Gas Executives Roundtable
Gas distributors tell how their business strategies are changing in response to issues such as higher gas prices, electric M&A, LNG, and gas pipeline development.
Big changes are coming to the U.S. natural gas industry. As upstream developers work to expand capacity for importing liquefied natural gas (LNG), midstream and downstream players are asking questions about how these new resources will affect their businesses.
For gas marketers and distributors, LNG promises to bring greater price stability. But it also raises questions about long-term contracting, storage and pipeline capacity, and marketing strategies. To discuss these issues, assembled a roundtable of senior executives at U.S. midstream and upstream gas companies, including:
Ron Bertasi, President & CEO, Southern Company Gas; Lawrence Downes, Chairman & CEO, New Jersey Resources and Chairman, American Gas Association; Don Felsinger, President and COO, Sempra Energy; Fred Fowler, President and COO, Duke Energy; and Michael Jesanis, President and CEO, National Grid USA.
Fortnightly What's the biggest issue affecting the upstream gas industry in the United States today?
Downes, New Jersey Resources: First and foremost it's price. Price obviously is affecting our customers and making clear the need for comprehensive energy legislation. Price is forcing LDCs to consider new regulatory strategies that will encourage greater efficiency and conservation, and is determining the long-term options that will be pursued.
Fowler, Duke Energy: The overwhelming issue is the need to get gas supply back into shape, so we can get prices down to a more acceptable level. There are three ways to get additional gas supply: You can build the Alaska gas pipeline, open more lands to drilling, and import more LNG (liquefied natural gas). Probably the quickest way is to get as much LNG into the country as we can, and if you look at what the super-majors are doing, they are very much promoting LNG at this point.
Downes, New Jersey Resources: But this is not just about supply. Given the challenges we've seen in the last year or two, we need greater focus on efficiency, conservation, and alternatives. We need to talk to customers about the ways they use energy and how to do it more efficiently. There are things we can and must do on the supply side, but just as important is the focus on conservation and alternatives.
A point that tends to get lost in the discussion is the fact that the North American gas resource base is capable of meeting the increase in demand, but there is a problem with access right now. We need policy action to make resources more available for sensible development.
Bertasi, Southern Company Gas: Rising gas prices exacerbate another major issue that retail gas providers face, and that is bad debt and customer credit generally. It is part of the nature of the service we provide. Customers receive the commodity on demand and then pay after the fact, and that creates more credit risk for gas providers than for many consumer goods.
Supply and demand set the gas price, and as gas prices rise, it's harder for consumers to pay their gas bill.
Jesanis, National Grid: The supply problem is related to the intersection between the gas and electricity sectors. Gas has become not just the fuel of choice, but virtually the only choice for new power plants in this part of the country. In other regions there might be greater ability to introduce more coal into the mix, or build truly dual-fuel power plants. But in this part of the country, I don't think it's possible to license a coal or nuclear plant. That means the alternatives to natural gas are things like windpower, which don't fit neatly into the grid's needs. I think gas will continue to be the fuel of choice for power generation for some time to come.
Downes, New Jersey Resources: We need renewables in the package because so much of the increased demand is expected to be for power generation. Renewables may have limitations, but that just means we need to get cracking on it right now.
Fortnightly Since the summer of 2003, much attention has been paid to expanding U.S. LNG capacity. Does progress on LNG terminals give gas retailers confidence that LNG supplies will be available when needed?
Fowler, Duke Energy: We think LNG's day has arrived, and the more we can accelerate LNG projects, the better. The two key challenges are siting import facilities and getting people aligned on supply arrangements. Projects in the Gulf Coast and on Canada's east coast are progressing nicely in terms of approvals.
Felsinger, Sempra Energy: Most people who study the problem are convinced that LNG is the long-term solution that can put prices back in a range where they will have the least impact on customers, both residential and commercial. It is hard to tell where the market is going, but looking to 2006 and 2007, NYMEX futures prices are still in the high $6 range. They don't start falling until 2008, and in my mind that coincides with the time when currently contracted LNG terminals will begin operating.
