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Power Generation and Opportunities for LNG
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New Era in Natural Gas Pricing
Natural gas prices have entered a new era. As Figure 1 shows, gas prices
have risen not only in absolute level, but also have moved closer to crude
parity (pricing on average between distillate and fuel oil). The “gas
bubble”, that turned into a “gas sausage” finally burst as demand growth
outstripped supply growth. On the supply side production flattened as producing
areas matured and access was limited (e.g., parts of Rockies, east Gulf of
Mexico, Alaska), while on the demand side legislation, regulation, and
efficiency drivers made gas the fuel of choice (as evidenced by the explosive
growth of gas fired generation in recent years).
As a result, expectations are forming of a higher price environment. For example, the NPC (National Petroleum Council) study uses a reference price of $5/MMBtu going forward and concludes that in the future, the landed cost of new LNG (e.g., from the Middle East) would be less expensive than marginal North American production. In other words, LNG (while an important piece of the future supply picture) would not be the price-setting mechanism in (most) North American markets.
In addition to higher levels, gas prices could continue to experience volatility due in part to the projected tight supply/demand balance, but also due to the increasing importance of the volatile demand patterns of the power sector. Each of these trends would appear to provide an opportunity to LNG suppliers from the perspective of being able to provide: (1) quicker response to demand than other long-distance supply (e.g., Alaskan pipeline projects), and (2) alternative storage capability due to faster withdrawal times and some locational flexibility.
Tightening environmental standards will continue to improve competitiveness of gas relative to coal. NOx and SO2 restrictions expand from regional (e.g., Ozone Transport Region) to national and seasonal to year-round. Additional limits on fine particulates, mercury, and local haze are expected by 2008.
Power Generation Key to Natural Gas Demand Growth
An example of this increasingly important component of gas demand is shown in Figure
2. Power generation accounts for 23% of total demand from the power sector
(much of which is associated with the merchant companies who are focused on
costs). Looking forward, 95% of announced power capacity additions are
gas-fired, accounting for about 80% of the cumulative growth in gas demand
through 2010. By 2010, power generation’s share of gas demand more than
doubles (from 23% to 56%). Thus power generation is of interest to LNG (and all)
suppliers because it is the growth in gas demand for at least the rest of the
decade.
Focusing on the eastern portion of the U.S., natural gas consumption will grow at an annual average rate of 11.5% through the rest of the decade. This growth is depicted on the left-hand side of Figure 3. LNG suppliers should find this growth an attractive target for contracting off-take agreements. These suppliers tend to prefer long-term contracts, high volume commitments, and constant lifting.
However, the profile seen by power generators (as seen on the right-hand side of Figure 3) would be much more volatile than the annual picture. The volatility in the demand profile comes from three sources: (1) economic activity – long-term cycle over quarters, (2) weather – mid-term cycle over a season (i.e., summer), and (3) intraday – short-term cycle over hours, driven by demand profile of end customers. Generators need variable off-take (be it from a pipeline or LNG source) to quickly adjust to power market conditions (e.g., warmer than normal summer). Because of these uncertainties, power generators prefer contracts of short duration with low volume commitments.
Power generators think about gas prices in two ways. They are concerned with the absolute level of natural gas prices when gas-fired assets are setting power prices. Generators also are concerned about the price of gas relative to competing fuels (i.e., coal for base load or oil products for intermediate/peaking) because they tend to have a portfolio of assets with a variety of fuel options within certain geographies to serve load.
Issues in Defining the Role of LNG in Supplying Power Generation
Solving the puzzle of the role of LNG in supplying East Coast power demand
revolves around four issues: (1) the length of the off-take agreement, (2)
dealing with seasonality, (3) pricing terms, and (4) counter-party commitments
(see Figure 4). Some of the questions within those issues are below.
How long are off-take agreements?
New off-take agreements in the US may differ from previous LNG deal structures.
Traditional off-take agreements at regasification terminals in other parts of
the world (e.g., Japan and South Korea) have been for 10-20 years at fairly
stable volumes. There usually were no competing supplies (e.g., no pipelines or
indigenous supplies) so a 10-year contract did not force the customer to forego
other supply options. Nor did the counter-party run the risk of being at a
competitive disadvantage because they tended to be in a regulated market or no
competitor had the ability to secure gas from some cheaper alternative.
Do we measure “long-term” in months or years?
However, in the U.S. because of the variety of supplies and routes available,
most contracts are for less than one year. Debundling of services from Rule 636
significantly changed the nature of relationships between suppliers and
end-users. As a result, the US market has a different perspective about what is
the “long-term” than Asia or even Europe.
