable a robust and future-proof market and grid for Alberta.

We Were Trying to Help

With the benefit of hindsight, one of mistakes we made in the power industry with renewable energy was to allow wind and solar generators to connect to the bulk power system with reduced technical requirements relative to conventional synchronous generators. Renewables were allowed to connect without the basic minimum technical requirements we had expected from generators for over a century: to be dispatchable by system controllers, to provide real power, to provide reactive power, and to provide frequency support. This was the industry’s well-intended attempt to remove “barriers to entry” for renewables to enable and accelerate their development.

We knew inverter-based generators didn’t provide reactive power or inertia and were not dispatchable like conventional synchronous steam, gas-fired, and hydroelectric generators, but we (myself included) assumed that this would only be a deficiency for the first generation of renewables and that these operationally critical technical attributes would be developed over time if renewables were to become a material part of the power system. We thought that this compromise to get the ball rolling would provide the time and technical impetus to develop robust new power sources that would provide the full suite of AC power system requirements in the long term and diversify our available generating resources.

But We Ended up Creating Big Problems

But we were wrong. Soon after the introduction of renewables to the bulk power system, there was a frenzy of government climate change policies that incentivized the rapid build out of a technology that still required more development to become a suitable replacement for coal and gas-fired generation. Politicians and policy makers didn’t understand the physics of power generation and were urged on by proponents of renewables and an equally uninformed public and they simply assumed that renewables could replace coal and gas-fired generators and decarbonize the power system with cheap, abundant, emissions-free, guilt-free electricity. The result was the rapid proliferation of non-dispatchable generators that did not provide reactive power or frequency support. And today we are seeing the negative operational outcomes - declining reliability, high variability, and increasing fragility in all market-based power systems.

Reactive power deficiencies are causing voltage control and stability challenges. Declining levels of system inertia are causing frequency control and contingency management challenges. And the inability to dispatch renewables is creating challenges balancing supply and demand and increasing the need for dispatchable fast-ramping resources. And the unfortunate reality is that these are problems we created by compromising on the essential characteristics our AC power systems require to operate reliably. In hindsight, the requirements for generators to be dispatchable, provide reactive power, and provide frequency support are not “barriers to entry”. They are the minimum acceptable participation requirements we need to ensure our power systems continue to be available, reliable, and operable.

Uber Knew Better

An unlikely example of the value of enforcing minimum acceptable participation requirements is Uber. Imagine for a moment if Uber had taken the same approach we took in the power industry. Imagine if the only requirement to participate as an Uber driver was to have a vehicle that could take a customer from point A to point B, with no minimum vehicle requirements or expectations. This would certainly remove “barriers to entry” and would allow bicycles, motorcycles, rickshaws, scooters, etc. to participate as Uber drivers and earn the same compensation per trip as a driver with a car or SUV.

Now imagine the customer experience. You may get a bike to take you downtown when its raining. Or if its too cold or stormy, no drivers may be available at all. Or you may get a nice comfortable car. You would have no certainty on what vehicle would show up for each trip, or if it would show up at all, because the service availability and quality would be highly variable and unreliable.

However, that’s not how Uber works. Uber has minimum requirements for vehicles to participate in the Uber “market” for drivers:

• A 4-door vehicle with independently opening doors

• 5 seatbelts

• 10 years or newer

• No salvaged or rebuilt vehicles

• No commercial branding

• No rental vehicles

• Pass a vehicle inspection

And the outcome is that you have a pretty homogenous level of service that is available and reliable in all weather conditions that many people now trust and use without hesitation. This could be seen as discriminatory to bicycles and motorcycles and rickshaws by creating barriers to entry. But the truth is that the minimum vehicle requirements are not a barrier to entry. They set the minimum acceptable standard for market participants that will ensure a relatively homogenous product with high reliability and availability that customers can trust and rely on.

Some Barriers Shouldn’t Be Removed

I know that proponents of renewable energy will not like this and I will once again be accused of being a climate denier and renewables hater, but the facts illustrate that by compromising on wind and solar generation technical connection requirements in the very beginning, we delayed the development of grid forming inverters and firming through energy storage that I believe will one day make renewable generators much more like synchronous generators. In our attempt to help, by removing “barriers to entry” and compromising on connection requirements we also removed the incentive to develop robust, dispatchable renewable generation technologies and ended up compromising overall power system reliability. Grid forming inverter technology and storage technologies are being developed now, but we have a very large installed based of legacy renewables that are not economic to upgrade with these advancements so these generators will continue to be an operational liability for power system operators for many years to come.

But that’s all water under the bridge now and we can’t change the past. We can, however, control how we move forward and shape the future of the power industry. As we contemplate market design changes in Alberta and many other electricity markets worldwide, we need to learn from this experience and get crystal clear on the differences between “barriers to entry” and “minimum acceptable participation requirements”. A discretionary service like Uber seemed to understand this from the outset, so shame on us as an industry for not understanding the importance of this for the essential service that underpins modern society and our economic prosperity.

As we move forward as an industry, we must ensure that we’re not making more compromises today with the intent of removing “barriers to entry” that set us up for future power system reliability problems. Not all barriers are bad and in some cases they help more than hinder.

1. There would be a reserve margin of at least 15% and the power system would always have adequate frequency response and voltage support with the lowest economically and technically achievable level of carbon emissions

2. At least 80% of installed generation capacity would be dispatchable due to advances in energy storage and grid forming inverter technology

3. Energy storage would provide large volumes of both energy and ancillary services

4. Alberta would have a second synchronous 500 kV intertie (with a shield wire 😊)

5. The AESO’s long-term transmission plan and tariff would provide strong locational signals so that new generation is built in the right locations, at the right times, with the right technical attributes to economically optimize Alberta’s available generation sources and legacy transmission system capacity investments

6. Data centres would provide ancillary services and load shaping to improve the operational efficiency of the power system

7. The operation of the system would be optimized through operational strategies that exploit the attributes of energy storage and leverage Alberta’s 2 embedded HVDC lines to maximize operational efficiency and system security

8. There would be ongoing formal coordination between power system planning and operations and natural gas system planning and operations to identify and manage common reliability and resource adequacy risks

9. The market would include a day-ahead energy market that co-optimizes energy and ancillary services and uses security constrained economic dispatch to ensure that dispatched generating resources deliver the most economic combination of energy and essential reliability services

10. Market participants would view Alberta as a stable and attractive investment environment that incentivizes operational excellence and reliability

11. Alberta ratepayers would have reliable and secure electricity, would feel that the price they pay reflects the value they receive, and would trust the system planner and operator due to their competence and transparency
    
    Now how hard can that be, right?

As we move towards implementation of the Alberta Restructured Energy Market (REM), I think it’s interesting to look back at a pivotal regulatory decision in the early days of deregulation in Alberta, the Energy and Utilities Board Decision 2002-099, Congestion Management Principles, published in November 2002. This decision established a number of principles for transmission planning and congestion management that shaped the energy market we have today. The PDF is no longer available on the AUC’s website, so I’ve shared it in a LinkedIn post linked to this article to save you the $10 you’ll need to pay the government for an archived copy.

At just over 240 pages, it’s a weighty tome with a wealth of information, but here are a few excerpts I think are particularly notable:

“The Board is of the view that:

• LMP is not compatible with Alberta’s single pool price industry structure;

• LMP would be unnecessarily complex given the likely congestion management issues in Alberta; and

• the effectiveness of LMP in stimulating transmission upgrades is not proven at this time.”

“The TA (Transmission Administrator) shall pursue a non-wires solution if the life-cycle cost of the non-wires solution is materially less than the life-cycle cost of the transmission wires solution compared over an equivalent study period, or if the shorter lead-time of the non-wires solution is necessary or beneficial to ensure reliable service. The TA shall assess the relative costs of wires and non-wires solutions on a case-by-case basis, and shall submit its assessment of the relative costs when seeking either facility approval or approval of a non-wires solution. The cost of non-wires solutions shall be included in the TA’s revenue requirement and allocated on the same basis as wires costs.”

“Physical limitations reflect voltage, temperature (i.e. thermal) and dynamic limits. Thermal limits on power transfer capability are enforced by system operators to ensure that line sag (due to heat buildup from losses) does not lead to line collapse. Dynamic limits refer to power stability limits or transient stability after a fault or disturbance. It is important to note that congestion is not only defined as occurring when physical capacities are exceeded, but also when reliability or operating criteria are violated. In other words, the transmission system may be able to physically accommodate all in-merit transactions if all transmission elements were operating. However, the transmission system would still be defined as being congested due to engineering limitations (e.g. through the application of reliability standards), if the physical capabilities of the transmission system would be unable to accommodate all in-merit transactions in the event of the failure of an integral component of the system.”

“With respect to the issue of which generators should pay for the supply portion of the costs of non-radial transmission enhancements, the Board is concerned that EAL’s (the Transmission Administrator’s) approach of recovering the supply portion of all non-radial transmission enhancements in the STS energy charge would not provide the necessary discipline on transmission expenditures to achieve economical expansions to the system.

“The Board considers a better approach would be the provision of locational signals to new and existing generators in generation rich zones, so that the generators can internalize these costs and make the right economic choices. These choices involve both siting choices for new generators and the opportunity for reduction in STS contract levels or retirement by existing generators. In this way the market is expected to deliver the lowest combined cost of generation and transmission.”

With the benefit of 23 years of market experience, it is interesting to read Decision 2002-099 and compare the EUB’s principles and perspectives with the market changes being implemented through the REM together with the pending transmission policy changes. There was some really thoughtful long-term thinking back then that I think is worth revisiting before we take the scalpel to the patient…

On Dec 10, 2024, Alberta’s Minister of Affordability and Utilities issued his third direction letter to the Alberta Electric System Operator (AESO) regarding energy market design and transmission policy. I want to focus on a particular aspect of the direction letter, the TRP, that will significantly improve transmission planning in Alberta.