The market is telling us that we are operating at the edge of a supply/demand imbalance, and it won't take much to fall off that edge and have prices spike to $7, $8, or $9.
My view is that between now and the end of the decade we'll have between seven and 10 new LNG facilities built. That will handle demand growth, and we'd expect to see gas prices being set by LNG.
Am I satisfied with the pace of LNG development? No, I'm not, but I don't know what we can do to speed it up. The solutions are still three years out, and in the meantime we have to live with that and manage prices as best we can.
Downes, New Jersey Resources: We are not going back to the days of low prices, and without policy changes we will continue facing supply-demand imbalances.
Under any scenario, LNG will play a larger role in the country's supply picture. There's no question about that. The issues now are more related to siting and contracting. The industry is sorting through those and has made good progress. Also good progress has been made on the Alaska natural gas pipeline. Congress has provided financing incentives, and FERC has developed open-season provisions (). Now the question is who will finance it and who will build it.
As challenging as this progress has been, we must continue advocating public policies that are appropriate to develop both supply and conservation options.
Fortnightly Assuming LNG terminals proceed to construction, will pipelines and storage become the next bottleneck in the U.S. gas market?
Fowler, Duke Energy: LNG will drive the development of pipelines and storage. With the introduction of LNG, huge volumes of gas will hit different parts of the system. There's a lot of work to be done to take this gas and distribute it to where the market requires it, and it will dramatically increase the need for new storage capacity across the system.
Bertasi, Southern Company Gas: We think storage is adequate to serve existing needs today, but whether more capacity will be needed depends on the rate of growth in demand. Traditional retail demand isn't hard to predict, but what's harder is power and industrial demand. If they grow at a good clip, there will be need for more storage capacity.
Jesanis, National Grid: LNG imports lead to issues involving the diversity of delivery points. The system in New York state is quite adequate, and we've secured storage capacity to serve our domestic growth requirements. But in other parts of the Northeast, additional storage would be desirable.
Downes, New Jersey Resources: We will be able to meet demand growth without any problem, but it becomes a question of price. Pipelines and storage will play key roles as they always have and always will. We just increased our total storage capacity from 19 Bcf to 21 Bcf.
Felsinger, Sempra Energy: Substantial LNG imports over the next decade will cause a fundamental shift in how the gas business operates. Pipelines and storage are natural plays in a market driven by rising gas prices and additional LNG imports.
Pipelines will be needed to move gas from the new production basins, which will be LNG receipt facilities. In the next decade, we will need new investment in pipelines-most likely to bring gas from the Gulf of Mexico to the rest of the country. There's a lot of infrastructure there already to strip out the high-Btu substances, allowing imported LNG to meet U.S. pipeline requirements. Pipelines will be needed to connect major markets to major transportation hubs.
At the same time, there will be need for additional storage. With prices in the range we are talking about, it doesn't take much of an upset in demand or delivery to spike prices. A lot of things could happen to the LNG trade that could drive prices to unusual levels. People want to hedge their bets, so they need reserve margin to ride out major events. We are developing a number of storage projects in the Gulf area and one in upper Michigan.
Fortnightly Will we see a lot of new pipelines going over the Rockies? Where will California get its gas?
Felsinger, Sempra Energy: California will get its gas by displacement. Price impacts will not be as severe as you might imagine, because Permian Basin gas will flow to California instead of going to Chicago. However, California could avoid a lot of pipeline charges if the state can get access to more LNG.
Fortnightly What's the status of LNG-supply contracting? Are marketers and big gas customers becoming comfortable with the risks of tethering their future to the global LNG trade?
Fowler, Duke Energy: First, you have to start from the realization that the energy business from now into the future is a global business. Second, we can learn a lesson from the way we handled crude oil. We depleted our crude-oil resources quickly, and then became dependent on foreign resources. In the gas industry, I would hope we'd bring in foreign resources earlier, which in effect lets you produce your domestic resources over a longer period of time. You get more leverage that way.
