Shadows of Uncertainty: Trends that Will Shape the Future of Power Supply and Gas Demand

Chris Goncalves and Patrick Hurley, Navigant Consulting

LOOKING FORWARD TO THE NEXT TWO decades, three trends will have material impact on both new and existing power plants in the U.S.:

*Greenhouse gas (GHG) policies

*Renewable power supply policies

*The critical growing supply of liquefied natural gas (LNG)

These trends are just three among many affecting the future of power generation, however, they have the potential to exert the greatest influence on the future power supply landscape. Moreover, these three trends are interrelated, each affecting the other two.

Greenhouse Gas Policies

New policies intended to curb GHG emissions will increase the total costs of fossil fuel for power generation through additional costs associated with cap-and-trade and/or carbon tax. This will likely alter the mix of new power plants and increase the demand for natural gas.

Forget the scientific debate about global warming and the impact of GHG. The reality is that the GHG and related environmental regulations under consideration, and those previously enacted, are already creating a great deal of uncertainty within the energy industry and in its planning process. The anticipation of broad regional and federal GHG regulations is impacting capital investment decisions, fuel market prices, and renewable energy and energy efficiency policies.

Coal-fired generation, which produces about twice the CO₂ per MWh as gas-fired generation, will be hit hardest as a result of the cap-and-trade and carbon tax plans under consideration. The extent of impact to coal-fired generation is under study by many parties in the industry and will vary by regional markets. Under many scenarios, the relative mix of coal-fired generation will diminish due to the retirement of existing units and/or the development of fewer new units. The breach must be filled by energy efficiency, renewable energy sources (e.g., wind power), and conventional gas-fired or nuclear supplies.

Energy efficiency will play a greater role in matching energy supply and demand in the future. As today's already-high energy prices continue to increase, new efficiency technologies will be developed and implemented. Unfortunately, this may be a slow process and will be somewhat unpredictable as a component of the overall solution to match the growing power market requirements with increasingly tight supply.

A resurgence of nuclear power will meet some of the supply requirements. However, there is great uncertainty about the timing of the development of any new nuclear power plants in the U.S. Despite providing 20% of today's electricity supply and emitting no GHG, nuclear power has a dark cloud of negative public opinion hanging over its head. Nevertheless, opinions have eased somewhat in recent years and several utilities are now poised to submit applications to build new nuclear generating plants.

Thus, if coal-fired generation bears the brunt of new energy policies, it will be supplanted by a mix of renewable supplies and gas-fired generation. Gas-fired generation could become the swing resource utilized to firm up intermittent renewable generation. If this occurs, it would add to the rapidly growing demand for natural gas generation capacity while reducing overall gas-fired capacity utilization in favor of renewable resources when available.

Renewable Power Supply Policies

Proposed new federal policies mandate that a substantial portion of power supply must come from renewable sources, similar to existing and proposed state policies. A national renewable portfolio standard (RPS) will alter the U.S. mix of new power plants and may decrease the demand for natural gas.

Several states have initiated RPS policies that set targets for the portion of energy supply that must be met by renewable sources. And the U.S. House of Representatives has passed a bill (HR 969 on August 4, 2007) mandating that 15% of electric energy generation must come from renewable resources by the year 2020. This action shows that RPS has climbed high on the national agenda and will be subject for debate this fall and into the 2008 Presidential campaign.

A national RPS of 15% would constitute a significant policy change that would substantially alter power capacity additions and gas demand, with a range of results including:

*Substantial renewable capacity additions displacing a portion of future additions of coal generation capacity.

*Marginal impacts on gas capacity additions.

*A need for additional gas-fired peaking capacity to serve as "renewable firming" resources due to the intermittent nature of some renewable power sources.

*An overall reduction of future gas demand for power generation which could soften future gas price expectations, also potentially tipping the scale from coal to gas on future capacity additions.

Consistent with this assessment, the U.S. Energy Information Administration (EIA) recently examined the potential impact of a national 15% RPS. EIA concluded that biomass generation (including wood) would see the greatest increase in terms of both energy production and percentage change—more than tripling by 2030. A portion of this increase would be accounted for by co-firing coal plants with biomass fuel. The analysis also concluded that relative to a 2030 scenario without a national RPS, coal and nuclear generation would be reduced by 7% and 5%, respectively, while gas-fired generation would decrease by about 2%. Despite these relative decreases anticipated as a result of the RPS program, the EIA results indicate substantial growth over current levels of installed coal, nuclear and gas generation capacity, as well as increases in net generation by each fuel type.