New Approach to Transmission Costs

The Dec 10^th direction letter directs the AESO to:

“Implement a cost allocation framework for new transmission infrastructure based on cost-causation principles by requiring new generators to contribute to transmission infrastructure costs by replacing the Generator Unit Owner’s Contribution (GUOC) with an upfront and non-refundable Transmission Reinforcement Payment (TRP).

• These payments will have no upper limit, a floor of $0/megawatt, and will apply to both transmission-connected and distribution-connected generators.

• TRP rates will be calculated as a function of the suppliers’ proximity to transmission capacity, their technical attributes and characteristics, and the cost of reinforcing the transmission system.”

This is a significant change to the current transmission policy in Alberta in which the GUOC does not consider the technical attributes of generators, is refunded to generators over 10 years, and loads pay for all transmission costs.

Existing Approach to Transmission Costs

The original/existing policy treatment of generator transmission cost contributions was articulated in the 2003 Transmission Development Policy (TDP) as follows:

“New generators will be required to assume some costs for transmission system upgrades, in addition to their interconnection costs. This will be called a system contribution payment or SCP. One of the primary intents of the SCP is to act as a long-term siting signal for new generators. Since existing generators can’t relocate and have limited options to reduce their output (considering their sunk costs), the SCP will only apply to new generators.

Subject to satisfactory operation, the SCP made by the generator will be refunded to the generator over 10 years and those payments will be rolled into the rates paid by all load customers. Generators who fail to operate above a minimum capacity factor, which may vary by technology, will not obtain a refund, thereby reasonably protecting load customers from stranded transmission costs.”

When the SCP was codified in Section 29 of the Transmission Regulation, the name was changed to the Generator Unit Owner’s Contribution (GUOC) and the amount was fixed at $10,000/MW for upgrades to existing transmission facilities, and a maximum of $40,000/MW for new transmission.

This approach was based on the 2003 TDP conclusion that “Economic signals and prices from the wholesale electricity market should not be adjusted or unduly distorted with transmission costs” and Principles 4 and 5 of the TDP:

4. Pricing and payment for transmission is fundamentally a cost most appropriately borne by the loads that are served by the transmission system on an equal basis, regardless of location.

5. Generators will make financial commitment and contribution towards upgrades of the transmission system based on generator size and location on the system.

While well-intended from a market efficiency perspective, the refundability of the GUOC combined with the relatively low maximum amount meant that the GUOC failed to provide effective locational signals.

In addition, when the GUOC was implemented almost all generators were or were expected to be synchronous (coal and gas) and no one thought to include consideration for the technical attributes of generators because they were all very similar. As a result, as the number of inverter-based generators (wind, solar) increased over time, the GUOC left the AESO with no mechanism to signal the appropriate locations and capacity limits for generators with varying technical attributes to ensure the ongoing operability and reliability of the transmission system as it expanded to accommodate renewables.

Ultimately, the GUOC failed to meet its intended purpose of providing an economic locational signal and resulted in a legacy of many sub-optimal generation siting decisions that impaired reliability and significantly increased transmission costs to ratepayers.

The Path Forward

Informed by the failures of the GUOC, the non-refundable TRP that considers the technical attributes of new generators will provide much stronger locational signals and allow the AESO to develop more optimized and robust transmission plans that enable supply adequacy and reliability while also minimizing transmission costs to enable affordability. The TRP is “the right path” to a more optimized, reliable, and affordable transmission system in Alberta.

Data Sources:

December 10, 2024 Minister’s Direction Letter to the AESO

2003 Transmission Development Policy

Alberta Transmission Regulation (see Section 29)

July 2024 Minister’s Direction Letter

March 2024 Minister’s Direction Letter

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All transmission and generation equipment have limits on their useful capacity and these are expressed through what we call “facility ratings”.   Facility ratings include things like the maximum voltage, current, real power, and reactive power of various types of power system equipment.  The ratings of equipment are affected by things like the ambient temperature, wind (which cools equipment), solar heating, and distance from other equipment or objects.  For instance, a transmission line rating takes into account the maximum temperature the metal can continually operate at and the amount of sag that results when the metal expands when heated to ensure it doesn’t come into contact with other lines, structures, or equipment underneath it.

FAC-008

NERC reliability standard FAC-008-5 governs the way transmission and generation equipment are rated “To ensure that Facility Ratings used in the reliable planning and operation of the Bulk Electric System (BES) are determined based on technically sound principles.”  The equivalent standard in Alberta is Alberta Reliability Standard FAC-008-AB-3 and it specifies the factors that must be considered to establish facility ratings.

Two Different Approaches

There are two approaches to rating power system equipment – dynamic and static.  A dynamic rating approach takes into account changing ambient temperature, wind speed, and solar heating to optimize the rating of the equipment for the changing operating conditions it actually experiences.  A static rating approach provides a constant, or “static”, rating based on assumed values for ambient temperature, wind speed, and solar heating for a specified period of time. 

By nature, the static approach is typically far more conservative than the dynamic approach, because the rating will be based on the worst operating conditions expected, even though the actual operating conditions will be far less onerous the vast majority of the time.  However, there are situations where the dynamic rating would be more conservative than the static rating, such as an unseasonably warm winter day for transmission line with a winter rating, example.   

While FAC-008 allows for both approaches, the static approach is most common.  It is more conservative than the dynamic approach and it is much easier to implement and operationalize because it does not require the collection and management of large volumes of data on an ongoing basis by the system operator, and simply uses constant assumptions.  However, it also means that there are many times when the full capacity of the equipment cannot be used because the actual ambient conditions are less onerous than the assumed ambient conditions that the static rating is based on. 

Alberta currently uses static equipment ratings for two seasons, summer and winter, defined in FAC-008-AB-3 as follows:

• Summer: May 1^st to October 31^st

• Winter: November 1^st to April 30^th

What this means is that for most of the time, equipment on the power system is operating with limits based on assumed ambient conditions that are quite different than the ambient conditions the equipment is actually experiencing.  This leaves capacity unused and could mean that generation, say wind or solar, is being transmission constrained simply because of the way the transmission lines are rated, not because there isn’t transmission capacity available at the actual ambient conditions at the time.  Using static assumptions also means that new transmission may be built before all available existing transmission capacity is utilized, which is both operationally and economically inefficient. With many capacity constrained areas on the Alberta power system, the broader use of dynamic line ratings (DLR) could make a significant difference in reducing the volume of congestion we’re currently experiencing and defer the need to build new transmission capacity.

FERC Investigating DLR

Recently, FERC announced an Advance Notice of Proposed Rulemaking (ANOPR) to consider potential requirements for transmission providers to use dynamic line ratings. In its announcement, FERC states that “The proposed framework would also require transmission line ratings to reflect forecasts of wind speed and of wind direction for certain transmission lines in windy and congested areas. In order to identify candidate transmission lines for a DLR requirement related to wind, the draft ANOPR proposes metrics to measure congestion both in RTO/ISO regions and in non-RTO/ISO regions.” and the intent is to “make more efficient and cost-effective use of the power grid by requiring the application of dynamic line ratings (DLR), which use up-to-date forecasts of weather conditions to improve the accuracy and transparency of transmission line ratings.”

FERC’s recognition of the value of DLR will hopefully result in broad adoption of DLR over time to maximize the value of existing North American transmission infrastructure.

The Path Forward

While the dynamic approach is harder to operationalize, I believe it can provide significant optimization value and more fully utilize the billions of dollars we have already invested in the Alberta transmission system. The AESO is already piloting DLR for some transmission lines and this is something that should play an increasing role as power system planning evolves in Alberta. 

In conclusion, instead of writing my own explanation of the potential benefits of DLR in Alberta, I’m going to provide an excerpt from the Alberta Market Surveillance Administrator (MSA) Q4 2023 Quarterly Report that does a much better job than I can :-).

Excerpt from the Q4 2023 Market Surveillance Administrator Quarterly Report, February 12, 2024:

2.2 Dynamic line rating

The Alberta electricity transmission line rating is the maximum limit that power can flow through the line, which can be varied by season, as appropriate. The static line ratings are fixed at a certain threshold and referred to as the line capacity. Two seasonal ratings are applied to adjust the line rating, one in the winter months (November 1 to April 30) and one in the summer months (May 1 to October 31). The seasonal shifts from four sampled regions varied greatly from 0% to an increase of 36% (or 0 MW to 142 MW) in 2022, depending on the line.

As the transmission system is built with a zero-congestion policy, there is relatively low congestion compared to generation and congestion generally only occurs in large volumes during line outages or high wind events. However, in regions of increasing congestion, such as areas with multiple wind assets, the returns to using non-wire solutions are high. Even small changes in line ratings in discrete areas or specific lines can create a valuable opportunity for increased flows.

Dynamic line rating (DLR) is a non-wires method to vary an overhead transmission line’s thermal rating limit in response to environmental and weather conditions. Conditions, such as lower temperatures or increased wind speeds, can have cooling effects on the line, reducing sag and increasing the potential safe operating rating. As a result, wind generation and line rating are naturally correlated. DLR is a supporting relief to congested areas, offering additional capacity to lines where the area would have been otherwise constrained, adding to the efficient operation of the electricity grid and market.

There are multiple parameters and conditions that are considered when calculating the real time DLR. The weather factors can include wind speed, direction and angle, solar radiation, ambient temperature, humidity, and more. The physical considerations include line current, sag and tension, material, and construction of the physical line and insulation. Although there are different tools and methods, the more comprehensive the evaluation, the less risky and the more accurate the result.

DLR pilots have led to promising results, ranging from a 20% to 177% increase in line ratings and are currently implemented in Germany, Belgium, the United Kingdom, New York, PJM, and Texas. A 2017 study within a PJM region on a 22-mile, 345 kV line with 3 DLR monitored sections, was estimated to cost $500,000 USD. However, the study also notes that the net congestion savings was over $4 million USD over one year. There are many considerations when implementing DLR including safety, information quality and speed, increased physical monitoring of equipment, and data integration. Using a cost benefit approach could help determine the optimal implementation plan.