Downes, New Jersey Resources: Companies are working to fit LNG into their supply strategies. All the stakeholders are learning about how the market will change, and how those changes will affect their portfolios in the future. I don't think it's clear yet what types of contract terms will be required. Are we going back to the days when long-term contracts dominated? Which players should we be dealing with? What operational issues arise with LNG? The answers to these questions will change companies' future supply strategies. This is a time of transition.
Felsinger, Sempra Energy: I see the LNG business moving forward in a rational way, as opposed to the way the merchant power industry developed. No one today is building a merchant LNG receipt facility. They are all being built on the backs of long-term contracts.
People have always been convinced that the United States is the largest gas market in the world, but until recently they weren't convinced prices could sustain the investment required to expand LNG import capacity. You need prices in the high $3 range to land LNG in North America economically. When we saw gas prices rise in 2002, the gas majors didn't believe those prices would persist. We spent a couple of years traveling around the world, trying to convince gas producers that prices in North America would support landing LNG here. It was not an easy process, but we saw a turning point at the end of 2003 and the beginning of 2004. People now are comfortable investing in the infrastructure needed to support an LNG supply chain, because they understand the North American market better, and have some assurance they can get a return with posted spot prices.
We have a fairly liquid and deep spot market, with indices that people are now comfortable selling into. For the first time, producers are signing long-term LNG contracts and accepting the risk and upside potential of selling gas at spot prices. We've signed 20-year, fixed-price capacity agreements with Shell at Costa Azul, and with BP and the Tanggu partners that will provide them with a proxy of the California border price. Shippers have alternatives today in this market. These agreements are all new, and are being developed as part of the LNG trade.
Contracts today are mostly point-to-point. But as more receipt facilities are built, we'll see arbitrage develop, where shippers will move LNG around to get better prices. They'll get diversion rights built into their contracts, and pay some amount for capacity not being used. This spot market will begin with very low numbers, around 2 or 3 percent of the market. But over time we expect that gas will follow the highest prices in the world, as oil does.
Fortnightly As the energy and utility industry has evolved over the past couple of years, how have the gas markets changed?
Fowler, Duke Energy: As we unbundled the markets, we thought electricity was moving toward unbundling. You saw LDCs signing over their pipeline capacity rights to large merchant companies who managed them in a big pool. The sophisticated merchant players were doing a good job of optimizing those resources. Now, with the consolidation of merchant players, LDCs are more involved in managing their supply, and this has resulted in a loss of efficiency. The net effect is a little less effective optimization, which means higher costs.
Over time this situation might change. Marketing players might get into the game of managing capacity rights, or a group of LDCs could get together and run them jointly. The gas market is not fully free, but it is pretty much allowed to work. If there is an opportunity, someone figures it out and goes for it.
Fortnightly Do you expect to see more consolidation in the downstream gas business?
Fowler, Duke Energy: With regard to pipelines, it would be difficult to imagine much more consolidation than we've already had. There may be some switching around of assets, but it would be hard for the major players to get past the Federal Trade Commission.
We've also seen a lot of consolidation among LDCs. We had 21 gas utilities in New England, and now we're down to four or five. We'll still see some consolidation, but the big moves have already happened.
It's difficult for a state-regulated utility to grow through acquisitions. A lot of what drives consolidation is cost synergies, and utilities usually have to cut deals with state regulators that limit those synergies. It makes it virtually impossible to pay a big premium to take someone over. That means we'll see more mergers of equals, where they don't pay a premium.
Bertasi, Southern Company Gas: I wouldn't be surprised to see consolidation in both LDC and marketing. The retail gas industry is still somewhat fragmented. On the LDC side, companies are greatly affected by regulatory posture. If state regulators don't favor consolidation, it will be harder to make it happen. But on the marketing side, you get the same synergies you get with other retail companies, and there have been acquisitions.
The large private equity firms have gotten into the electric power industry in a big way, buying companies and generating assets. There's a lot of speculation in the industry about how that will play out. We haven't seen the same thing happen on the gas side.
