Preview: Gas Executive Roundtable

In the midst of one of the largest generation build-outs in America’s history, natural gas prices are plummeting at a pace that has taken even the experts off guard. Some electric utilities have already joined the “dash to gas,” but others are more hesitant, waiting to see what natural gas prices will do long-term. In an industry that largely has been driven by cost reliable forms of generation such as coal and nuclear, natural gas plants are being planned in abundance, but with a stigma of hesitation still lurking.

In a recent interview, Associate Editor Lindsay Morris discussed the forecast for natural gas-powered generation with four leaders in the field: Kevin Geraghty, vice president of power generation at NV Energy (NYSE: NVE); Kevin Needham, executive vice president, Power Market & Strategy, Kiewit Power; Bill Wince, vice president of business development for Chesapeake Energy Marketing (NYSE: CHK); and Brian Gutknecht, marketing general manager, thermal products for GE Power & Water.

The U.S. Energy Information Administration (EIA) expects the natural gas portion of electric generation to increase from 24 percent in 2010 to 27 percent in 2035. Is this a modest or accurate estimation, and why?

Brian Gutknecht: We believe that EIA’s forecast is more modest than what we are predicting. In the short-term, with the EPA (U.S. Environmental Protection Agency) regulations, and much higher gas capacity factors driven by low gas prices, we believe there will be a rapid increase in gas generation. In some regions, we’re seeing gas combined cycles dispatching ahead of coal plants. So we predict 30 percent gas generation by 2015 and we believe that in the medium term, we’ll start to see national CO2 pricing driving further gas pricing, and we believe there will be low natural gas prices persisting and continuing to contribute to generation, and we’ll see it climb to 35 percent by 2020.

Kevin Needham: We agree with the previous statement. This is a modest projection. There are going to be significant retirements between now and the time frame referenced, and at this time, the only form of generation that’s easy to permit and build is natural gas generation. Those percentages are going to be potentially significantly higher than what EIA is estimating.



Kevin Geraghty: We believe that those numbers are a little understated, but probably not overwhelmingly so. From a utility’s point of view, there are still a lot of things that have to happen before you can believe the growth is going to be much more than that. One of the big ones is obviously carbon. The introduction of carbon in the later part of this decade will seriously inhibit the development of combined cycles. Also, there are lower-cost alternatives to combined cycles, as the states really look at demand-side management, renewable portfolio standards, and on a national level – clean energy standards. All of those things are going to inhibit too much of a rush for gas. And the reality is, some of the EPA’s new rules, especially MACT and the mercury rule, weren’t as severe as predicted, and they are really not going to knock out any of the large, baseload coal plants. So the coal production numbers won’t be as severe, but we do believe the EIA number is a little understated.

Bill Wince: I think the power guys are better versed to make the predictions. We believe these numbers are too modest and know that we’ve got the gas supplies in industry to supply significant growth in power demand.



Do you sense that power generators are hesitant to switch plants to natural gas, in expectation that gas prices will not always stay at around $2.20 (gas price at time of publication)? For example, some natural gas plants that were built when gas prices were low in the early 2000s ended up running as peakers and not base load. Does this seem to be a fear that is common in the power industry, and if so, is it justifiable?

Geraghty: Most of the senior executives and senior planners at a regulated utility have experienced the volatility of natural gas and that experience creates real skepticism. Utilities do not have the ability to lock in firm transportation and firm supplies [20 to 25 years] at those prices, so there’s always going to be a hesitancy that the gas curve will blow out. Most of the forwards that we use for planning are certainly not showing the fundamental change in gas supply. You’re seeing $5 gas in a couple years. Ten years out, you’re seeing $6 gas. Fifteen years out, you’re seeing $8 gas again. All those things, coupled with carbon costs, make it very difficult to just bet the bank on gas. I think there is some hesitancy toward too much baseload natural gas.

Gutknecht: We’re seeing more customers, an increasing interest in switching to natural gas, and the viewing of gas more as a destination fuel. This is largely driven, in the short-term, by the low gas price. But natural gas generation pairs so nicely with the amount of renewable energy generation that’s being added to the grid. It’s flexible, helping to ensure that you’ll have grid stability by being able to quickly ramp up or down when wind or solar is intermittent. We see a much more interest in the long-term view of increasing gas generation.

Wince: A couple things to Kevin’s comments. The infrastructure argument is problematic to me. Chesapeake and Statoil participated in a project to bring about 800 mmbtu’s per day to ConEdison (NYSE: ED)’s doorstep. There’s a prospective project being discussed now that will likely be a combination of utilities and producers to bring gas through Alabama, Mississippi and into North Atlanta. I see much more activity between the producers and the regulated utilities on the infrastructure side. Associated with that, the dynamic growth in shale gas causes the producers to have to build out additional infrastructure. In many cases, we’re bringing additional gas to a location that then allows the utilities to use their existing transport to access it. We’re entering into 10- to 20-year agreements to support that activity, so I don’t see infrastructure build-out as a problem. I see a producer community that’s willing to take out long-term transport to support their reserve development.