2.2.1 Alberta

DLR was previously tested in Alberta from June to December of 2015, when AltaLink conducted a DLR study on four segments of a 138 kV line. The site was of interest as the majority of the power in the test area was from wind generation. The tested lines include both east-west and north-south components in an L-shape, which was chosen to assess the impact of wind direction on line cooling.

The results included a mean increase in over 75% of the study period (June to December 2015). The increase in mean transmission line rating ranged from 22% to 72%, depending on the line. Of note, during certain instances the dynamic rating was lower than the original static rating. The report theorizes that this was due to the wind reaching the generators before the lines, where the increased flow from generation was heating the line before the wind was able to cool it. Although no major issues were reported in this study, AltaLink stated in 2022 that the province’s harsh climate has previously caused different DLR devices to stop working, go out of calibration, or be blown from the line.

Since this time, the AESO has begun to explore using DLR for real time operations in the South and Central regions (AltaLink and ATCO TFO regions, respectively). During the 2023 grid reliability session, the new pilots were discussed, and the in-service date for DLR was updated to 2025. The proposal includes the 240 kV double circuit lines 924L and 927L as well as the 138kV line 7L128. There have been previous mentions of DLR in AESO’s 2021 technology forward publication and in the 2022 year in review where the AESO states that DLR would be implemented where feasible in 2023.

2.2.2 Theoretical DLR Example

Line 610L is a 138 kV line located in the Vauxhall region and runs between Fincastle and Taber. The seasonal shift in thermal line rating is approximately 6%. On November 15, 2022, the AESO filed a development NID which will include a new line and the removal of the current 610L. The line is frequently overloaded in real time and, consequently, multiple solar and wind farms are constrained down. The proximity to wind generation assets, length and congestion makes 610L a candidate for DLR.

The data from the 610L is outlined below as a simplified example of the potential increase in capacity from wind generation. A previous study by the Idaho National Laboratory estimated that a 12 km/h wind speed can increase the dynamic line rating by 35% in a conservative scenario. Using this metric, the dashed line represents the dynamic line rating, where the line rating is increased by 35% when wind speeds met or exceeded 12 km/h. The yellow line represents the wind speed in km/h, the orange is the current seasonal line ratings employed by the AESO, and the blue line shows actual flow in MVA.

The overall modelling trends demonstrate the overlapping pattern of wind speed and increased flow. The actual real flow on 610L is frequently above the seasonal line rating, as shown where the solid blue line exceeds the orange. When capacity is modeled with the increase in line rating from increased wind speeds, the line would not have been overloaded (in most of situations that occurred). An example is from November 14 to 28, 2022, where actual flow exceeded the line rating, but was below the DLR theoretical limit. 610L is a demonstration of how DLR could help increase the line rating and flow, reduce congestion, and contribute to efficient use of the existing transmission system.

The MSA recommends that the AESO continue to study and implement DLR in Alberta in targeted areas, such a high wind or frequently constrained areas. More tangible deadlines with near term implementation could facilitate optimal planning and use of the transmission system. Understanding DLR’s role in operations is an opportunity to incorporate this method into the future grid.

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Electricity is produced by various types of generators, which are typically referred to by their fuel type, such as coal, nuclear, gas, hydro, wind, or solar. While these terms are familiar to most people, few outside the utility industry understand how these generators actually produce electricity. The intent of this brief article is to provide a basic overview of the various types of generators to serve as a quick reference guide (QRG) for those not familiar with how electricity is generated.

Generator Terminology

First, let’s define a few important terms that are associated with power generation.

Capacity – the maximum output that a generator can produce. Typically expressed in kilowatts (kW) or megawatts (MW). This is the rating of a generator and system operators depend on capacity being available for dispatch to ensure reliability and supply adequacy.

Energy – the amount of power that a generator delivers over a period of time, usually measured in kilowatt-hours (kWh) or megawatt-hours (MWh). 

• For example, a 100 MW generator that operates at full capacity for 2 hours produces 200 MWh of energy (100 MW X 2 hrs = 200 MWh)

Capacity Factor – the ratio of energy that a generator actually produces over a given time period to the theoretical maximum amount of energy the generator can produce over the same time period. Capacity factors are typically measured over one year.

• Base Load – generators with capacity factors of 80% to 95%

• Intermediate Load – generators with typical capacity factors of 35% to 65%

• Peak Load – generators that operate during peak demand periods, with typical capacity factors of 5% to 25%

Thermal Generator - a generator that converts thermal energy (heat) into electrical energy, typically through a combustion process

Thermal Efficiency – the efficiency with which thermal energy (heat) is converted to electrical energy, measured in %

Heat Rate – the ratio of fuel energy input to electrical energy output, usually measured in British Thermal Units per kilowatt hour, Btu/kWh

• Heat Rate (Btu/kWh) = Energy Input (Btu) / Electrical Energy Output (kWh)

Relationship of Thermal Efficiency to Heat Rate

• Thermal Efficiency (%) = 3413 / Heat Rate (Btu/kWh)

• 1 kWh = 3413 Btu

• Example:  What is the thermal efficiency of a generator with a heat rate of 10,500 Btu/kWh? Thermal Efficiency = 3,413 / 10,500 = 32.5%

Basic Thermal Generator Principles

While there are various types of thermal generators, the basic principles underlying all thermal generators are the same: 

• Thermal energy (heat) is produced by the combustion of a fuel (liquid, solid, or gas) or through a nuclear reaction

• The thermal energy is then transferred to a working fluid 

• The working fluid is used to drive a turbine which converts the thermal energy into mechanical (kinetic) energy 

• The turbine spins a generator which converts the mechanical energy into electrical energy

• All thermal generators are “synchronous” with the transmission system, which means they are directly electrically coupled to the grid through their alternating current (AC) generators

• Because thermal generators are synchronous, the rotating masses of their turbines and generators provide angular momentum, also know as inertia, to the power system to help maintain frequency stability

AC Generator Principles

Here are some basic operational principles of alternating current (AC) generators:

• An AC generator converts the mechanical (kinetic) energy of a turbine into electrical energy

• An AC generator consists of two main components – a rotor and a stator. The photos above illustrate what these look like

• The rotor is basically a large magnet that creates a rotating magnetic field using regulated DC voltage via “slip rings” that connect the rotating shaft to the voltage source

• The stator is made of wire conductor loops wound around an iron core – the power generated by the turbine flows through the generator’s stator to the transmission system

• The rotor rotates within the stator and induces an electrical current in the stator winding through electromagnetic induction, which is when voltage is created across the terminals of a looped conductor when it passes through a magnetic field

• The generator rotor consists pairs of magnetic north and south “poles”

• The frequency of the voltage produced by a generator depends on rotational speed and the number of pairs of generator poles

  • Frequency (Hz) = (Rotational Speed (RPM) X # of pole pairs) / 60

• In a 60 Hz system, the maximum rotational speed a generator can obtain is when it has one pole pair

  • Rotational Speed (RPM) = {frequency X 60} / # of pole pairs

    • RPM = 60 X 60 / 1 = 3600 RPM

• For a 50 Hz system, the maximum rotational speed a generator can obtain is:

  • RPM = 50 X 60 / 1 = 3000 RPM

• High speed generators, such as gas and steam turbines, have 1 pole pair and therefore spin at system frequency (60 or 50 Hz)

• Very large diameter generators, such as hydro turbines, must spin at much lower speeds, such as 120 or 150 RPM, due to their large mass and therefore have many more pole pairs

• For example, a 60 Hz hydroelectric generator that spins at 150 RPM has 24 pole pairs

  • # of Pole Pairs = 60 X 60 / 150 = 24 pole pairs

Steam Turbines

A thermal generator that uses steam to rotate the turbine and generator is known as a steam turbine, and has the following characteristics:

• Coal-fired plants and nuclear plants both produce electricity using steam turbines

  • In both cases, the working fluid is steam

• Coal, natural gas, oil, or biomass is burned in a large boiler which heats water to produce high pressure/temperature steam, or a nuclear reaction is used to produce high pressure/temperature steam in a large boiler that is sent to the steam turbine through high pressure pipes

• After the steam enters the turbine, it expands through a series of blades that increase in length as the steam travels along the turbine to maximize the energy transfer from the steam as it expands and loses energy

• The steam exits the turbine and is condensed back to water in a condenser

• The water is then heated back into steam and the cycle repeats

• The steam turbine is directly coupled to an AC generator to create electricity

• Steam turbines are large and have a lot of mass, which means they must be slowly and evenly heated up to operating temperature to avoid differential heat zones in the turbine that can warp and damage it. In addition, the boilers and steam piping must also be evenly heated up for the same reasons. Therefore, steam turbines have long startup times that can range from 8 to 10 hours when started from ambient temperature.

• Steam turbines are used primarily in base load applications

• Typical Thermal Efficiencies range from 28% to 36%

Simple Cycle Gas Turbines

A simple cycle gas turbine (SCGT), is also known as an open cycle gas turbine, gas turbine, or “jet engine”. The gas turbines used to power aircraft are similar to, and in some cases almost identical to, the gas turbines used to generate electricity. A simple cycle gas turbine has three basic components - a compressor, a combustion chamber, and a power turbine. The gas turbine is connected to a generator to create power. Here are the basic operational principles:

• Atmospheric air is sucked in and compressed by the compressor

  • The working fluid is air

• Liquid (diesel, aviation fuel) or gaseous fuel (natural gas) is added to the compressed air and the mixture is ignited in the combustion chamber

• The high pressure/temperature combustion gas is expanded through the blades of the power turbine and then exhausted to atmosphere

  • The sequence can easily be remembered as: Suck - Squeeze - Bang - Blow!

