The Polar Vortex: Was Gas at Fault?

On a frightfully cold Friday afternoon this past January, at the height of the infamous "Polar Vortex," grid system operators at PJM faced a daunting choice.

Recent weeks already had witnessed widespread outages at electric generating plants across the Northeast US, causing power reserves to drop to astonishingly low levels, as if in tandem with the falling mercury.

And now loomed the three-day Martin Luther Day weekend, meaning that natural gas turbine generators would need to take action immediately to line up gas pipeline fuel deliveries for the coming Tuesday, the next workday, before natural gas commodity markets went on virtual vacation for the holiday, as gas commodity markets are known to do over the weekend.

PJM pondered: should it commit those gas-fired turbines to purchase the fuel needed to be able to run at high capacity all weekend long - Saturday, Sunday, Monday, when not really needed - so as to assure regular operations come Tuesday? Doing so would waste milllions of dollars in ratepayer money. But that's what PJM decided to do.

As was recounted by Michael Kormos, PJM's executive v.p. for operations, who spoke at a conference held at the Federal Energy Regulatory Commission (FERC) in April, "We felt we had no choice.

"Unfortunately," said Kormos, "we were required to commit them, based on the best information we had, based on the fact of the forced outage rates we had seen in the previous cold weather."

But the cost to ratepayers was huge.

"In some cases," Kormos said, "the units told us they had to run Saturday, Sunday, Monday, to be there on Tuesday. We had to burn them 24 hours straight, all of it out of market.

"That caused us significant uplift costs ... . We tried to back out of some of these [commitments], and the gas balancing costs at some of these units were just phenomenal.

"While I appreciate you [FERC] moving the Gas Day, and I think that will help to some extent, we'd like them to work weekends."

Kormos was alluding to the oft-cited fact that in today's energy industry, the electric power and natural gas sectors are hopelessly out of sync. The power industry runs 24/7, driven in many cases by centralized regional wholesale markets that feature computer software that allows utilities, generators, and power marketers to turn on a dime - to commit, dispatch, or redispatch over intervals so short as to be measured in seconds. By contrast, as some see it, the natural gas sector keeps to "bankers' hours," with buying, selling, and contracting performed over the telephone: by rolodex, so to speak, rather than by algorithm.

Even FERC Commission Philip Moeller has weighed in:

"It is part of the frustration that many generators have felt ... the challenge of the gas trading day essentially ending at 5 pm, and not going through the weekends."

So the question arises: Are natural gas industry contracting and trading practices too antiquated to allow gas-fired generation to participate easily to today's world of regional power markets? Was natural gas at fault in last winter's Polar Vortex?

To explore further, Public Utilities Fortnightly spoke recently with Frank Brock, senior energy market specialist at ICF International.

Fortnightly: We seem to be transitioning to a gas-dominated supply portfolio in power generation, but with fuel delivery tied to an insecure, interruptible, just-in-time regime. How did we get to this point so quickly, without any warning?

Brock: Back in the early 1990s, I was doing some work for DOE and NREL [National Renewable Energy Laboratory], largely focused on utility-scale renewables. Natural gas made up a relatively small percentage of power generation at that time. But our analysis showed that wind and other renewables were going to have pretty tough competition from gas-fired generation, both marginal costs and capital costs. And that was before fracking!

But here's another conversation I had early in my career, with a major manufacturer of gas turbines. They had come to ICF's predecessor in consulting and had said to us,

"We've got orders for many tens of gigawatts of gas turbines to be delivered during the next couple of years. Do you think that's going to have an impact on natural gas prices?"

Well, of course it did. And with conventional natural gas production declining, gas prices started rising. The market started looking for solutions, such as LNG imports. And a few LNG terminals were built.

But what won in the end was shale gas, through a lot of hard work, plus new technologies, such as directional drilling, and fracking [hydraulic fracturing].

But the funny thing is, all of that came to fruition just as the great recession hit.

Fortnightly: So the recession and declining demand in effect masked the shale gas revolution, keeping it hidden for a number of years?

Brock: You started to see really significant gas volumes coming to market just as demand got hit by the recession, plus the record warm winter in 2011-12, making for a one-two punch. That left us additionally long on supply. It was not until the last two years of so, and with this year's exceptionally cold winter, that the market flipped. But we're still not getting anywhere near the pre-recession prices of $8 to $9.

Fortnightly: Is this dash to gas sustainable, even when we are seeing so many generating plant outages related to lack of natural gas fuel?

Brock: The problem is really a transportation issue and not a supply issue.

What you saw this past winter was that in supply-rich areas, most prices stayed in the $5 ballpark. An example is was Dominion Southpoint, a big pooling area for gas from the Marcellus shale gas formation. And that's even when prices at New York City and Algonquin in New England were soaring to new record levels, over $100 per MMBtu, in some cases.

