Recentefforts to synchronize the natural gas and electricity markets mark animprovement but could stand to see further adjustments, according to onenatural gas marketer speaking at the North American Energy MarketsAssociation's spring conference in Orlando.
Oneof the primary issues is how power plant operators structure their gas deliverycontracts, according to John Bogatz, senior director of marketing at TenaskaMarketing Ventures.
"Iwent to a fair amount of SPP and MISO meetings and I'd always hear, 'I can'tgenerate because I can't get the gas.' That's actually not a true statement.Gas is generally readily available. The real issue is, what interstatetransportation contract are you trying to run on?" Bogatz said during anApril 28 presentation.
"Duringthe polar vortex [in early 2014] if you were trying to flow your gas on aninterruptible, or an IT, contract it wasn't going to happen. It just wasn'tavailable," he said.
Theresult in many cases was a squeeze on electricity supply as plant operators wereforced to idle units for lack of fuel. FERC responded with Order 809, which initiated a change in thegas nomination cycle. However, even this might not fully fix the problem.
Thenew FERC order, which went into effect on April 1, changed the timing of boththe day-ahead and intraday cycles. For day-ahead nominations, the timely cyclewas bumped back 90 minutes from 11:30 a.m. to 1 p.m. CT and the evening cyclewas left unchanged at 6 p.m. CT. For intraday nominations, the first cycle wasleft unchanged at 10 a.m. CT, the second cycle was bumped back from 2:30 to 5p.m. CT and a third intraday cycle was added at 7 p.m. CT.
"Thisall started April 1 and the fact that you're in a shoulder month there's notreally good data about what this all means to our industry but I will tell youthat overall, it doesn't have a good feel to it," Bogatz said. "Theremaybe wasn't a lot of good thought put between these timelines."
Hesaid that after nominations roll into the pipeline, the pipeline then needs toconfirm what is going to flow or not, however the new schedule is allowingschedulers very little time to react.
"Weare hearing some complaints by not only our schedulers at Tenaska but alsothroughout the industry that it feels like it has elongated their day withoutmuch benefit to anyone," Bogatz said. "Again, it's early, it's onlyApril [and] it's a shoulder month, but this could be really interesting towatch when it's 22 [degrees] below [freezing] in January or 110 [degrees] inJuly."
Onthe electricity side, the new gas nomination cycles have also presented issuesfor grid operators depending on the timing of their power day.
Alreadyin the PJM InterconnectionLLC territory, and soon to come to the effective Nov. 1, a power plant will be notified at 12:30 p.m.CT whether or not they will be dispatched for the following power day
"Sowhen you jam these two together — the new [nomination] cycles and the ISO'snotification of pipeline runs — you've got a little bit of an issue here,"Bogatz said. "If you are a power plant that decides you want to have firmtransportation to back up your bids but you can say that there is very littlechance of interruption or force majeure, you can see here that when you'renotified at 12:30 [p.m. CT] you have only 30 minutes to the timely[cycle]" in PJM and MISO. In the Southwest Power Pool Inc., day-ahead dispatchnotifications are not made until 3 p.m. CT, or two hours after the timely cyclefor next-day gas.
"Thirtyminutes is not a lot of time and [your ability to react] all depends on whatkind of shop you have," he said. "Again, this is all new. We'll haveto see how the industry reacts. It tends to be efficient and things tend towork out, but we are in that rough period."
Forsome power markets, the inability to generate electricity when it is neededmost can lead to steep penalties, which is prompting some power plants toprocure firm natural gas transportation contracts.
InPJM, which adopted a "capacity performance" structure after the polarvortex event in early 2014, the costs and benefits of a firm gas transportationcontract far outweighs the penalties that can come with being unable to generatefor lack of fuel.
Bogatzsaid that penalties can approach $4,000 per MW, which means that if a 500-MWplant clears the PJM auction and is unable to generate when it is needed,penalties can total close to $40 million in one day, far outweighing theapproximate $8 million it would cost annually to procure firm gastransportation.
"[T]herehas clearly been a rush to interstate pipelines for primary receipt and primarydelivery points in PJM because of that example I just gave you," Bogatzsaid. "There has been a push [for firm capacity in PJM], which quitefrankly has a lot of the power plants in MISO and SPP that are also connectedto the same natural gas pipelines that are in PJM, they're nervous" thatall of the pipeline capacity is being absorbed by PJM customers.