How do LNG suppliers shape off-take to reflect demand profile of power
plants?
Off-take contracts may need to be sized on the minimum (or shoulder) month
demands, assuming the regasification terminal is still economic at those levels.
Gas demand in power and heating (e.g., LDCs) are counter-seasonal so terminal
throughput economics would be improved by looking at power and LDC demand
together.
How do LNG suppliers guarantee deliverability during winter?
There is very little (if any) firm winter transportation for power generators on
the East Coast. A supplier bringing new volumes to the market (and expecting
winter off-take) needs to solve how to get that volume to power plants at times
when infrastructure deliverability is stretched. Deliverability would not be an
issue for new CCGT sited on the same footprint as the regasification terminal.
However, given the current glut of capacity along the East Coast it will be some
time before this option becomes viable.
How do LNG suppliers assure heat content compatibility of pipelines and
power plant requirements?
As LNG become more prominent in interstate pipelines this issue becomes more
important as excessive heat content threatens the warranty of turbines. This is
an issue of growing concern not only for power generators, but also LDCs as the
FERC recently urged the industry to address gas quality and interchangeability
issues before the agency is compelled to step in and regulate such standards.
How quickly could LNG suppliers alter delivery schedules?
Forecasting weather more than 3 days ahead is little more than a roll of the
dice. Because we don’t get an advance copy of Mother Nature’s plan, it is
difficult to accurately plan a call on gas three months ahead, which is the time
frame of arranging shipping for supplies coming half-way around the world.
During a warmer than normal summer suppliers need to be able to quickly offer
additional volume (e.g., securing more LNG tankers) to feed incremental gas
demand, assuming the regasification terminal is not already fully utilized.
What kind of credit rating would off-take parties need?
Given the weak financials of many potential counter-parties, take-or-pay
contract provisions in traditional LNG off-take agreements are a non-starter.
Even if the counter-party has the credit to enter into a take-or-pay, they
should either try to push it off the negotiating table because the supplier has
limited counter-party options or use their credit worthiness as a counter-weight
in price term negotiation
Does price have a seasonal component?
One way to incent power generators to burn large volumes year-round (in other
words annualizing the seasonal profile) is to promise to keep them whole. In
other words, offer the generator a spark spread guarantee. But to make such a
guarantee requires access to the market (i.e., firm transportation).
What do we mean by “price”? Is price on a fixed or index basis?
People have a variety of definitions for “fixed” and “index” prices:
The likelihood LNG might not be the price-setting mechanism in most U.S. markets gives suppliers some pricing flexibility. Suppliers could offer a price below the local hub yet still realize a price above delivered cost (and possibly less volatile?).
The price an LNG terminal can expect to receive is not necessarily that of the nearest pricing hub. Figure 5 shows the difference in the price LNG would sell for depending on whether the regasification terminal includes transportation rights. If the end-user takes title to the gas at the terminal gate and secures transportation, the user is willing to give up only the saved transportation from an alternative source (the difference between $0.25 and $0.10 in Figure 5). However, if the LNG supplier secures transportation to the market area, then the terminal can price at the market price (and the value received is the netback from the market area to the terminal).
Pulling all the pieces together, Figure 6 lists several observations:
There is some room to compromise between the prices desired by the LNG supplier and a generator. LNG suppliers want to price at local market index (e.g., Transco Zone 6), CCGT break-even, or distillate parity. Generators need coal parity to run their CCGTs in baseload, fuel oil parity to run CCGTs in the intermediate stack, or cost-plus (e.g., spark spread guarantee) to burn a constant volume of gas.
A power generator usually has a suite of assets burning a variety of fuels. They are not wedded to burn gas at any price because a relatively small amount of capacity has “must run” requirements on large segments of gas-fired facilities. If the price of a fuel is not economic, generators hold less efficient gas assets off the merit order until either (a) the price of a fuel falls or (b) the price of power rises – because some less efficient plant set the clearing power price
Summary
This list of issues and possibilities to consider when shaping an off-take
agreement with a power generator is not unique nor is it exhaustive. Would the
absence of any of these kill the deal for a generator? Probably not, but it is
intended to be a first-pass at a launching pad of creative ideas to consider
when trying to structure an off-take agreement.
Anchoring an LNG terminal with power generation demand will be difficult, but not impossible. A lot of homework and hard work will be the order of the day. The effort is worthwhile because well-structured projects would have less risk. Competitive pressures place premiums on innovation not only in terms of technology, but commercially as well. At this point in time, it appears that the LNG projects most likely to succeed are those where one of the supply parties purchases LNG in the U.S. and takes responsibility for integrating (“on-selling”) the gas into an existing supply portfolio.