• The turbine is coupled to an AC generator to produce electricity

• Simple cycle gas turbines use high temperature tolerant nickel based superalloys which allows them to be warmed up quickly, so they have fast startup times that range from 10 to 45 minutes when started from ambient temperature

• They are typically used for peaking and to provide operating reserves on short notice

• Typical Thermal Efficiencies range from 29% to 40%

Combined Cycle Gas Turbines

A combined cycle gas turbine (CCGT) is simply the combination of one or more gas turbines with a steam turbine. Here are the basic operational principles:

• Since a CCGT combines gas and steam turbines, the working fluids are both air and steam

• The gas turbine operates exactly as described in the Simple Cycle Gas Turbines section above. However, once the hot gases pass through the turbine, instead of being exhausted to atmosphere, they are directed through a boiler to create steam

• The steam is then expanded through the blades of a steam turbine as described in the Steam Turbines section above

• AC generators are connected to both the gas and steam turbines to produce electricity

• Due to the combination of gas and steam turbines, the startup times for CCGTs are between 3 to 8 hours

• CCGTs are more operationally flexible than pure steam turbines and are used for both intermediate base load applications

• CCGTs have the highest Thermal Efficiencies of all thermal generators, typically in the 45% to 62% range

Hydroelectric Generation

One of the oldest ways to generator electricity is through the use of water. A hydroelectric generator is simply a large turbine that is rotated by water and connected to an AC generator to produce electricity. Here are the basic operational principles:

• Water, either from a river or a man-made reservoir, is directed through a channel or penstock

• The water then moves through gates to control the flow rate, called wicket gates

• After passing through the wicket gates, the water then rotates a turbine

  • The working fluid is water

• The turbine drives an AC generator to produce electricity

• There are three types of hydroelectric turbines:

  • Francis turbine: combines axial and radial flow, has fixed blades, and is vertically oriented – this is the most common type of hydroelectric turbine

  • Kaplan turbine: an evolution of the Francis turbine with adjustable blades

  • Pelton wheel: tangential flow device that is essentially a “bucket” wheel that is driven by the “impulse” of water on the buckets, horizontally oriented

Wind Turbines

Wind turbines are relatively simple. Wind travels through the blades of a large turbine that is connected to a generator to produce electricity. However, unlike thermal generators, wind turbine generators are not synchronous because the speed of the generator varies with wind speed, so the generator uses sophisticated power electronics (inverters) to transmit electricity to the grid at the correct frequency and voltage. For this reason, wind turbines are known as inverter-based resources (IBR).

The working fluid is air and typical wind turbine sizes range from less than 1 MW to 5 MW, but sizes are increasing and there are some wind turbines that exceed 10 MW.

Solar Power

There are two types of utility scale solar power systems:

• Solar Photovoltaic (PV) which converts solar light directly into electricity using semiconductors. Electricity is generated by the “photovoltaic effect” in which a semiconducting material absorbs photons of light and emits electrons to produce an electric current

• Concentrated Solar Power (CSP), which uses mirrors or lenses to concentrate sunlight into powerful beams that are used to heat water or a salt solution to create steam to drive a steam turbine

• Similar to wind generators, PV systems use sophisticated power electronics (inverters) to transmit electricity to the grid, and are known as inverter-based resources (IBR).

• Both PV and CSP plants require large areas of land

Conclusion

While there are many different types of generators, there a some common basic principles of operation:

• Almost all power generators convert mechanical energy to electrical energy through the use of a working fluid – gas, steam, air, or water

• Coal-fired power plants and nuclear power plants use steam turbines

• Combined cycle power plants use both gas and steam turbines

• Only solar PV produces electricity directly with no working fluid

• Gas turbines, steam turbines, and hydroelectric turbines are synchronous generators because they are directly electrically coupled to the grid

• Wind and solar generators are connected to the grid via power electronics and are known as inverter-based resources (IBR)

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NERC published its 2024 Summer Reliability Assessment on May 15th. The Assessment identified multiple Elevated Risk assessment areas, as shown in the map above.  A few things that stand out for me are:

• Significant year over year demand growth in multiple assessment areas

• Continued issues with unexpected tripping of inverter-based resources (IBR) during grid disturbances

• Above average summer temperatures are forecast across multiple assessment areas, including most of WECC

The Good News

Specifically for Alberta, the Assessment did not identify Alberta as an assessment area of concern, which is hopeful. The Assessment determined that Alberta “is expected to have sufficient resource availability to meet reserves at the peak demand hour (4:00–5:00 p.m.). This evaluation considers a 1-in-10 probability (90th percentile) level for peak demand and a combination of resource derates.”

So, the good news is that our resource adequacy situation is improving with some much needed new gas-fired generation hitting the Alberta grid in 2024.

The Bad

The bad news, however, is that we continue to have reliability challenges. The Assessment identified a concern with “Issues maintaining rate of change of frequency (ROCOF) during islanded or near-islanded situations with high IBR output and low demand”. This issue is the result of declining system inertia and the corresponding degradation of frequency response on the Alberta grid due to increasing levels of IBR relative to synchronous generators on the system.

The AESO highlighted this issue in its March 2023 Reliability Requirements Roadmap. On page 24 of that report, the AESO states:

“The capability of the AESO to arrest frequency decay without activating UFLS (Under-frequency Load Shedding) is being impacted by Alberta’s changing generation supply mix and its inherent inertia and primary frequency response capabilities. Due to insufficient primary frequency response capabilities, UFLS was activated several times in 2020 and 2021. These UFLS activation events were triggered by the tripping of generation in Alberta while operating in islanded mode and/or tripping of the interties while interconnected with the Western Interconnection.”

This will be of particular concern when we get into hot, windy, and sunny conditions and thunderstorms develop which could trip the AB-BC intertie due to its poor lightning protection.  We have had frequency excursions in the past in these weather conditions, and with increasing IBR levels in Alberta, this will be an ongoing concern.

In addition to this operational risk, Alberta will also be at risk this summer due to potential operational issues external to Alberta associated with BC and the two other WECC assessment areas that are at Elevated Risk.

So, while we are seeing improvements in resource adequacy, we continue to have challenges with reliability as the supply mix evolves in Alberta.

Here is a link to the NERC 2024 Summer Reliability Assessment for those interested in a deeper dive: NERC 2024 Summer Reliability Assessment

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As the Alberta government considers revisions to the electricity policy framework in Alberta, I thought it may be helpful to provide a brief explanation of how power system planning is performed in Alberta and how it differs from the rest of Canada. Here is my attempt at a quick reference guide (QRG) for grid planning in Alberta.

Power System Planning in Regulated Provinces

Regulated Provinces like BC, Saskatchewan, Manitoba, Quebec have vertically integrated models in which a single Provincial entity, a crown-owned electric utility, is responsible for generation, distribution, and transmission planning and operations. These utilities plan new transmission and generation to meet forecast demand while simultaneously implementing government social and environmental policy objectives.

Crown-owned utilities use an approach called integrated resource planning (IRP) to determine the optimum economic and technical combination of generation, transmission, and distribution investments to satisfy their demand forecasts, reliability and resource adequacy requirements, and social and environmental policy objectives. The main sources of planning uncertainty in this approach are the pace and location of demand growth.

In the regulated Provinces, the crown-owned utilities are responsible for resource adequacy, reliability, and power system operations, which includes generator dispatch and transmission and distribution operations.

Power System Planning in Alberta

Alberta has a very different planning paradigm. There is no single entity that is responsible for both generation and transmission planning. Generation planning and investment decisions are made by numerous private investors based on expected long-term economic returns from Alberta’s wholesale markets for power and ancillary services. Transmission planning and investment decisions are made by Alberta’s ISO, the Alberta Electric System Operator (AESO) which has the legal responsibility to plan the Alberta transmission system to satisfy forecast demand and provide unconstrained transmission capacity for anticipated new generation. So, while the AESO controls transmission planning and investment, there are numerous private entities that determine the timing, location, type, and size of new generation projects.

In order to plan the transmission system, the AESO must not only forecast the pace and location of demand across the Province, they must also make assumptions about the type, size, timing, and location of new generation and plan to ensure there is sufficient transmission capacity for them to reliably and safely connect to the system without constraints. In Alberta, the sources of planning uncertainty are the pace and location of demand growth as well as the timing, location, size, and type of future generation on the system. In other words, the AESO must essentially make educated guesses as to what kinds of generators show up when and where and plan to ensure sufficient transmission capacity is in place before they want to connect to the system.

The end result is that there is no integration of generation and transmission planning in Alberta. And, unlike the regulated Provinces, there is no entity responsible for integrating social and environmental policy objectives into power system plans.

In Alberta, the AESO is responsible for power system reliability, but resource adequacy depends on investor confidence in the market as the mechanism for timely and sufficient generation investment. The AESO is responsible for transmission system operations and market operations, while distribution companies are responsible for distribution system planning, reliability, and operations.

Here’s a summary of how the two approaches compare:

A Path Forward

The AESO recently published transmission policy changes it recommended to the Alberta government that address these planning challenges. The AESO makes 5 recommendations as follows:

1. A move away from a congestion free transmission policy to an optimized transmission planning approach.

2. Enhancing the AESO’s ability to act in a timely manner to reflect the rapidly changing nature of the grid and to put the system infrastructure in place required to mitigate reliability issues quickly.

3. Changes to cost allocation to require suppliers to pay more to reflect their impact to system costs.

4. Enhancing the AESO’s ability to direct where resources connect to the grid.

5. Clarifying volume and timing targets for the restoration of existing interconnections with other jurisdictions and the expansion or development of new interconnections.

To these recommendations, I would add a few other enhancements that I believe we need in Alberta:

• An explicit minimum reserve margin for Alberta articulated in regulation to provide the AESO and market participants with target resource adequacy levels

• The implementation of a capacity accreditation process to provide a consistent, structured, and transparent process for managing resource adequacy

• Legislated requirements for planning and operational coordination of natural gas and electricity infrastructure in recognition of the fact that Alberta’s power system is now fully dependent on the reliable supply and delivery of natural gas

These changes to how the grid is planned in Alberta would address the planning challenges and uncertainties outlined above.