One other thing we see, at least in a couple of jurisdictions, since 2008, the only price volatility we’ve had is down, and that’s been modest. We’ve seen a couple of commissions that might allow utilities to take an interest in gas properties and put this interest into their rate base. I think that’s an excellent opportunity for the utilities to take price volatility out. If they can buy into the gas development at costs that are sub $5, they no longer have to worry about the volatility of prices on the NYMEX. There have been a couple of studies – Tudor Pickering came out with one in the fourth quarter about the equilibrium price of gas, which they view as $6. Anadarko had in their most recent filings, their view for equilibrium price for gas is in the $5 to $7 range. All of those are prices that can be sustained without significant volatility.

Geraghty: I think the one challenge for utilities is that during the last big boom of baseload generation, which was coal in the late ‘60s and early ‘70s, the experiences of the utilities actually owning coal was terrible. Once again, most utilities have senior executives who have seen that. I don’t know how many utilities will actually rush to owning that gas, but it’s really not core utility business to own that field. I’m not sure how many people will reach for that. If gas really does hit that price – $6 to $7 – you’re not going to see a lot of large, baseload coal go away. And gas will have to compete with renewables, which pretty much have the government picking losers and winners and bringing those into the market. Gas will get there, but it may not have as much of a dominant use as some would like to see.

Wince: I’d point you to Nucor Steel, which is not a utility, but supported their multi-billion dollar transaction in the Baton Rouge area, the Pig Iron facility, by buying interest in oil and gas properties – to your point to manage price risk through ownership of the commodity. I wouldn’t argue that ownership isn’t for everybody in the utility sector, but I think it’s one other arrow in your quiver of ways that you can manage price.

Geraghty : You’re exactly right.

Needham: When we assist utilities and IPPs with planning, we definitely hear concerns expressed about what will happen with the future of natural gas if there is a very large build-out, which was really what happened last time. Again, as utilities are forced to add renewables, particularly wind, they have to have backup in firming generation. Back to my comment about the ability to permit and build with certainty, it may be slightly uncomfortable, but their hand is really forced in some ways to go in that direction.

Wince: One of the things that we’ve done at Chesapeake is go to the commissions usually together with the LDC, and bring shale data, answer the questions they have about environmental implications of hydraulic fracturing, and give them a little more insight into the reserve base than maybe some of the published reports and criticisms. That’s been helpful. We’ve done that in a couple states, and the product of that is the approval of significant infrastructure additions in combined cycle plants.

How would potential LNG exports from the U.S. affect the price and operations of electricity from gas-fired plants?

Wince: [Chesapeake CEO] Aubrey McClendon asked the reservoir guys to work up a Lower 48 Gas Potential, and it was not restricted for infrastructure or demand, but we came up with a Lower 48 potential that doubled gas production by 2035. They used normal reserve technology there, except that E&P companies can’t count reserves further out than five years, so there are a lot of reserves you don’t see simply because they’re outside of our five-year horizon, especially shale gas. All that to say, I feel very confident that we could support six, seven, eight, maybe even 10 bcf per day of exports as an industry with very modest impact on pricing. I’ll broaden this question to say we could also support what I think will be growth in transportation, which may not be initially rapid. I think we can support that as well. With shale reserves, we no longer have to find gas; we just access it where it is now. You add places like the Utica, which we don’t have reserve studies of yet, but we feel it’s going to be another world-class gas field. We have this wonderful resource right now, and we feel very confident in our ability. We know our history in terms of price volatility. We had exceptionally large rig counts in the late ‘90s and 2000s and did not add many reserves. We’re adding reserves and volumes with rig counts today that are half to two-thirds of what has been seen previously. The technology has changed, the knowledge of the resource has changed; it’s really a completely new environment.

Gutknecht: I would echo the same point. We believe the modest export of LNG terminals will not have major implication on gas prices. A similar perspective that we believe if shale gas development is reasonably harmonized with demand increase, then you can build supply and demand in a balanced fashion and not get out of sync. We have a very similar perspective.

Geraghty: We don’t really look at that perspective as a utility. Our view still is not skeptical, but concerned about the future of the price of natural gas and any export raises that level of concern. That little bit of skepticism still hurts. Anytime there is a threat of shifting it offshore for a non-energy use, I think energy planners may be concerned by that.

Until those forward curves reflect all of this robust view of its availability, there may be a bit of a damper on planning for a massive increase in gas. Those “forwards” still don’t seem to reflect what everybody’s talking about with regards to a fundamental change in domestic gas supply. This was talked about at great length at CERA Week – that these fundamentals are just dramatically different this go around. But until those forward curves come down, it is really hard for it to impact the planning. At the same time, you’ve got a carbon curve that’s sitting out there at ’18, ’19, ’20, and it is kind of hard to synthesize those two right now.

Wince: Is $5 gas too high for you guys?

Geraghty: At $5, existing coal is still in play. You’re not going to have new coal, but at $5, coal wins. Then, when you throw on carbon and various forms of renewable energy, gas is going to have a place at the table, no doubt. There are just not many other choices out there. But at that price, if those forwards don’t show a long-term, consistent price, there’s just not going to be a dash for gas like a lot of people expect.

Utilities are hesitant to go “all in” on any one source of energy. So there will continue to be the balancing requirement. However, the instant that baseload nuclear or baseload coal goes away, renewables obviously will take a bigger piece.

To read the full version, check out the May issue of Power Engineering magazin

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