Energy Spot Prices: Should We Care?

It's often tempting for home buyers to assume that credit availability and interest rates at the day of purchase are somehow reflective of the future. If corporate and utility managers who oversee investment in large energy projects took the same short-term perspective, the financial consequences could be considerable. For them, spot prices for energy and traded futures count for little. More important are long-term trend in the security of fuel supply, capital, components and labour, as well as the marginal cost of providing these to meet demand.

As an investor in industrial technology start-ups in the energy sector, it's clear that these long-term trends in energy supply are what drive value for our portfolio companies. The long-run marginal cost of supply has typically set the future price of the commodity -- at least that's generally been the case for the price of oil for most of my lifetime. However, given the recent economic downturn and related fall in energy prices, it's worth examining the outlook for all of our major fossil-fuel sources: oil, natural gas, and coal.

Oil

The demand for oil is not particularly sensitive to price, though there was clear evidence of some demand destruction when prices reached extreme levels in 2008. Generally, consumers and businesses will pay what's required to drive to work or transport goods to customers. In a recession, however, belt tightening and corporate restructuring will reduce demand as economic activity falls. We're seeing this today. GDP among OECD countries is in rapid retreat and, while the decline in non-OECD countries has been slower, the relatively higher consumption per capita in OECD countries means that oil demand will actually fall, according to a recent forecast from Bernstein Research.

On the supply side, it's well known that oil reserves are dwindling and the number of oil wells needed to product the same output will need to increase. These reserves per new well are forecast by 2015 to shrink to one-fifth their size compared to the period between 1996 and 2002, when reserves peaked. This means producers must develop five times the number of wells to just to keep up. Reserves per developed well is one of the primary drivers of cost in this industry, and hence the primary driver of long-run marginal production cost (inclusive of capital recovery). Even taking into account the rapid expansion of production by members of the Organization for the Petroleum Exporting Countries (OPEC), it's estimated that all increases in supply after 2014 are likely to come from new well production -- not from the now historically low spare capacity within OPEC. For this reason, energy analysts peg the long-run marginal cost of oil at around $100 (U.S.) per barrel.

Natural Gas

Natural gas is more a regional than global market, so let's take a look at North America and Europe. The North American market historically has been oversupplied, with market prices around $2 (U.S.) per thousand cubic feet (Mcf). This price was often much lower under long-term contracts with chemical companies located along the Gulf Coast.

But then U.S. power generators made the "dash to gas" and demand for this relatively clean-burning fossil fuel began to shoot up. These utilities grew to represent 30 per cent of the natural gas market demand. Significantly, this represents a considerable source of inelastic demand as utilities can more easily pass through higher fuel prices to their ratepayers, which have little choice but to pay.

The result is that North America's gas supply is now tight, and production now carries a much higher long-term marginal cost. New supply is heavily dependent on non-conventional fields (e.g. shale, coal bed), deep-water projects, or LNG imports and some industry analysts predict that the marginal cost of natural gas will rise to around $8 Mcf by the end of the decade.

In Europe there is much less price transparency with natural gas. Prices are coupled to oil prices, and there are complex international transit agreements governing the flow and transmission of the fuel from Russia to Europe (to a lesser degree from Norway and Northern Africa). It means Europe is a price taker when it comes to natural gas, and increasingly so. The region's preference for natural gas as a heating fuel and for power generation has bumped up its demand significantly.

No wonder therefore that Europe is highly sensitive to the security of its supply. To address this it has taken two seemingly contradictory approaches. On the one hand, it secures long-term supply agreements from Russia and receives the gas through a new pipeline that circumvents Eastern Europe. On the other hand, it attempts to develop alternative sources of natural gas and transmission routes through Southern and Eastern Europe, outside of the political influence of Russia.

Continuing insecurity -- and limited ability to store natural gas locally -- is preventing European utilities from developing new natural gas-fired power plants to meet a looming electricity crisis. Such plants would otherwise be the least expensive to build and would serve as a lower-carbon alternative to coal.

Coal

Coal is the natural choice for power plant operators in both North America and Europe. The fuel is cheap to mine and has few other competing uses. If utilities had their way, they'd replace every old coal plant that's retired with a new one. Why stop using coal when the trusty coal plant can reliably provide baseload, intermediate and peak electricity needs?

Unfortunately, coal is at the centre of a public-relations nightmare. It's the fossil fuel with the highest emissions with or without flue gas clean up. Coal power claims twice the carbon footprint of natural gas.

Several U.S. utilities have announced plans to build advanced coal-fired power plants, but all have been postponed because of environmental concerns expressed by a variety of stakeholders -- from grassroots community groups to Wall Street banks.

In Europe, the carbon market is a major barrier for coal power. Rules forbid the transfer of carbon credits or "allowances" from retired plants to new plants. This is compounded by the auction cost of allowances in the power sector. These two factors have tipped the economic scale away from coal and toward alternative -- and cleaner -- forms of energy. Carbon capture and storage (CCS) technologies are under development, but it's still early days. The regulatory framework for CO2 storage and transit from a power plant to a storage site doesn't support imminent deployment. Some utilities are promoting the idea of "CCS-ready" power plants, but to date only small-scale and pre-commercial prototypes have been developed.

All of this has opened the door to renewable energy. Sceptical? Consider that in 2008 General Electric sold more wind turbines than gas turbines, and new wind farms represented nearly 50 per cent of all new power-plant capacity in Europe and 30 per cent in the United States.

Will declining spot prices and oil futures mean lower venture capital returns from energy-focused industrial technologies? Not likely. Demand for oil can only go up. Meanwhile, the rate at which we can replenish oil reserves continues to fall. This means more difficult -- and costly -- resources will have to be exploited. A slowdown or recession in the West may temper this trend, but this won't change the fact that fossil-fuel prices will rise alongside the value proposition of emerging clean-energy technologies.