This huge spread in prices is an indication on constraints in pipeline capacity. The vast majority of gas-fired generators rely on interruptible pipeline service [IT], not firm. By contrast, natural gas LDCs [local distribution companies] contract for firm capacity, based on a peak winter load day, called a "design day," Based on maybe a one-in-thirty-year cold weather event.

Fortnightly: Why do gas-fired generators rely on IT for pipeline fuel delivery? Isn't that dangerous for reliability?

Brock: First, gas-fired turbines just don't have a way to pass along the cost of that firm capacity. And second, metrics for reliability in the gas industry are much different than in the power industry.

The equivalent in the gas industry to an electric outage or blackout is called a gas "re-light" situation. This would be a catastrophic event. Gas customers like hospitals and nursing homes with health and safety obligations. If you lose heat, your pipes can burst. And if the gas system loses pressure you have to start shutting off valves to avoid air incursion, which could cause an explosion.

Fortnightly: Why don't we see new gas pipeline construction in the Northeast, to make transportation more accessible to gas-fired generators? What does it take?

Brock: Under FERC regulation, gas pipelines will construct new capacity only as necessary to serve firm load. The mechanism for that now is a benchmark of 10-year long-term firm contract - that's a FERC-imposed imposed benchmark of due diligence to prove need. FERC wants to see a large percentage of capacity reserved for such long-term firm.

Now in Florida, you do see gas-fired generators who buy firm pipeline service. Florida Power & Light issued an RFP in 2012 for more pipe capacity, and six to seven months later they selected two winning bidders. Both pipelines are due to go into construction in 2016, and be online in 2017.

Contrast that to getting new pipe built into the Northeast and New England. It was 2010 when Algonquin first floated the idea of AIM - the Algonquin Incremental Market Expansion. They held several nonbinding open seasons but had very little interest. It was not until last year that they got 340 Mcf per day committed from LDCs, but there were no firm service commitments from gas-fired generators.

Fortnightly: What about FERC's new initiatives to improve gas/electric coordination, such as the NOPR (Notice of Proposed Rulemaking) announced in March to rethink the timing of the Gas Day?

Brock: There were a couple of campanion orders with the March gas NOPRs - one dealt with how the pipes post info on capacity release.

As for changes to the Gas Day, NAESB will have to resolve that, talking with shippers, LDCs, gas generators, and stakeholders. But there's push back from LDCs and also from western pipelines. You're putting a cost burden on LDCs by changing their gas scheduling. And gas pipelines worry that if the Gas Day shifts, you might just be pushing the problem to the West.

And moreover, the FERC initiatives attempt to make the best with what infrastructure we have today. There's no incentive for new pipe capacity to be built. So the headline is that FERC is focusing on day-to-day operations, and not incentives for pipeline construction.

Nevertheless, if you look carefully at the FERC NOPRs of late March, you will see a reference to combined contracts - having multiple shippers pair up in a single contract, but there's no clear guidance presently on how that would work. For example, one of the things that would do would be to allow a pairing of capacity contract between an LDC and a generator. Then, if one yields to the other, the other can have the capacity without going to the release market, as gas use peaks in summer for electric generation, and then again in the winter for heating load.

Fortnightly: At the technical conference at the FERC last month, one of the witnesses suggested that we need computer-driven, regional system operators for natural gas pipeline and commodity services. Sort of like an ISO or an RTO for gas. What's your take on that?

Brock: The gas industry has been moving incrementally toward a more real-time-based system for information sharing as well as for trading of released capacity. But note a couple of important things.

First, if you had some massive reorganization of the system, who is going to front the cost of that? What you hear from LDCs and pipelines is - the gas system works reliability for us, the scheduling system works for us very well. Why then, should we front the cost for adjustments to this system to meet the needs of power customers - gas-fired generators?

Fortnightly: So there's no chance that gas marketing and contracting will go real-time, 24/7?

Brock: What's real-time for the gas industry is much different than real-time for power.

Gas in pipelines travels at about 10-15 mph. If you want to impose a huge change in flows on a gas pipeline in a very short time, you risk reducing pressure on the system. It's called "drafting." You're sucking the gas out of the system and it's not being replaced at the supply end.

In fact, we had an example of that sort of thing just this past January. Natural Gas Pipeline Co. of America issued a critical notice posting. A gas-fired generator in illinois was taking more gas than it was entitled to. It was "drafting." That caused a pressure drop on the system. The pipeline then looked at their real-time monitoring and found that the generator was taking too much, called them up, and said, in effect, "stop that now."

It was a bit of public shaming by putting this notice on the bulletin board. I don't think I've ever seen that before, though I've heard of them anecdotally. These sort of events have certainly occurred in the past, but in this instance NGPL wanted to send a clear signal to shippers to follow the rules.

For sure, you don't want to be the one who caused the system to collapse.

---

Bruce W. Radford is editor/publisher of Public Utilities Fortnightly. Contact him at radford@pur.com.

Image (c) Can Stock Photo