New England Struggles with Gas Supply Bottlenecks

New England’s big push toward gas-fired power collided hard with its historical pipeline constraints this past winter, leaving multiple generators unable to respond to start-up requests from ISO-New England during a major storm. In the wake of the episode, the region is looking for some long-term solutions.

Gordon van Welie, the president and chief executive officer of ISO-New England (ISO-NE), is a man with a big problem.

As he explained to the House Subcommittee on Energy & Power on March 29, the New England region has realized almost $7 billion in savings since 2007 from reduced wholesale electricity costs. Old, inefficient oil and coal plants—mostly public-owned—have been retired and replaced with a modern fleet of natural gas–fired combined cycle plants financed by private investors. The shift not only saw the average wholesale price of electricity in 2012 fall to its lowest level since 2003, but it’s also led to significant reductions in emissions of NOx, SOx, and CO2 and shifted new infrastructure investment risk from ratepayers to private investors. The once coal-heavy region now gets 52% of its electricity from natural gas.

Those may sound like problems worth having. But ISO-NE learned the hard way this past winter that whatever the merits of greater reliance on natural gas, few, if any, of them are available unless the gas can get to the plants.

Twice this year, in late January and mid-February, cold temperatures and bad weather caused a spike in gas demand for heating, sending gas prices at the Algonquin city rate spiraling over $30/MMBtu. With the wholesale electricity price determined largely by the price of gas, costs shot up over $200/MWh and stayed at abnormally high levels for weeks.

The causes of the challenge the ISO-NE region is facing are complex and in some ways interdependent.

Not surprisingly, one culprit is increased power burn (Figure 1). From an average of 3.53 Bcf/d from 2005 to 2010, power burn rose to around 6 Bcf/d last year, according to the U.S. Energy Information Administration (EIA). Capacity factors and utilization for the region’s newer combined cycle power plants (CCPPs) have nearly doubled compared to 2001, with total annual gas-fired generation rising from under 20 TWh in 2001 to more than 50 TWh in 2012, according to ISO-NE.

1. A widening appetite. GenConn Energy’s new 200-MW four-unit gas turbine peaking plant in Middletown, Conn., is one of numerous new gas-fired plants to come online in New England recently. Courtesy: Murtha Cullina LLP

However, the gas crunch has been exacerbated by two additional factors that have reduced supplies in the region.

Liquefied natural gas (LNG) imports into the city of Boston and the Canadian province of Nova Scotia, which provided an important additional “relief valve” when resources were short, have fallen substantially since 2008 along with U.S. gas prices (Figure 2). Those low prices have made the region an unattractive LNG market compared to others overseas, such as Asia. Spot and short-term LNG shipments have been diverted elsewhere, and only long-term contracts are still being serviced. This is an increasingly serious problem because, according to EIA data, since 2010, LNG has supplied around 25% of New England’s daily gas demand, and has risen to as much as 60% of total demand on some peak winter days.

2. A narrowing window. As consumption in New England has climbed on the back of increased power burn, imports from Canada and via liquefied natural gas (LNG) have fallen, even as the capacity to import gas from elsewhere in the U.S. and move it through the region has remained flat since 2008. Source: EIA

In addition, Canadian production from the Sable offshore field in Nova Scotia has been falling steadily since 2002, and 2012 production was the lowest it’s been since the field came online in 2000.

Pipeline Bottlenecks

While the region’s rising demand in the face of reduced supplies is the immediate challenge, the problem really comes down to one thing: pipeline capacity.

Natural gas flows into the U.S. Northeast have long been somewhat constrained due to the need to ship gas long distances from producing regions in the South and Southwest. The system has traditionally run near capacity only during the peak winter months. That has changed in the past five years.

According to EIA data, flows on the Algonquin Transmission pipeline, one of the key arteries in the region, have climbed steadily since 2005. Loads at the Stony Point compressor station in New York historically rose over 80% only from November to January. In 2012, it was over 80% for almost the entire year. Consequently, the traditional winter price spikes have begun cropping up during summer demand periods as well.