Jesanis, National Grid: I think it will happen in parallel with electric industry consolidation. A lot depends on what the economic drivers will be, and whether there will be regulatory pressure to reduce costs.
Fortnightly Will we see greater convergence between retail electric and gas companies? Might electric utilities acquire gas assets to grow their businesses within a back-to-basics strategy?
Bertasi, Southern Company Gas: That's a definite possibility. Many electric utilities have consolidated and cleaned up their balance sheets, and now they are thinking about growth. They might see gas assets as opportunities that are close to their core skills.
Jesanis, National Grid: We saw it in our U.K. operations. National Grid is not only an electric utility, but a gas company. Being part of that larger group has allowed us to improve our New York operation and make it more efficient. We've taken skills and practices that were developed in the UK and found they are effective here as well.
We think it's quite logical for retail gas and electric services to be provided by the same company in the same area. Many of the skills that it takes to be successful in one business apply to the other. But it might not be an area that electric companies pursue to create growth. The barriers are the same as they are for electric-to-electric consolidations. By the time you are done paying a premium, cutting rates and making concessions, there isn't much left to make it worthwhile to your shareholders.
Fortnightly Is deregulation and unbundling complete? How successful has retail competition been in gas markets?
Bertasi, Southern Company Gas: It has worked pretty well. The difference for us came when the Georgia Public Service Commission allowed marketers to decline providing services to high-risk customers. Prior to that, there was no regulated provider of last resort, and marketers were obligated to serve. Now we have pre-screening criteria, and customers who have struggled to pay their bills have gone to the regulated provider.
There is innovation happening now in products and service offerings among retail providers that are benefiting customers. We and other marketers are doing interesting things to handle customer credit risk. For example, different price plans serve different needs, with levelized payment options, credit offerings, and other services that we didn't see in the past.
Jesanis, National Grid: Our customers in New York state have a choice of supplier. Not as many exercise that choice as most of us would like to see over the long term, but there are a couple of initiatives under way to improve the penetration of alternative suppliers. For example, the New York regulator would like to see the marketers assume more responsibility for servicing the customer.
The big barrier to customer switching is that the utility provides a pretty good product right now as the supplier of last resort. We hedge our portfolio so the customer sees only about one-half of the volatility in prices.
Regulators have been reluctant to assign customers because that has the smell of slamming. As long as we have a good utility backstop product, the customer has to make the final choice of whether to switch.
Orange & Rockland has a program that we are looking at, in which they assume receivables from customers. We could work with customers on buying receivables. This would facilitate risk management during this period to help transition customers into the market.
Over time marketers should be responsible for taking their own credit risk. We shouldn't have marketers redlining customers. I hope we will find better solutions that protect customer interests.
Bertasi, Southern Company Gas: How regulators define the market as a whole is important, so marketers can customize products and offer different price structures for different customers. The key is for regulators to get the approach right.
Worries about future gas-supply shortages recently abated somewhat, as two major gas-import projects took decisive steps forward.
In mid-February, the Federal Energy Regulatory Commission (FERC) issued Order No. 2005 to establish open-season provisions for the proposed Alaska natural gas pipeline. The FERC order followed Congress' October 2004 enactment of the Alaska Natural Gas Pipeline Act as part of an appropriations bill. The act approves up to $18 billion in federal loan guarantees to build the 3,500-mile pipeline, which could bring 4.5 billion cubic feet (Bcf) of gas per day into the Midwestern United States beginning in 2014.
Also in February, Cheniere Energy closed financing on an $822 million credit package for its 2.6 Bcf/day Sabine Pass LNG terminal in Cameron Parish, La. The deal involved a syndicate of 47 financial institutions, led by HSBC and Société Générale. "As the largest domestic LNG financing to date, this transaction will serve as a template for future LNG project financings," says Dan Bartfield, a partner with Milbank, Tweed, Hadley & McCloy, which represented HSBC and SG in the deal.-M.T.B.
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