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Heating Up Electrical Costs

By Lindsay Audin - October 2004 - Power & Communication


For the past three years, facility executives using natural gas to heat buildings have become quite aware of its rising price. Wholesale gas prices have been hovering above $6 per million btu for months, roughly double where they were only a few years ago. Many economists see this trend continuing for years to come. The Federal Reserve Bank of Dallas recently projected that such high costs are likely to persist through 2010.

Less known, however, is the impact that high gas prices are having on electricity prices. As a result of changes to emissions regulations, generating technologies and wholesale power markets, most new power plants run on natural gas, allowing the price of gas to influence the price of electric power. This convergence is yielding a two-way link that could cause electric demands to raise gas prices, and gas demands to raise electricity prices.

In the months ahead, some areas might see power prices that peak in the winter as well as the summer. Boilers and light fixtures might soon be competing for the same energy resource and, as a result, raising the price to run them both.

Facility executives concerned about rising energy prices should use this winter to understand how their organization uses gas and electric and to prepare for ways to lock in to lower energy prices starting in spring. Typically, gas rates are at their lowest in the spring and summer, meaning it’s not too early to start thinking about how to lower next winter’s heating bills.

According to statistics from the U.S. Department of Energy’s Energy Information Administration (EIA), use of natural gas for electric power production has been rising at a rate of 7 to 8 percent per year since 2000. Utilities are using more gas than commercial buildings and as much as residential users. This change has contributed to a greater than 50 percent rise in less than two years. That has occurred even though overall U.S. gas consumption has remained relatively stable over the last five years.

In the past, summer natural gas use bottomed out because the need for that fuel was dictated by winter heating demands. Now, however, summer demand has increased as power plants turn to natural gas to produce electricity. Even utilities’ demand has increased in some regions as many new gas-fired plants also serve intermediate loads — above base but below peak.

Because winter gas demand has always been high in some parts of the United States, natural gas is routinely stored over the summer. In winter, those stockpiles supplement the normal flow of gas from wells. Utilities and others buy and store gas in the summer when prices are lowest, and then use that gas during their winter heating peaks. Gas-fired power plants running during the summer have, however, become competitors for that low-cost gas, forcing its price upward.

Oil Markets Aren’t Helping

Since the energy crises of the 1970s, many large gas users upgraded boilers to dual-fuel capability, allowing them to switch to fuel oil when gas became expensive, and switch back again when gas prices dropped. Such switching helped reduce gas prices and winter consumption in past decades. In some cases, dual-fuel systems were changed back to gas-only systems to comply with tightening emissions and fuel storage regulations.

But now, because of a confluence of disturbances in international markets and the U.S. economic recovery, even those able to switch to oil are faced with oil prices that were higher this summer than seen in many past winters. As a result, many who would have bought oil contracts for the coming winter are still waiting for oil prices to drop. If they don’t, demand for natural gas this winter could be quite high, pushing up gas prices for all end uses, including electricity.

Rising oil prices have also attracted more price speculators that buy blocks of energy and hold them for sale when prices begin to rise. Whether a shortage is real or not, a perception of tight market conditions and a rising price stimulates trading activity, often resulting in sharp rises — and sudden falls — in energy prices. Even if fuel prices cease their recent summer increase, such volatility is likely to be the norm in the coming winter.

Even where natural gas-fired power plants are only a small part of the generation mix, changes to wholesale power market rules have occasionally magnified price impacts. When utilities dominated power pools — regional groupings based on local transmission grids — power trading was essentially a help-thy-neighbor effort in which utilities needing short-term power could buy it from a nearby power company at a small markup. The favor was then returned when the situation was reversed.

In many parts of the country, that process has been replaced by Independent System Operators (ISOs) that manage such transfers using a market-based set of rules governing a variety of participants, including wholesale traders as well as utilities. ISOs presently cover New England, New York, California, Texas, Pennsylvania, Maryland, Delaware, New Jersey, most of West Virginia, Ohio, Indiana and Illinois, and are expanding into the Great Lakes area, as well as much of the Midwest, Virginia and Kentucky.

Some ISO rules may sharpen wholesale pricing volatility, which then trickles down to end users through tariffs and retail power contracts. When natural gas-fired plants provide the last increment of power needed to meet demand, for example, ISOs allow owners of those plants to determine the price for power paid to all generators, regardless of their energy source.

During such hours, electricity produced from nuclear power plants costs just as much as that from gas-fired power plants, for example. When gas-fired peaking generators are not needed, however, they produce little income for the operators. As a result, there is a tendency for the price of power produced by such generators to rise when they are needed.