During January and February of this year, loads exceeded 90%, and both the Algonquin and TETCo pipelines were forced to issue operational flow orders (OFOs), a mechanism that requires shippers to balance supplies with usage within a specific range. When an OFO is in place, customers without “firm,” or guaranteed, service are at risk of being cut off.

“During that period,” van Welie explained, “ISO operators had to cope with multiple instances where generators (both gas- and oil-fired) could not get fuel to run.”

At one point during the February snowstorm, more than 6 GW of capacity—about one-fifth of the region’s total—was unavailable because of a lack of fuel.

“Our experiences this winter,” he said, “lead us to conclude that the status quo is not sustainable.”

It’s worth noting that the situation this winter did not take ISO-NE by surprise. In 2010, it launched a strategic planning initiative that was intended to address potential threats to reliability, among them overreliance on gas-fired capacity. The initiative warned that “sufficient gas may not be available to meet power system needs during periods of very high seasonal demand, under other stressed system conditions, or when facing contingencies associated with natural gas supply/transportation system infrastructure.” That warning would prove prophetic.

Solutions, however, have been elusive. Most of the impediments lie in the nature of the gas pipeline business.

Pipeline service has traditionally been tiered according to priority, having evolved to serve customers with different needs. Gas utilities, with predictable demand and service obligations to residential customers, are able to sign long-term contracts for firm service, and it is on these contracts that gas pipelines get built.

Power plant owners, with less-predictable needs and a desire to keep costs down, instead normally opt for less-expensive interruptible service.

The bulk of the pipeline capacity into New England has long been tied up by long-term firm service contracted by the area’s local distribution companies. Still, for many years, there was sufficient unused capacity in the system that interruptible service worked for the region’s generators. During peak winter demand when gas prices spiked, the area’s coal- and oil-fired plants were able to take up the slack and meet electricity demand.

If You Come, Will They Build It?

That was then. As oil prices have skyrocketed, gas prices have fallen, and coal plants have been retired, that alternate capacity has shrunk substantially. But despite the added gas demand, pipeline capacity has not grown to meet it.

In many ways, this is a clash of business models. Pipelines are almost always designed, financed, and built based on peak firm contracted service, period. Unlike the electricity grid, little to no concern is given to reserve margins. Firm customers typically contract 100% (or nearly so) of a pipeline’s capacity, because it makes little sense for a pipeline owner to build speculative capacity.

Unfortunately for generators, especially in a wholesale electricity market like ISO-NE, it makes equally little sense for a plant to spend the extra money on a firm service contract when demand is uncertain. Doing so creates substantial risks of having purchased gas that is unneeded or that cannot be used profitably because of day-to-day market conditions.

Said van Welie, “Natural gas generators generally have a short- to medium-term financial horizon, and they are a diverse group with diverse market interests. Thus, they are a group of ‘fragmented buyers’ who are unlikely to enter into long-term fuel arrangements on a large scale. This does not align with the long-term commitment preferred by investors in gas pipelines and gas storage infrastructure.”

ISO-NE is working to develop market changes that are intended to increase the financial incentives for generators to secure reliable fuel supplies. These include:

  • Changing the wholesale market to improve electricity price formation and improve the ability of generators to reflect the true cost of fuel in their offers.
  • Strengthening performance incentives for generators and demand resources.
  • Changing the timing of the electricity market to make it easier for generators to secure fuel from the gas market to meet their obligations in the electricity market.
  • Expanding the region’s reserve margin.

Van Welie also suggested that some of the billions in savings reaped from lower gas prices be devoted to expanding the region’s gas infrastructure.

New England may be leading the vanguard on this issue, but it is not alone. Last year, in the wake of a similar disruption in the Southwest in 2011, the Federal Energy Regulatory Commission (FERC) formally launched an initiative to improve coordination between the natural gas and electricity industries. The issues it is trying to address are much the same as what ISO-NE faced this winter: scheduling and market structure, communications and information sharing, and reliability. In August, FERC held a series of five regional conferences in an attempt to gather information and begin the process of developing solutions. Three follow-up conferences were held in February, April, and May of this year.

