I took a look at the AESO site and it looks like they are really taking a blank slate approach currently . There is a lot of variation on how the markets are run , so I can really only talk about mine . This is sold as a move to ensure adequate supply while we phase out coal and bring on large volumes of renewables while reducing price volatility This is pretty much why my ISO does it . Adequate supply , reduction of power market price volatility , and the ability to send locational price signals to get generator investment where it is actually needed . 1 How far into the future is capacity procured ? We run a capability period auction summerwinter at least 30 days before the period starts . For this market , all load serving entities have to put in load bids for their share of the forecasted peak load of the capability period and the generators bid their proven generation against it . The money from the loads pays out the generators for this auction . We also run a monthly auction and a spot auction that , essentially , fine tune the results . 2 Do they have controls to ensure adequate capacity clears for a reasonable cost ? I recall reading issues with a MISO auction but didn ' t really understand the full issue and remedies . I assume we have something since we tend to have pretty robust market design , but I don ' t know that we have ever actually experienced a capacity shortfall . I know we have individual zones that have been short which caused price increases . These worked as expected and some mothballed plants returned to service refitted on natural gas . This question would rely on me interpreting our capacity manual which is about as easy of a read as a tariff , so I don ' t know that I ' d get the mechanisms correct . 3 How does this impact the realtime energy market and bidding ? Are their restrictions imposed on sellers of capacity IE must offer in at cost ? In our market it drives energy bids down . The idea is that the capacity market is supposed to pay for the fixedcapital cost kind of stuff like the land the generator is built on , the financing for the construction and equipment , etc . Since these costs are covered , your energy cost should reflect only your variableoperational costs like fuel and staffing . While a generator could bid higher , it ' s putting itself at a disadvantage from being selected in the market . Additionally , our energy market pays out on the next marginal MW structure , so every generator in the bid stack is being paid the same clearing price based on whatever the bid of the next marginal unit is . This also encourages generators to not only bid their real costs since you ' re paid the market cost regardless of bid , if selected but to also encourages investments in efficiency so they can increase the spread between their bid and the market rate . As for restrictions , for us it ' s more about obligations . Before I can talk about the capacity aspect , I should explain our day ahead market . In order to solve our day ahead reliability requirements we have a separate market that uses , essentially , the same processes as realtime to solve the dispatch on an hourly basis . This is a binding market with its own settlement . Generators that got a day ahead award automatically have their awards entered as bids in our realtime market at prices that are automatically economic . If a generator fails to deliver in realtime what it was awarded in the day ahead , they have to pay for the replacement energy in our realtime market . So in terms of the capacity market , any generator that has a capacity award is required to bid in our day ahead market . If they aren ' t selected in the dayahead , they can have their bids automatically converted to realtime bids for the same values . We would expect to know if we are going to be running tight on capacity day ahead , so the expectation is that we have already secured sufficient generation in our capacity market and that it will be bid into that market . If for some reason we fail to forecast our dayahead load correctly , during our realtime market those capacity backed generators should still have bids in the system and be dispatched economically . If they didn ' t have a bid in , we can still order them on for capacity and they will go through a settlement process to be made whole on actual costs . We also treat GTs slightly different in the day ahead . Instead of an actual energy award , we post how many MWs of GT capacity were used for the day ahead solution . It ' s up to the GTs to bid into our realtime market as economically as they think is sufficient to secure a portion of those MWs . Of course , in the real time market , we will often need more or fewer MWs then the predicted GT capacity so it tends to work out better volatilitywise to limit their energy awards to realtime . 4 Functionally , how does a capacity market actually reduce volatility in the realtime market ? Securing capacity in advanced shifts our energy markets closer to the actual cost of the energy itself instead of the means in which it ' s produced . By offering generators a means to cover their capital costs , we get a more consistent energy bid out of the generator . Ideally in an efficient energy market you ' d expect the price to be reflective of the actual price of the energy . Why would you choose to distort an energy market to cover the costs of what is really a capital project market ? Overall , doesn ' t it make more sense to have two efficient markets designed for their actual goals instead of distorting one market to solve the issues of another ? Without a capacity market , a generator needs to recoup its fixed costs through the energy market meaning they are less competitive then established generators . Essentially , an older inefficient generator that ' s paid off a lot of fixed costs may be constantly selected over a newer generator that ' s far more energy efficient , but is still paying off financing . This means , in the long run , we are not encouraging new investment or upgrades in efficiency , and are instead rewarding established players . Any other info would also be appreciatedAs a real time operator , my only interactions with capacity tend to happen on peak days . Our concerns are pretty much limited to Can we order capacity backed generators on ? and How much of our exports are backed by capacity and cannot be curtailed ? Also , by taking the longterm view in the energy market of dispatching on actual energy while running a cap market , we have seen the following trends in our market since 2000 SO 2 rates down 92 %, NOx down 79 %, and CO 2 down 42 % despite building around 12 , 000 MW of new generation in this period . This means generator companies were confident in their ability recoup costs on newer more efficient generation , and their costs for upgrades to existing generators to make them more fuel efficient . 80 % of that added generation has been added in our highest demand regions . This means the locational price signals are working to get new generator where it is actually needed .