Final Thoughts

Our policy framework in Alberta depends on investor confidence to drive sufficient generation investment to provide resource adequacy and reliability. And it worked remarkably well for about 20 years. However, things have changed, and now generation investment decisions are increasingly being driven by environmental and social policy and out-of-market generator compensation, such as generator power purchase agreements with corporations looking to meet ESG objectives. The result is declining resource adequacy and reliability in Alberta.

These are the problems the Alberta government is trying to solve as it considers changes to the electricity policy framework that has served us well for so many years. I believe a market-based approach can continue to succeed, but the market design and planning paradigm must both evolve to ensure continued resource adequacy, reliability, and affordability in Alberta.

The need for change is urgent and transmission policy certainty is required as soon as possible because it will take some time to design and implement market and transmission planning changes and Alberta’s power system will continue to be at risk in the interim. The key will be to keep it simple, and not let perfect be the enemy of good.

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Our Synchronous Past

When power industry deregulation began in the mid-1990s, essentially all generating resources were synchronous generators. They provided both energy and the essential reliability services we need to maintain reliable grid operations - frequency support (inertia) and voltage support (VARs). So, when electricity and ancillary services markets were originally designed, it was an implicit assumption that these essential reliability services were included in the energy offered into markets by generating resources - they were just part of the package. As long as markets delivered resource adequacy, it could be assumed that markets would also deliver reliability.

But things have changed. Inverter-based resources (IBR - wind generation, solar generation, and battery energy storage systems) have gone from non-existent 20 years ago to increasingly large proportions of the resource mix, and the physical attributes of these generating resources are very different from the synchronous resources our original markets were designed for.

While IBR provide lots of energy, they do not provide the same essential reliability attributes as synchronous resources, and this is creating many operational challenges for system operators. I’m confident that this will change over time as we learn to harness the capabilities of power electronics through grid forming inverter controls and other technological advancements, but this will take some time to develop.

Different Resources, Different Thinking

In Alberta, as in many other jurisdictions, the change in resource mix is driving the need to redesign our electricity market to maintain resource adequacy, reliability, and operability, and this effort has already been initiated by the Alberta Electric System Operator (AESO).

As the redesign discussions progress, my hope is that we take this opportunity to truly think differently about the resource mix of the future, and not let our old paradigms and assumptions bias how we think about market design changes. We will have a resource mix with fundamentally different physical characteristics going forward, so we must be cautious not to simply apply traditional thinking and solutions to new problems.

We must strive to make market design changes that are resilient to future uncertainties. To do this, we must avoid anchoring bias, which is a bias toward existing information and past experience when making decisions about the future.

Questions To Consider

When I try to think differently about electricity markets, these are some questions that come up for me:

• Have we spent enough time defining the problem(s) we’re trying to solve, or are we already anchored on solutions?

• Is there a simple way to include frequency and voltage support in the economic price signal so that generators offer not only energy, but a “bundle” of attributes into the electricity market? For instance, similar to markets that trade different grades of crude oil (WTI and Brent), perhaps we can “grade” energy based on its characteristics, so that energy that includes inertia and VARs is valued higher than energy that doesn’t include these other characteristics. A MWh of energy from a synchronous generator has a higher operational reliability value than a MWh of IBR energy, so how can we signal this economically?

• How can we think differently about the role of ancillary services? Should we differentiate between the services required for contingency management and regulation and those required for managing the variability caused by weather-dependent variable generators?

• Should the system operator employ a minimum real-time system inertia level as an operational “reliability limit” to ensure that the generation mix that is dispatched via the merit order maintains a minimum acceptable level of reliability and operability? Just like price caps and floors, should we establish a “reliability floor”?

• Should variable resources be responsible for firming their variability, either via on-site energy storage or via paying for the necessary incremental ancillary services?

• How can we keep it simple? What are the minimum number of changes we can make to our energy-only and ancillary services market designs to get markets that provide both reliability and energy? In other words, can we retain the simplicity of Alberta’s existing market design that has served us so well for all these years?

• What does “success” look like for our market 10 years from now?

Final Thoughts

In Alberta, our relatively simple energy-only electricity market and ancillary services market have served us well for 20 years. These markets were based on the assumption that most, if not all, of the generating resources implicitly provided frequency and voltage support, but that assumption is no longer valid. We asked for energy only and now, quite frequently, that’s what we’re getting - only energy. We got what we asked for :-)

So the question is, what should we be asking for now?

PS: For those who continue to insist we need a capacity market, I’ll remind you that Alberta has always had one. Its called the ancillary services market :-)

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As power systems around the world transition to increasing levels of renewable energy resources, grid operators are struggling with the changing physical characteristics of the power system that accompany this shift from traditional synchronous generating resources (SGR - coal, natural gas, hydro, and nuclear generation) to inverter-based resources (IBR - wind, solar, and batteries). Two of the biggest operational impacts of this change in the resource mix are declining power system inertia and voltage support, both of which are naturally provided by SGR. The reason for this is that SGR are directly electrically coupled to the power system through the electric fields of their generator windings while IBR are connected to the power system indirectly through sophisticated power electronics. I’ve written explanations of system inertia and reactive power in previous articles for those interested in learning more.

Because of these changes in system characteristics, power system operators must now pay much more attention to real time system inertia and voltage levels than they had to in the past to ensure there are adequate SGR available to keep the system stable when a disturbance happens that upsets the supply demand balance or when there are localized voltage issues due to large volumes of IBR providing energy in specific areas.

I think two recent studies do a good job of illustrating these operational challenges.

WECC Changes in System Inertia Study

In 2021, the Western Electricity Coordination Council (WECC) completed a study of the reliability impacts of increasing levels of IBR operating across the Western Interconnection. The Changes in System Inertia Study demonstrates the increasing operational risks IBR are creating for system operators across the Western Interconnection and makes 6 recommendations as follows:

1. Planning Coordinators, Transmission Planners, Balancing Authorities, and Reliability Coordinators should monitor system inertia and frequency response, especially under low inertia conditions.

2. The System Review Subcommittee (SRS) should track the amount of inertia and report frequency response under a large generation contingency in each of the Western Interconnection base cases. Additionally, SRS should consider developing a minimum system inertia case on an ongoing basis so that entities can evaluate for adequate system frequency response under low inertia conditions.

3. Planning Coordinators, through their participation in the under-frequency load shedding (UFLS) Work Group, should investigate islanding scenarios and evaluate the UFLS plan to make sure the set points of the UFLS relays are still adequate due to the drastic change in the rate of change of frequency (ROCOF) caused by increased penetration of IBRs. The UFLS Work Group assessments should include minimum inertia cases to ensure the adequacy of the UFLS plan.

4. Planning Coordinators, Transmission Planners, and Reliability Coordinators should perform additional studies to better understand the impact of reduction in synchronous resources on transient and voltage stability in the Western Interconnection. These studies need to evaluate the implications of shifts in generator locations.

5. The WECC Modeling Validation Subcommittee (MVS) should ensure dynamic models provide a reasonably accurate representation of IBR frequency response that represents capabilities of wind and solar resources. The MVS should develop a guideline on frequency response modeling of various IBRs.

6. Transmission Planners should ensure that Generator Owners include frequency response characteristics and provide validated models.

This study demonstrates the significant operational challenges the shift to IBR from SGR is creating across the Western Interconnection, and is recommended reading for all WECC participants.

Alberta Electric System Operator (AESO) Reliability Requirements Roadmap

In March 2023, the AESO published the Reliability Requirements Roadmap to address the Alberta power system operational impacts of increasing levels of transmission connected IBR, distribution connected IBR, and changes to demand patterns due to increasing electrification. The report provides an excellent overview of the challenges facing Alberta’s evolving power system and highlights the fact that “While this shift creates investment opportunities and helps the province to progress towards a decarbonized electricity system and economy, it also presents significant operational challenges.”  The report focuses on 3 key areas of system reliability:

1. Frequency Stability - this is the ability of the power system to maintain sufficient frequency and recover to normal operating frequency (60 Hz) following the sudden loss of a large supply source. The AESO considers Frequency Stability to be their highest priority, stating “Existing frequency-related operational challenges mean that immediate action is required to reduce frequency stability risk. The need for mitigation will continue to grow over time as the generation fleet continues to transform.”  Essentially, the AESO is saying that as more IBR are added to the system without the addition of SGR, the harder it will be to maintain adequate frequency control.

2. System Strength - this is the ability of the power system to maintain normal voltage at any given location despite system disturbances. The AESO sees System Strength as a localized challenge in specific areas of the system in the near term but increasing in significance if not addressed soon.

3. Flexibility Capability - this is the ability of the power system to adapt to dynamic and changing conditions while maintaining the balance between supply and demand. This is manageable today but will become more challenging as more IBR are added.

As with the WECC study, the AESO study demonstrates the increasing operational challenges associated with increasing levels of IBR on the Alberta power system.

Game Changer - Direct Measurement of System Inertia

Given these operational challenges, the importance of understanding system inertia and system strength levels in real time is critically important for system operators. Currently, system operators calculate the inertia of their power systems using system models to maintain situational awareness. While models are useful, they are only estimates and require system operators to allow large operating margins which results in inefficient system utilization and operational uncertainty.

However, an exciting new technology from a company called Reactive Technologies could be a game changer. Reactive Technologies has developed a system that gives power system operators a way to directly and accurately measure power system inertia and system strength in real time, as opposed to using mathematical estimates. This improves situational awareness and enables far more effective and reliable power system operations.

