This article was originally published on Black & Veatch by Linda Lea

Historically low natural gas prices in 2012 resulted in record levels of coal-to-gas fuel switching – that is, operating natural gas plants in favor of coal plants – among power generators. More than 3.7 billion cubic feet/day of natural gas was used for short-term displacement of coal generation capacity in 2012. As a result, for the first time in U.S. history, natural gas matched coal in fueling the equivalent amount of electricity consumed in the United States, a trend unlikely to continue in 2013.

“Coal-to-gas switching likely reached its peak in 2012,” said Mike Donnelly, Director and Chief Geoscientist of Black & Veatch’s natural gas and power fuels group. “Since April 2012, when gas prices reached their lowest point, prices have steadily risen as supply has become more balanced with demand. In 2013, we project that total coal-to-gas switching will decrease by 10 to 15 percent from 2012 levels, although this will largely depend on the location and price elasticity of the new gas demand, the delivered gas price and other non-fuel related operational factors during 2013.”

During the past several years, more than 30 million tons per year of Eastern U.S. coal has been displaced by short-term fuel switching, as utilities rely less on output from coal plants and ramp up output from natural gas generation.  This volume is equivalent to about 3% of the total coal demand. However, the amount of coal-to-gas switching varies by region as costs for both coal and natural gas can differ greatly.

Price, however, is not the only factor in the decision for short-term fuel switching, Donnelly said. Levels of excess power generation capacity weigh heavily on decisions, as do a plant’s interconnectivity with the power grid and natural gas pipelines. Other factors include current fuel contracts and environmental regulations.

ENVIRONMENTAL REGULATIONS AND COAL

Environmental regulations will be a significant influence on the long-term operations of many coal-fired units. Black & Veatch’s 2013 Energy Market Perspective, a semi-annual outlook on the integrated power and fuels markets, projects that more than 62,000 megawatts of coal-fueled power generation will be retired as a result of proposed or new air emissions and water regulations by 2020.

Natural gas will replace the lion’s share of this capacity. Coal unit retirements, however, are not the only option for utilities.

 

“There are many technical options that utilities can consider for their older, smaller coal-fired units,” said Bob Slettehaugh, Technology Assessment Service Area Leader in Black & Veatch’s global energy business. “Environmental retrofits, co-firing with natural gas, or repowering of the units may be available to utilities to make the most of existing assets.” 

Slettehaugh noted that several factors should be considered when deciding what to do with older coal-fired units. “The important thing to remember is the characteristics of the individual unit will dictate the most advantageous option. Size of the unit, current emissions control equipment and site characteristics greatly influence which option will be the most cost-effective and align best with a utility’s business model.”

One key site characteristic is the capacity of existing natural gas pipelines and storage in a regional grid. Utilities must determine if there is sufficient capacity to meet consumer and industrial demands as well as the supply requirements for their electric generators.

“Integrated natural gas and electric reliability is a very important emerging issue,” said Donnelly. “Utilities can’t just decide that they want to convert to large-scale natural gas generation. They have to know where the gas is coming from. They also have to have a clear understanding of the risk of losing generation as a result of insufficient gas supply and delivery capacity, and how to alleviate those risks through storage and purchasing strategies.”

ASSESSING A POTENTIAL SWITCH

Black & Veatch is working with clients at the utility level as well as regional level to assess current gas infrastructure in order to prepare for future needs.

The New England States Committee on Electricity selected Black & Veatch to examine the effects that increased demand could have on its regional natural gas infrastructure. The company was tasked with analyzing current and future natural gas fuel supply and infrastructure within New England and determining the level of risk fuel supplies could have on the region’s power system, as well as develop cost-benefit analysis for potential solutions to each risk.

The first phase of Black & Veatch’s study concluded that “New England’s natural gas infrastructure will become increasingly stressed as regional demand for natural gas grows, leading to infrastructure inadequacy at key locations.” The second phase of this study examines potential solutions and will be completed later this year.

This finding was validated earlier this year when spot market prices at the Transcontinental Pipeline’s Zone 6 (which serves New York City), rose to $35.33 per MMBtu on Jan. 23, and increased to $37.07 per MMBtu the following day. By the following week, however, prices dropped to $3.47 per MMBtu.

“There is an increasing competition for natural gas between residential, commercial and industrial users,” said Donnelly. “During the next 20 years, Black & Veatch projects that electric sector demand for natural gas will nearly double nationwide, but in many regions it could be much greater, particularly in the Northeast United States where substantial coal and nuclear retirements will occur over the same timeframe.”

Donnelly advises clients to begin preparing now to shore up current and future natural gas supply requirements, both on the supply side and on the transportation  and storage side.

“When considering new natural gas generation, expansion of existing units, or even repowering or co-firing coal facilities, there are a lot of important factors to consider,” said Donnelly. “Clients need to examine pipeline access and capacity within their grid. What are the total and forecasted demands on the system? They also need to look at storage options as well as contracting strategies. This is all critical to ensuring reliability while balancing costs for customers.”