Booming natural gas production, mostly in the Northeast, will continue to confound traditional North American gas market dynamics in the near future, said speakers at the LDC Gas Forum—Rockies and West in Los Angeles Oct. 7-8.
“Northeast production is flipping the market on its head,” said Luke Jackson, an energy analyst with Bentek. Gas production growth in the northeastern U.S., mostly from the Marcellus and Utica fields, is dwarfing growth in all other regions. The Marcellus field will account for 30% of U.S. production by 2019, up from 5% in 2010.
This dramatic shift is changing market fundamentals. “Massive growth nationally and in the Northeast has left us with a very strange gas market,” David Braziel, director of finance and fundamental analysis for RBN Energy, said. Right now, “There’s not enough demand to soak up all that supply.”
While the dramatically cold weather of the 2013–2014 winter led to a number of short-term demand shocks, the polar vortex episode has had surprisingly few long-term effects on the market, explained Reza Haidari, manager, gas market trading North America for Thomson Reuters. Traditionally, such a massive withdrawal from storage—winter gas demand set numerous single-day and single-week records, with some storage fields rumored to be nearly depleted—would have spurred sustained higher prices the following spring. Instead, production spiked back up with the return of better weather, keeping strong downward pressure on prices.
The shale boom, Haidari said, has flattened the forward price curve, allowing the market to go into winter with more gas in storage than when prices were more volatile. That’s going to continue this year, he said, and 2015 is likely to see a return to the 2-Tcf-and-larger spring inventories seen a year or two ago.
Steve Piper, associate director of energy product management for SNL Energy, agreed. The markets have mostly ignored storage deficits, he said, and ever-rising shale gas production is breaking the link between price and storage balance. “That will only continue as takeaway capacity improves,” he said.
How far can it go? Chuck Stanley, CEO of QEP Resources and chairman of America’s Natural Gas Alliance (ANGA) essentially threw up his hands. Production has grow so fast, he said, “We just don’t know how big this is going to get.” Rig productivity has grown phenomenally, as technological advances have unlocked additional production from individual wells. “The entire traditional logic in how we move gas around the country has changed.”
Jackson pointed out that falling rig counts can’t be relied on as an indicator that production may be slowing. That’s because of the nearly 2,000 wells in the Northeast that still aren’t connected to gathering infrastructure. “We have a huge backlog of wells that are currently in inventory” in Ohio, Pennsylvania, and West Virginia. “That represents around 5 Bcf/d to 10 Bcf/d of trapped production,” he said.
Another factor, Braziel explained, is that production returns on oil and wet gas remain well above dry gas, which means large amounts of associated gas are still being produced because of high prices for natural gas liquids (NGLs) and oil—more than the market can absorb. While exports to Mexico and overseas (via liquefied natural gas [LNG]) will make a dent in it, it’s not enough. Mexican demand should climb to about 6 Bcf/d, while long-term LNG exports could amount to 8 Bcf/d to 10 Bcf/d. “We’re going to need to encourage more industrial growth,” he said.
The NGL connection could be changing, however, Piper said. Right now, NGL contributions to production returns are critical to shale gas economics—but they are also variable. With oil prices projected to fall as production growth continues and demand in Western countries declines, returns due to the NGL component will fall as well, putting upward pressure on prices, he said.
The problem with rising prices, Haidari explained, is that coal remains highly competitive in the short term. “Gas-coal switching keeps killing [price] rallies,” he said.
The Obama Administration’s Clean Power Plan and the Environmental Protection Agency’s proposed rule on carbon emissions for existing plants may change that, however. “The takeaway there,” Haidari said, “is that [the new rules] are accelerating current trends” toward increased gas usage. Piper agreed, warning that the Plan is likely to exacerbate pipeline constraints, particularly in the West and Southwest.
Pipeline constraints, in fact, are rapidly becoming the real challenge. Michelle Bloodworth, senior director of market development for ANGA, said pipeline infrastructure is critical—there is more gas supply now than there is capacity to move it. “It’s putting a lot of pressure on the market,” she said.
Jackson and Braziel both highlighted the impact of exploding northeastern production on the rest of the nation. Producers in Canada and the Rockies who traditionally served the Midwest, Eastern Canada, and the Northeast suddenly face stiff competition from gas closer to market. “Rockies gas needs to find new markets,” he said.
While an enormous amount of new takeaway capacity is planned for the Marcellus-Utica region—some 28 Bcf/d by 2017, 15 Bcf/d of it going to Midcontinent markets—that’s not good news for western producers. Production from the Rockies and Canada is falling as the regions lose their outlet to Eastern markets. “We expect this trend to continue going forward as new pipeline projects come online,” Jackson said.
The Southwest and West face different issues because of pipeline constraints that largely isolate the area from abundant supplies further east. “It’s a very tight market,” Jackson said. Demand is in the region is currently flat, but that will soon change. Much of the impetus is the region’s rapidly evolving power mix.
Shifting Power Mix
Generation in the western U.S. is currently providing little price support due to soft demand, Piper said. Though California has brought quite a bit of new gas-fired capacity online recently, Jackson explained, this hasn’t budged total power burn. The reason is the state’s even more robust renewable energy development. While new gas-fired plants are seeing high usage, wind and solar are pushing out other gas generation, even with reduced output from hydropower as a result of California’s ongoing drought. “The increased amount of generation is coming from wind and solar,” Jackson said.
But the Southwest is about to lose about 4 GW of coal-fired capacity, a whopping 50% of its total. That generation can’t be replaced with renewables because these plants have historically seen high capacity factors, well above what can be achieved with wind and solar. “When those go offline,” Jackson said, “you can’t have wind and solar provide that power like gas can.” That will boost power burn later in the decade.
And, because of growing demand for Texas gas from Mexico, the Southwest is due for some substantial pipeline constraints, which should put upward pressure on regional prices. California will soon become the new premium summer gas market.
The ongoing deregulation of the Mexican energy market is opening up opportunities for gas exporters and developers in the country, Greg Hopper, vice president of ICF International, explained.
Mexican production is likely to grow rapidly, potentially reaching parity with Canada by 2020. But Mexican demand is also growing strongly, and at least 2.8 Bcf/d of new import pipeline capacity is being planned, with incremental investment in export capacity to Mexico nearing 10 Bcf/d.
The driver is the country’s expanding gas-fired power sector. “Mexico’s gas demand is power-driven,” Hopper said. But how far that will go is uncertain. “We don’t really know yet” how much demand will materialize. There is additional uncertainty in that the country’s energy reforms are still being worked out.
Hopper agreed these developments would impact West Coast markets, forcing California to source more gas from the Rockies and less from Texas.
The Mexican impact on the U.S. gas market could “quite possibly” extend as far as the Marcellus region if demand is high enough. Over the long term, Hopper said, Mexican energy reform and infrastructure development, including planned LNG import facilities, will ultimately create a unified North American gas market.
—Thomas W. Overton, JD is a POWER associate editor.