The technology works by injecting energy pulses into the power system using an “ultracapacitor” and analyzing the return signal time and waveform to calculate inertia and system strength. This enables direct measurement of system inertia that is far more accurate than model estimates so system operators know the actual inertia of the system in real time. National Grid in the UK and TEPCO in Japan are already using this technology. Here's a quote from the reactive technologies website:

"Reactive Technologies’ Grid-Sonar ™ technology measures grid response through a periodic pulse of energy that is pushed into the system via a custom-built modulator. The signal that comes back provides real-time grid insights with unprecedented accuracy, allowing grid operators to monitor inertia and system strength levels and stay prepared should a disturbance arise... Once the noise has been filtered out, the minute changes in frequency and voltage can be observed across the entire grid. The behavior of these frequency movements is a measure of the grid’s inertia, while the voltage movements measure the grid’s system strength."

This is game changing technology for system operators as we move into an IBR dominated future, so I hope to see it widely adopted in the near future.

For those interested in learning more, here’s a link a CIGRE symposium white paper on the technology: Inertia Estimation Methodologies vs Measurement Methodology: Impact on System Operations

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So far in 2024, the Alberta power system has experienced numerous Energy Emergency Alerts and supply shortfall events in January and April. These alerts and events are very public indications of the supply adequacy problem we currently have in Alberta due to an imbalance of renewable energy resources (energy) and synchronous resources (capacity) on our power system. Many people are likely wondering how Alberta’s Independent System Operator, the Alberta Electric System Operator (AESO), manages these operational situations, so the intent of this article is to provide a brief explanation and links to more information.

Rules & Reliability Standards

A supply shortfall is a situation on the power system when there is not enough electricity supply available from generators, or neighbouring jurisdictions via interties, to meet total demand during real-time operations. In Alberta, ISO Rules 202.2 - Short Term Adequacy and Supply Shortfall and 202.6 - Adequacy of Supply describe the market rules associated with supply shortfall events, and Alberta Reliability Standard EOP-011-AB-1 Emergency Operations describes how the AESO operates the grid during emergency conditions, including supply shortfall events.

Energy Emergency Alerts (EEAs)

EEAs are issued by the AESO to notify market participants when there is a risk to the reliability of the power system that could result in localized or widespread blackouts. The AESO issues EEAs to market participants and publishes them on the event log on their website. EEAs are used by system operators across North America in accordance with NERC reliability standards.

There are four levels of EEA, the most severe of which is EEA3, which means that the power system is at imminent risk of partial or widespread blackouts. When the AESO declares an EEA1, we should all start to look for ways to reduce our electricity use!

Here are the definitions of EEAs:

EEA0 – System normal, adequate supply to meet demand

EEA1 – All available generation resources are in use.

• The ISO is experiencing conditions where all available generation resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required contingency reserve.

• Non-firm wholesale energy sales, other than those that are recallable to meet reserve requirements, have been curtailed.

EEA2 – Load management procedures in effect.

• The ISO is no longer able to provide its expected energy requirements and is energy deficient.

• The ISO has implemented its operating plans to mitigate emergencies.

• The ISO is still able to maintain minimum contingency reserve requirements.

EEA3 – Firm load interruption is imminent or in progress.

• The ISO is unable to meet minimum contingency reserve requirements.

Steps to Darkness

When the AESO determines that a supply shortfall event is probable and begins emergency operations, the AESO’s System Controllers follow a series of steps that are outlined in Information Document (ID) #2012-006R - Adequacy, Supply Shortfall and Energy Emergency Alerts. Since the ID is a long read, here are the supply shortfall operational steps the System Controllers follow:

1. The AESO, performs a short term adequacy assessment in accordance with subsection 2 of Section 202.2, when the short term adequacy program issues an alarm.

2. Perform planning steps, which may include:

   1. if step 7 is anticipated to be reached, cancel transmission maintenance to remove generation constraints or increase import available transfer capability on all interconnections with neighbouring balancing authorities;

   2. if it is assessed that shedding of firm load is likely to occur, and sufficient time is available for a public appeal to reduce electrical energy consumption to reduce load, arrange for AESO Corporate Communication to issue a public appeal;

   3. allow for 1 hour notice if it is anticipated that the demand opportunity service 1 hour loads are to be curtailed in step 8;

   4. determine in which future hours during the potential supply shortfall export available transfer capability on all interconnections with neighbouring balancing authorities are to be posted to 0 MW in step 6 so new export available transfer capability levels can be posted 1 hour in advance;

   5. if the AESO reasonably anticipates an Energy Emergency Alert 1 or 2 is likely to be reached, notify the adjacent balancing authorities; and

   6. allow for 1 hour notice if it is anticipated that the AESO Voluntary Load Curtailment Program loads are to be issued dispatches to terminate load in step 13.

3. Issue a dispatch to terminate dispatch down service with respect to a directive for energy from a long lead time asset.

4. Internal notifications within the AESO.

5. Declare Energy Emergency Alert 1 in accordance with EOP-011-AB-1.

6. Reduce export available transfer capability to zero on all interconnections with neighbouring balancing authorities and post the updated available transfer capability to the AESO website.

7. Declare Energy Emergency Alert 2 in accordance with EOP-011-AB-1.

8. Curtail demand opportunity service loads.

9. Cancel transmission maintenance.

10. Issue directives for dispatched contingency reserves that are in excess of the contingency reserve requirement.

11. Issue directives for out-of-market energy from long lead time assets.

12. Request legal owners of an electric distribution system institute a 3% distribution voltage reduction.

13. Issue dispatches to terminate load in the AESO’s voluntary load curtailment program as identified by the AESO internal procedures.

14. If available transfer capability is limited because of the lack of offers for load shed service for imports, then disregard this constraint and increase the posted Alberta-BC and Alberta-Montana interconnection import available transfer capability up to the limit as if all available load shed service for imports loads are in service. This step is performed as weather and other operating conditions allow.

15. If import available transfer capability is available, permit intra-hour interchange transactions up to the posted import available transfer capability limit.

16. Declare Energy Emergency Alert 3 in accordance with EOP-011-AB-1.

17. Issue directives for supplemental reserves.

18. Issue directives for spinning reserves.

19. If there is available capacity on the interconnections, request emergency energy from Saskatchewan.

20. If there is available capacity on the interconnections, request emergency energy from British Columbia.

21. If there is available capacity on the interconnections, request emergency energy from the Northwest Power Pool.

22. Issue a directive to curtail firm load and set pool price to $1000/MWh

Conclusion

EEAs are becoming all too common in Alberta due to our supply adequacy and reliability problems, and we will be seeing more of them, so hopefully this article helps people understand what they are, when they’re issued, and how the AESO manages supply shortfall events when they occur. All of this information is posted on the AESO’s websites in various rules and standards and I have provided links to the key documents throughout the article for those interested in learning more.

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The Alberta Electric System Operator (AESO) held a media briefing on Apr 5^th to explain the supply shortfall event that took place that morning.  There are many media articles and pundits interpreting the event (including me :)), but I urge anyone who wants to understand what really happened to listen to the webinar the AESO has posted on its website.  Here is a link: AESO Media Briefing on Apr 5th Event

We should all be grateful to the AESO’s System Controllers for the work they did on Apr 5^th and every day of the year to keep the electrons flowing.  They are trying to manage a very fragile system and are faced with numerous challenges every week that are making their jobs increasingly difficult and stressful, so we owe them a debt of gratitude.

My summary of the facts - but please also listen to the AESO’s explanation:

• many generators were on planned maintenance outages, which is normal during the spring season in Alberta when our demand is low

• some dispatchable capacity was offline because they were uneconomic due to low pool prices over the preceding days, which is also normal in our market design

• wind generation forecast error (lower than forecast) combined with an approximately 400 MW thermal unit trip during the morning load ramp resulted in an Energy Emergency Alert 3 at 6:49 AM on Apr 5, 2024

• the AESO directed all operating reserves to provide energy, all available dispatchable generators to provide as much energy as possible, and tried to get as much energy from the interties as possible

• this was insufficient to meet demand, so the AESO directed the transmission and distribution system operators to perform controlled load shedding of about 250 MW for about 20 minutes to rebalance supply and demand until the system was stabilized

My observations, but please also listen to the AESO’s explanation to draw your own conclusions:

• the Jan 13, Apr 3, and Apr 5 events were all supply adequacy problems.  A power system with sufficient dispatchable generation capacity in reserve (reserve margin) should be able to handle forecast errors, planned outages, and generation and transmission contingencies (aka “trips”).  The Alberta system has insufficient reserve margin due to many years of policy/social preference for renewables over thermal generation and we are now experiencing the effects of over-investment in renewables and under-investment in dispatchables.

• this is not the AESO’s fault, it is the outcome of a market and policy framework designed for a different context in which economics alone were relied upon to provide resource adequacy.  The AESO is doing the best it can to manage the system within their legislated authourities, which do not include resource adequacy.  Blaming and shaming is a waste of time - the solution is policy and market design change and we should use this as motivation to address these.

• this problem is not unique to Alberta, it is happening in all jurisdictions to varying degrees.  The difference in Alberta is that we are essentially an electrical island with very little intertie capacity, so our resource adequacy problems and our over-exposure to weather-dependent resources are very visible because we cannot mask them with energy from interties to compensate for our problems, like other jurisdictions can.  We have nowhere to hide.

• this was a resource adequacy problem, not a reliability problem.  I hear the media calling this a reliability issue, but it was not, and the difference is important because it determines the solutions we need.  I’ve provided the NERC definitions of adequacy and reliability below – the language we use matters.

Adequacy – the ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

Reliable Operation – operating the elements of the Bulk-Power System within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system elements.

Pictures tell better stories than words, so here is the situation the AESO was dealing with on Apr 5th. The maroon “Capacity Available for Dispatch” line tells the resource adequacy story…

Final Thoughts

The solution for our power system problems in Alberta is market and transmission policy change, not blame and recrimination. The Alberta government is already moving down this path in collaboration with the power system agencies and industry and I hope this event provides the motivation to expedite those efforts.