Where this process has repeated itself over the last two years, the price of competitive energy sources, such as coal, has risen. Providers of those fuels saw the power produced from their resources drawing greater returns for power plant owners, regardless of the actual fuel cost to run such plants. To secure their piece of the action, those fuel suppliers are now also charging more, potentially raising the base price for power made from such fuels.

Changes on Electric Bills

While market-based rules were designed to eventually foster greater price competition, that positive change remains a dream in most areas. Instead, utilities are seeking double-digit percent rate hikes in Wisconsin, Texas, Colorado, Kansas, Utah and other states. Most blame the rising cost of natural gas.

In many states, customers are unaware of such increases until they get their electric bills. No formal rate case has been convened, no opposition aired, no changes made to published tariffs. Instead, a fuel adjustment charge allows the utility to pass through all or part of its increased fuel costs to end-users. Where electricity, not gas, is bought by the utility through the wholesale market, its extra cost may also be passed through via a fuel adjustment charge. Some states — such as Arizona, Missouri, Utah and Vermont — do not allow adjustment charges, while other utilities simply choose not to use them. But such costs eventually get passed through, one way or another.

How to Respond

In the best case, natural gas and oil prices will moderate before starting their usual winter climb. That may provide the fleet-of-foot with an opportunity to lock in fixed fuel and power prices for the winter. Those with energy bills exceeding $100,000 should check with their energy suppliers on a weekly basis and be ready to sign an agreement on a day’s notice because prices could change by the next day. Where retail electric deregulation is in effect, now is a good time to extend an existing contract, if present terms are acceptable, or to seek bids from new suppliers. If contractual issues must be reviewed before a signature is possible, clear them up now so that the only remaining issue is price. Know who should sign the contract, and have a backup official ready in case the first is unavailable on a moment’s notice.

Another strategy to consider is to lock in a portion — 50 percent of average monthly use, for example — of electricity, gas or oil at a fixed monthly price, with remaining usage to be provided at the market price. If prices fall later, part of the budget will see the benefit. If prices continue to rise, however, at least a portion of the load will be secured at a fixed price.

If utility tariff service is the only choice, it’s time to give it a closer look.

  • Is a fuel adjustment charge in effect? Are there any limits on it, such as maximum price regardless of market pricing?
  • Are there any tariff options, such as interruptible electricity and gas rates or load shedding?
  • Are meters read only monthly, or does the utility monitor daily consumption? Is the utility price averaged over an entire month regardless of a customer’s daily use, reducing some of the value customers might receive from brief reductions in usage during high-priced usage periods?
  • If metered and charged on a daily basis, does the utility make available the weekly or daily fuel and power prices it is incurring to encourage reductions in usage on high-priced days? Will it contact you to request usage reduction or fuel switching if prices get too high?
  • Does the utility allow customers to lock in the price of a portion of their fuel or power use, perhaps under a “take or pay” rule that charges for the energy even if it is not used?

When Options Are Limited

If none of these options is available, this might be a good time to speak with the public utility commission to see if some of those measures can be considered during the utility’s next rate filing.

Smart facility executives have contingency plans for cutting electricity usage during periods when the price may be exceptionally high by minimizing outside air intake, closing off unused parts of a facility or reducing heat shortly before the end of the workday to take advantage of thermal inertia.

Good housekeeping may also help. In high-rise buildings, attention may be needed to reduce the stack effect in which rising warm air is lost through leakage at the top of shafts, such as in stairwells where doors have been left open. This may also be a good time to replace worn weather stripping at leaky windows and doorways. To minimize leaks of cold air into a building, some pressurize their facilities by reducing exhaust and increasing supply air flow. If doing so increases electric consumption, however, care is needed to ensure that the net effect actually saves money.

While it may be too late to pursue mechanical or architectural changes, consider what alternatives could be made next spring to avoid future energy budget blowouts. For buildings with large glazed surfaces, one option that helps in both summer and winter is low-e window film that reduces the effective U-value — heat transmission rate — of the glass.

For energy budgets greater than $1 million annually, consider financial options to control price or cost risk. While all such options entail some risk — the worst of which is that energy prices drop — they do limit the impact of energy price spikes. Such options include weather insurance and buying energy futures, derivatives or forward contracts that require an organization to take title to, or else sell, blocks of energy. For simple examples of these options, and sources for training and books covering them, go to the April and May 2004 Tips of the Month.

Lindsay Audin is president of EnergyWiz, an energy consulting firm based in Croton, N.Y. He is a contributing editor to Building Operating Management magazine.





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