FERC is equally worried about the potential for future interruptions in service. As Commissioner Philip Moeller pointed out at the same congressional hearing, these problems have emerged despite two unseasonably warm winters. “My fear,” he said, “is that this warmer weather has masked system vulnerabilities that will be exposed when more normal colder weather patterns occur.”

The Way Forward

The discussion in New England is being led by the New England States Committee on Electricity (NESCOE) Gas-Electric Focus Group, which was formed in October. Thus far, the focus group has been leading monthly meetings and conference calls among stakeholders in both industries.

NESCOE plans to issue a final report on the challenges and possible solutions New England is facing later this year. The report will also include a multi-phase study of regional pipeline capacity conducted by Black & Veatch.

The first phase of the study, released in December, reviewed existing research analyzing the adequacy of the gas infrastructure in New England and its ability to meet forecasted demand. The study identified a number of serious information gaps:

  • No previous study clearly identified what level of gas infrastructure would be considered adequate to meet electricity reliability challenges.
  • No study examined seasonal, daily, and hourly fluctuations in demand in an effort to identify potential system constraints.
  • No estimates exist of the costs of new pipeline infrastructure that might be needed, and no study has attempted to quantify the benefits of additional infrastructure in a way that accounts for market uncertainties.

The second phase, released in April, attempted to fill these holes.

Black & Veatch found that, historically, the region has been at risk of price spikes and capacity constraints any time system load exceeded 75% of contracted capacity. It projected that by 2018, those conditions would exist in almost every region of ISO-NE at least 30 days out of the year, and at least 60 days out of the year in most of them. In eastern Connecticut and western Massachusetts, load would exceed 75% on more than 120 days.

The report noted that Spectra’s Algonquin Incremental Market (AIM) pipeline project, which is intended to expand the capacity of the existing Algonquin pipeline, would help alleviate some of these constraints. The AIM project is currently in early planning phases and projected for service in late 2016.

Black & Veatch also pointed out, somewhat ominously that, “existing and proposed firm contracted capacity is only a theoretical proxy for natural gas availability.” The study assumed that LNG from the area’s terminals and send-out from the Canadian pipelines was fully available. In reality, of course, both resources fell short of capacity this past winter and could easily do so again.

The report identified an array of potential infrastructure solutions (it did not consider market-based solutions, as these are being developed by ISO-NE).

Approximately 2.85 Bcf/d to 3.35 Bcf/d of new and expanded pipeline capacity is currently being proposed for the region (including AIM). The report estimates the projected total cost for these projects at least $3 billion. About half the proposed capacity is greenfield, making potential development uncertain.

Additional LNG peak-shaving facilities could be added to the region’s existing 15 Bcf of storage capacity at a cost of around $110 million per 1 Bcf. These facilities, however, are limited in their ability to provide ongoing supplies because of the extremely slow liquefaction cycle.

While demand response is not expected to play a meaningful role in relieving gas capacity constraints, the report noted that New England still has a substantial amount of dual-fuel generation capacity, most of it built since 1990 and not expected to retire in the near future. While oil-fueled generation in the region has shrunk to insignificant levels because of higher oil costs and environmental restrictions (many of these plants are permitted to burn oil for only a limited number of days per year), these resources could provide a backstop in the event of gas unavailability. Indeed, oil made an unexpected comeback this winter, reaching 5% of total generation during the January crunch and 7% during the February storm, according to EIA data.

The final phase of the study, due out later this year, will analyze potential solutions.

Van Welie, though, made it clear what ISO-NE is hoping to get from the pipeline companies: more flexibility. “The gas sector,” he said, “could assist with reliability efforts if gas suppliers provided generators with additional opportunities to obtain fuel outside of normal business hours, and if pipelines would offer more flexible scheduling, additional services, and provide real-time information on the status of the pipeline system.”

Thomas W. Overton, JD (@thomas_overton) is POWER’s gas technology editor.