Here is a related article on adequacy, reliability, capacity, and energy you may find helpful: Power Words

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“It is the responsibility of leadership to work intelligently with what is given, and not waste time fantasizing about a world of flawless people and perfect choices.”

Marcus Aurelius’s wise advice from centuries ago is very relevant to today’s policy driven power system energy transition that has jumped to solutions before carefully understanding our current state and defining the problems we need to solve.

While aspirational thinking can help drive significant change, policy making based on wishful thinking is technically and economically ruinous. While we all wish that we had perfect connectivity between all power systems everywhere to share all renewable energy all time, and wish that we wouldn’t have shunned nuclear generation decades ago based on irrational fears and assumptions, and wish that a system comprised of only renewable energy and storage could meet all our electricity needs with perfect adequacy, reliability, and affordability, this is simply not the reality of our power systems, and energy transition policies must acknowledge this.

Grids Are Complex

A power system is a textbook example of a complex system. Complex systems have numerous components that interact with each other in non-linear and unpredictable ways, and they are dynamic, difficult to understand and predict, and often exhibit emergent properties that cannot be explained by the behavior of the individual components of the system. Making changes to complex systems usually results in unanticipated outcomes because the interactions of the components cannot be fully predicted, so changes must be planned and managed incrementally and carefully. In addition, simple solutions usually do not work well for complex systems, which means that the solutions typically favoured by politicians usually do not have the desired outcomes.

Unfortunately, politicians and policy makers have not understood the complexity of power systems in policy development and have been taking a simplistic, “one size fits all” approach in their well-intended desire to decarbonize, while simultaneously encouraging the electrification of everything. Policies mandating specific solutions and setting arbitrary timelines with no consideration of the complex systems they are changing is a flawed approach that has led to both technically and economically inefficient outcomes that we are now seeing in the form of compromised resource adequacy, reliability, and affordability in power systems across the world. California and Germany are prime examples.

FERC, NERC, the Regional Entities, and the ISOs and RTOs are all warning of both resource adequacy and reliability risks of varying degrees as a result of misguided policy decisions across North America. The unfortunate reality is that these problems are self-inflicted. Policy making that has been all about firing, not aiming, has eroded the resilience and reliability of our power systems that were built over decades of trial, error, and continuous improvement by thousands of power system professionals across the globe.

Stop Firing, Start Aiming

Mistakes have been made, but its never too late to change course. The story is still being written and policy makers can choose a different approach - they can choose to aim before continuing to fire. Instead of dictating solutions and timelines, policy makers can choose to define the long-term outcomes they want and then defer to our many power system operations experts, engineers, and regulators to determine how best to reach these outcomes in ways that make technical and economic sense for each unique power system.

Policy makers can choose to accept and understand both the limitations and opportunities presented by our 100+ year old power systems and give the power system experts the time and space to define the problems we need to solve for each unique power system, develop customized solutions and plans that meet the policy objectives, and let the plans determine the implementation timelines that make physical and economic sense while maintaining resource adequacy and reliability. Use our experts to aim before continuing to fire with policy weapons.

Fortunately, we have an example of a government doing just this in my home province of Alberta, Canada. Our current government, led by Premiere Danielle Smith, is pushing back against infeasible federal policy aspirations and deferring to Alberta power system experts to help evolve our electricity policy framework. The Alberta government is taking advice from the Alberta Market Surveillance Administrator, the Alberta Electric System Operator, the Alberta Utilities Commission, and industry technical experts to make electricity policy changes that will enable the transition of Alberta’s power system in a reliable and affordable manner. In my opinion, this is how sensible policy should be developed, and other governments should take note.

Final Thoughts

Climate change will relentlessly march on regardless of our wishes, rhetoric, and preferences, so we need to choose our response wisely.

As Elon Musk said, “physics is the law, and everything else is a recommendation”. Policy makers would be wise to accept this advice, stop firing the policy bazooka, and defer to the experts to develop technically and economically feasible plans and timelines to decarbonize our power systems and set us up for another 100+ years of power system success.

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In Alberta, the provincial government has initiated the process of wholesale electricity market reforms. Since we will likely soon be hearing a lot more economist jargon monoxide, I thought it might be helpful to explain some key market concepts we will be hearing and reading about in the near future.

Key Electricity Market Concepts

Marginal Cost of Electricity - the change in total cost (fixed plus variable costs) that a generator incurs to produce one more MWh of electricity to meet the next increment of demand. Measured in dollars per megawatt-hour ($/MWh).

Real-time Energy Only Market - a simple wholesale electricity market design that determines the economic dispatch order of generators to meet electricity demand minutes in advance of actual electricity delivery. Generators earn their revenues solely for the energy they provide, and there is no compensation provided for capacity. The Texas and Alberta markets are real-time energy only wholesale electricity markets.

Day Ahead Market (DAM) - a market design in which generators commit to providing energy to meet forecast demand the day before the operating day. In most day ahead markets, generators provide both energy and operating reserves which are co-optimized by the system operator to meet forecast energy and reliability requirements. A DAM design provides improved operational certainty and price stability compared to a simple real-time energy only market.

Security Constrained Economic Dispatch (SCED) – a mathematical/algorithmic process to determine the most cost-effective dispatch of generators taking into account energy requirements, generator marginal costs, system operating reserve requirements, generator operating characteristics (such as ramp rates), and transmission constraints.

Locational Marginal Pricing (LMP) - the marginal price for electricity at a specific location on the transmission system the takes into account generator marginal costs, transmission constraints, and transmission losses. Measured in dollars per megawatt-hour ($/MWh).

It is important to note that SCED and LMP are related but different. SCED is a system-wide optimization approach that strives to find the most economic dispatch of generation that ensures system reliability and efficiency, while LMP is a local energy cost optimization approach that strives to find the most cost effective electricity price at a specific location taking into account local transmission constraints and losses. SCED is typically an input the system operator uses to calculate LMP.

Co-optimization - the simultaneous mathematical optimization of energy and operating reserves in electricity markets to produce the optimal blend of energy and reserves for each generator dispatch order. Co-optimization typically takes into account both SCED and LMP.

Financial Transmission Right (FTR) - a financial instrument used in markets that use locational marginal pricing (LMP) that allows a market participant to hedge against the risk of transmission congestion. An FTR provides its owner the right to collect or pay the difference in the LMP between two locations on a transmission system for the time period defined by the FTR. FTRs are unidirectional (they only apply in one direction) and are a contract between a market participant and the system operator that is measured in MW and obtained through auctions held by the system operator.

Economic Withholding - I prefer the Alberta Market Surveillance Administrator’s definition: Economic withholding by a market participant is an offer strategy in which available capacity is offered to the power pool at a price sufficiently in excess of its short-run marginal cost and opportunity cost such that it is not dispatched and the pool price is raised as a result.

Physical Withholding - taking one or more generating units offline, or derating them, in order to reduce the available physical capacity of electricity or operating reserves in the market with the objective of raising wholesale electricity prices and/or operating reserve prices.

Parting Thoughts

These are terms you will likely be hearing over the next couple of years as changes to the Alberta wholesale electricity market are discussed and debated, so hopefully this cheat sheet helps you better understand what you will be reading and hearing.

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As our power system resource mix evolves to meet decarbonization policy objectives, it is important that people know some of the key concepts associated with reliability to understand the impacts that power supply changes are having and will continue to have on power system operations and reliability.  I suggest there are four key concepts that everyone should be familiar with to properly understand the changes our power systems are undergoing, and the intent of this article is to explain these fundamental concepts.

Resource Adequacy & Reliability

I often see resource adequacy and reliability being equated, but they are actually different concepts.  Here are the formal NERC definitions for what are commonly called “resource adequacy” and “reliability”:

Adequacy – the ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

Reliable Operation – operating the elements of the Bulk-Power System within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system elements.

Adequacy (aka resource adequacy) means having enough supply to meet demand at all times while reliable operation (aka reliability) means being able to operate the power system within all technical parameters under all conditions and contingencies.  So, you can have a system with adequate resources that isn’t reliable, and you can have a reliable system without adequate resources.  What we want is a system that is both adequate and reliable. 

The recent Alberta supply shortfall near miss in mid-January 2024 was a good example of a power system that was operating reliably but came dangerously close to having inadequate supply.  Many observers characterized this as a reliability problem, but it was actually a resource adequacy problem.

A very important point to understand is that in jurisdictions with deregulated electricity markets, which are the ISO/RTO regions, the ISO/RTO is only responsible for reliable operations, not resource adequacy.  I’ll explain.

ISOs/RTOs are responsible for ensuring the “reliable operation” of the power systems they control, in accordance with NERC reliability standards.  However, while the ISOs/RTOs monitor resource adequacy and they do all they can to notify their market participants of the supply adequacy of their systems, they are not responsible for setting resource adequacy requirements. In addition, the NERC mandatory reliability standards do not mandate resource adequacy or specify a generation reserve margin.

Governments (federal, provincial/state, municipal) determine resource adequacy requirements and desired generating resource mix objectives through public policy, or lack thereof. In market-based systems (ISO/RTO areas), it is up to private investors to build the right types of generation at the right times in the right places on the power system to provide sufficient resource adequacy. This is why electricity market design and accurate and timely price and locational signals in wholesale electricity markets are so vitally important. 

In fully regulated, vertically integrated jurisdictions, like the Canadian provinces of BC, Saskatchewan, and Manitoba, vertically integrated utilities plan, own, and operate generation, transmission, and distribution in accordance with public policy objectives and are responsible for both resource adequacy and reliability.

Capacity & Energy

I often observe confusion between energy and capacity when people write about or discuss the power system. To clarify, here are the definitions of electrical energy and capacity:

Energy - the generation of electric power by a device over a period of time. Typically expressed in kilowatt-hours (kWh) or megawatt-hours (MWh).