Liquified Natural Gas Supply

LNG import capabilities will grow substantially. Actual imports are likely to be seasonal, with the highest levels of imports in the summer and fall—taking advantage of the huge storage capacity in the U.S. and avoiding the highest cost winter supplies that will be dear in European markets short on seasonal storage capacity.

With respect to LNG supply, 2007 brought a shakeout in the terminal development business. A few proposed projects have been cancelled, but others have successfully navigated the permitting, supply procurement and financing necessary to launch construction. Meanwhile, monthly LNG import levels are climbing and the amplitude of their seasonal swing has widened.

EIA projects a 22 trillion cubic feet (Tcf) base case gas market in 2030, with gas demand driven by power generation. Of this total, about 4.5 Tcf (more than 20%) would be supplied by imported LNG to account for the rising demand and declining pipeline imports.

The inventory of U.S. LNG import terminalsthose that exist or are currently under constructionwould bring total LNG import capacity to approximately 16 billion cubic feet per day (Bcf/d) or 5.8 Tcf annually by 2010. Several other terminals have secured permits and are close to obtaining supply commitments. At this rate, U.S. LNG terminal capacity will reach EIA's 2030 target capacity of 6.5 Tcf by 2015.

However, the actual LNG import volumes and LNG terminal load factors are another story. Worldwide import terminal capacity continues to be added at a faster clip than liquefaction (export) capacity. The resulting international market competition for limited LNG supplies implies that actual U.S. imports and terminal load factors are apt to fall short of EIA's projections.

This is because LNG imports are on the margin in North American gas markets and are trending toward an increasingly pronounced seasonal pattern of peak summer/fall imports followed by winter import troughs. LNG import activity is increasingly associated with seasonal storage utilization patterns and price volatility in North America.

Other key LNG importing countries lack the levels of underground storage capacity enjoyed by the U.S. and are subject to significant seasonal peaks. Whereas the U.S. underground storage capacity represents approximately 18% of U.S. demand, other importers face tighter conditions. For example, Spanish storage capacity represents only 9% of demand and UK storage capacity represents only 4% of demand.

When key European LNG end user markets such as Spain and the UK hit winter gas demand peaks, their lack of storage leads to a premium valuation of imported LNG. In the winter/spring months, European buyers tend to outbid the U.S. for LNG supplieswith European and U.S. prices considered on a netback basis at the key Atlantic liquefaction terminals.

With ever greater levels of gas in underground storage during the shoulder months, U.S. markets and buyers tend to have greater price leverage than Europe in the peak winter months (under normal weather conditions).

Until Atlantic LNG supply options catch up with U.S. and European demand growth, we should expect the intensification of the seasonal pattern of U.S. LNG imports to continue widening the seasonal swings in U.S. storage inventories and market prices. The anticipated addition of new LNG capacity along the U.S. Gulf Coast and Atlantic Seaboard will support this pattern.

The mid-term outlook for LNG imports involves a substantial increase in import capacity that will likely be utilized much more heavily in the summer/fall months than in the winter/spring months. On balance, actual annual LNG import levels will remain constrained by available supply, and well below import capacity.

Overlapping Shadows

Notwithstanding the additional renewable capacity driven by the prospective national RPS program (and indirectly by anticipated GHG regulations), capacity of coal, nuclear and gas-fired generation is expected to continue to grow over the next two decades. The subsequent question then becomes, "By how much?" Gas-fired capacity may actually increase from the combined pressure of GHG and RPS policies due to lower CO₂ emissions from gas and the need for firming capacity for wind and solar.

These market and operational uncertainties yield mixed expectations for total gas demand levels and a "spikier" gas demand profile associated with gas-fired renewable firming capacity. These uncertainties will be compounded by the accelerating trend toward seasonal volatility in North America's marginal LNG imports, which will constrain and cast uncertainty over seasonal and annual gas supply levels.

On balance, these mega-trends could exert countervailing forces on average gas price levels. The prospective GHG and RPS policies along with LNG supply cast long shadows of uncertainty over the future generation mix, and the gas market balance and profile, pointing toward extended volatility over the coming several years.