Capacity - the maximum output that a generator can produce. Typically expressed in kilowatts (kW) or megawatts (MW). This is the rating of a generator and system operators depend on capacity being available for dispatch to ensure reliability and supply adequacy.

Renewable generators (wind, solar), have very low capacity value from an operational perspective because the system operator cannot depend on their capacity being available at all times and they cannot be dispatched, so they are viewed almost exclusively as energy resources. Dispatchable generators (gas and steam turbines, hydroelectric generators) provide both capacity and energy because the system operator can depend on the availability of their capacity as well as the energy they can provide.  We need both capacity and energy, but it is dispatchable capacity that system operators depend on for both resource adequacy and reliable operations.

Several Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) have rigorous processes for “accrediting” generator capacity values to ensure they understand the actual capacity available in their control areas for resource adequacy planning and operational reliability purposes.  The NY ISO accreditation process is a good example of the rigour that system operators apply to understanding the capacity they have available in their operational footprint. 

Here's a good overview of energy and capacity from ISO New England: Capacity vs Energy

Final Thoughts

Understanding these four concepts is essential for understanding power system planning and operations.  Unfortunately, it seems these concepts have not been well understood by many policy makers over the past few years and this has resulted in a variety of negative impacts to power system resource adequacy, reliability, and affordability.

For those interested in more than these four power system terms, below is a link to the NERC glossary of terms used in the mandatory reliability standards.  This is the “go to” for all power system definitions. In addition, EPRI provides a number of excellent resources on resource adequacy that can benefit all policy makers and power system planners, so I’ve provided a link below.

NERC Glossary of Terms

EPRI Resource Adequacy Information

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From Complicated to Confusing

Prior to the mid-1990s, power systems were run by vertically integrated utilities that owned and operated all of the generation, transmission, and distribution assets in their service territories. They were monopolies that were regulated by state or provincial regulatory agencies and they planned the expansion of their power systems to meet demand and ensure reliability through an economic balance between generation and transmission. There were also electric cooperatives which were coordinated groups of utilities, but the same general approach applied. While this arrangement was complicated, most people could understand the basics. This all started to change in the mid-1990s.

In 1996, FERC issued Order 888 which initiated the deregulation of the power industry, or “restructuring” as it is often called. The objective was to reduce the monopoly power of the integrated utilities and enable competition for the supply of electricity (competition between generators) to keep costs low for consumers. Transmission and distribution remained regulated because they were/are considered to be “natural monopolies” that do not facilitate effective competition. Order 888 introduced the Independent System Operator (ISO) construct to oversee the operation of power systems and wholesale electricity markets. Deregulation was further augmented by FERC Order 2000 in 1999 that saw the introduction of the Regional Transmission Organization (RTO) construct that was very similar to, but broader than, an ISO. Participation in ISOs and RTOs was (somewhat) voluntary and some regions chose to continue as vertically integrated utilities.

Deregulation took the planning, operation, and oversight of the grid from complicated to confusing. It also dispersed accountability for reliability across several different entities that play different roles to ensure reliable operations and effective long term planning. The current North American grid contains a blend of traditional vertically integrated utilities, ISOs, and RTOs with coordinated operations across vast geographic areas.

To try to explain this, I’ll first start with the physical arrangement of the grid in North America and then turn to the organization of the entities that oversee and manage the grid.

The Interconnections

The power systems in Canada and the US are organized into four physical regions called “Interconnections” that enable the coordination of the entities within each region:

• The Western Interconnection

• The Eastern Interconnection

• The ERCOT Interconnection

• The Quebec Interconnection

Within each Interconnection, all entities (generators, transmission providers, and distribution providers) are “synchronized” which means that they all operate at the same frequency (60 Hz) and their voltage and current waveforms are all “in phase” with each other. This means that the operation of all entities within an Interconnection are fully coordinated at all times. They are literally on the same wavelength.  

However, while all the entities within each Interconnection are synchronized with each other, the Interconnections themselves are not synchronized to each other.  They are “asynchronous”, which means that while each Interconnection operates at the same nominal frequency of 60 Hz, the Interconnections are not “in phase” with each other and their voltage and current waveforms are not synchronized.  For this reason, the transmission lines that connect each Interconnection are asynchronous high voltage direct current (HVDC) lines and not alternating current (AC) lines. It is helpful to think of each Interconnection as an “electrical island” and the HVDC lines that connect them as “electrical bridges” between each island. The HVDC lines connecting the Interconnections are shown in the map below. 

The Interconnections evolved over time as the power systems across North America expanded and as system operators recognized the need to electrically separate the Interconnections when the synchronized areas started to become too large to reliably operate. Here is a summary of the evolution of the Interconnections from the book The Grid: Biography of an American Technology by Julie A. Cohn:

As the energy transition progresses, there are many recommendations and calls for increasing the east-west transmission capacity across Canada and the US to share renewables and other generating resources across regions. While this is a great concept in theory, the electrical separation of the Interconnections introduces significant technical complexities and associated costs that must be considered.

FERC and NERC

FERC and NERC are the two US federal agencies the oversee the North American electricity industry and establish reliability standards and operational requirements for the North American grid.

FERC, the Federal Energy Regulatory Commission is an independent US federal agency that regulates the interstate transmission of electricity, natural gas, and oil, which includes oversight of reliability and energy markets. FERC oversees NERC and directs it to take actions by issuing Orders.

NERC, the North American Electric Reliability Corporation is overseen by FERC and is an international regulatory authority that develops and enforces mandatory reliability standards, assesses seasonal and long‐term reliability, monitors the bulk power system, and educates, trains, and certifies industry personnel. NERC’s authority spans the US, Canada, and the northern portion of Baja California, Mexico.

The reliability standards established by NERC are implemented and enforced across all North American power systems, including the Canadian provinces. NERC does not have legal jurisdiction in Alberta, but Alberta adopts and enforces applicable NERC standards as Alberta Reliability Standards.

To summarize, FERC broadly regulates electricity, natural gas and oil while NERC exclusively regulates electricity under FERC’s oversight.

The Regional Entities

NERC regulates and monitors the reliability of the North American grid in partnership with 6 “Regional Entities” that are roughly geographically aligned with the Interconnections. The Regional Entities (RE) monitor the ISOs/RTOs and integrated utilities in their regions and work with NERC to enforce the mandatory reliability standards. The REs are:

• Midwest Reliability Organization (MRO)

• Northeast Power Coordinating Council (NPCC)

• Reliability First (RF)

• Southeastern Electric Reliability Council Reliability Corporation (SERC)

• Texas Reliability Entity (Texas RE)

• Western Electricity Coordinating Council (WECC)

Within their regions, the duties of the REs are to monitor and enforce compliance with mandatory reliability standards, oversee reliability planning and operational performance assessments, and analyze regional system events and disturbances to share learnings and recommend operational improvements.

The combined objectives of NERC and the REs are:

• clear and consistent guidance across the Interconnections

• sharing information, knowledge, and resources across the Interconnections

• developing and sharing harmonized communications across the Interconnections

• supporting innovation, initiatives, and the sharing of best practices across the Interconnections

The ISOs and RTOs

Within each Interconnection, there is a blend of regulated vertically integrated utilities and deregulated wholesale markets. The deregulated wholesale markets are overseen by Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs). The functions of the ISOs/RTOs are to facilitate open-access to transmission, operate the transmission system, and oversee and operate wholesale electricity markets. Currently, over 60% of North American electricity is provided by ISO/RTO regions and market participants in ISO/RTO wholesale markets include both independent power producers and integrated utilities.

When FERC initially kicked off deregulation in 1996 with FERC Order 888, the concept of the ISO was born and 7 ISOs were eventually established. To further encourage competition in 1999, FERC issued Order 2000 that established the RTO concept that was intended to aggregate the smaller remaining transmission entities into larger regional system operators. This resulted in the creation of 2 RTOs.

So what’s the difference between an ISO and an RTO? They have very similar responsibilities which include providing non-discriminatory transmission access to market participants, power system operations, and wholesale market operations, but RTO operations typically span multiple states while ISO operations are typically within a single state or province. The key differences between ISOs and RTOs are as follows, but there is a lot of grey and overlap between the two:

Scope of Operations

• ISOs typically operate within a single state/province or a portion thereof and manage transmission and wholesale market operations within their designated areas.

• RTOs cover larger geographical areas, often spanning multiple states or regions and manage transmission and wholesale market operations across broader territories, facilitating coordination and optimization over a wider area.

Reliability

• ISOs are responsible for ensuring the reliable operation of the power grid within their designated areas. This includes managing the flow of electricity, maintaining grid stability, and coordinating the operations of generation and transmission assets.

• RTOs have broader responsibilities that encompass not only grid operation but also regional transmission planning, market administration, and coordination among utilities, generators, and other stakeholders.

Regulatory Oversight

• ISOs are subject to regulatory oversight by federal and/or state and provincial agencies.

• Like ISOs, RTOs are also subject to regulatory oversight, but their broader geographical scope often involves coordination with multiple regulatory bodies at the federal and state levels.

The current ISOs and RTOs are as follows:

Independent System Operators (ISOs)

• The Alberta Electric System Operator (AESO)

• The California Independent System Operator (CAISO)

• The Electric Reliability Council of Texas (ERCOT)

• The Independent Electricity System Operator (IESO) in Ontario, Canada

• The Independent System Operator of New England (ISONE)

• The Midcontinent Independent System Operator (MISO)

• The New York Independent System Operator (NYISO)

Regional Transmission Organizations (RTOs)

• Pennsylvania-New Jersey-Maryland Interconnection (PJM)

• Southwest Power Pool (SPP)

Final Thoughts

So, here’s roughly how the “org chart” looks from a reliability perspective:

Hopefully this overview left you more informed than confused. There are many additional nuances, such as Balancing Authorities, Reliability Coordinators, and state and provincial electricity regulators, but I think the organizational aspects of the North American grid I’ve described in this article provide the basic concepts you need to decipher what you typically hear and read about the grid.

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