As gas-fired plants take up the slack for a substantial amount of retiring coal-fired generation and gas producers are able to back off from drilling merely to hold production, gas prices will get a lift, Credit Suisse Commodity Research Director Teri Viswanath told NGI last week.
Viswanath is looking for gas prices to average $5.25/MMBtu at the Henry Hub during 2011 and $5.85/MMBtu during 2012. Those numbers might not feature in producers’ wildest dreams, but $5.85 in 2012 beats the New York Mercantile Exchange (Nymex) strip.
But the Credit Suisse analyst’s outlook is bullish compared to recent estimates of Bentek Energy LLC, Barclays Capital, and independent analyst Stephen Smith, all of whom seem more focused on the abundance of gas supply the nation has in shale plays.
Bentek, well respected in the industry for its monitoring of pipeline flow volumes across North America, recently said prices would average less than $5/MMBtu at the Henry Hub for the next five years (see NGI, July 26). Barclays has been more pessimistic about gas price recovery. In mid June the firm’s analysts repeated their expectation that 2011 prices would average $4.10/MMBtu (see NGI, June 21).
But the Nymex futures screen shows prices rising steadily over the next five years to close 2010 at $5.11, 2011 at $5.70, 2012 at $5.91, 2013 at $6.12, 2014 at $6.33, and 2015 at $6.60. But in Bentek’s view the screen doesn’t get it, at least not yet. “The Nymex futures strip through December 2015 currently averages $5.76,” Bentek said. “The futures market has not fully adjusted to the fundamental changes that are expected to take place.”
Last week Smith of Stephen Smith Energy Associates further undercut the strip when he lowered his gas price estimates for this year and next and in doing so came closer to joining Team Bentek. Smith cut his 2010 Henry Hub bidweek average price estimate to $4.65/MMBtu from $4.70/MMBtu and his 2011 estimate to $5.00/MMBtu from $5.50/MMBtu.
“On a net basis we are more bearish about the 2011 supply-demand balance than we were in our previous monthly outlook,” Smith wrote. “We have assumed average 1997-2009 HDDs [heating degree days] and CDDs [cooling degree days] for our 2011 demand forecast, but…the [National Weather Service January, February and March] HDD outlook for 2011 is for milder-than-normal weather.”
Smith also cited a flagging economic recovery and an until-recently steadily climbing gas-directed rig count (see related story) as the two other reasons for his pessimism on prices.
During an earnings conference call with financial analysts last week RRI Energy Inc. CEO Mark Jacobs might have summed up the view of the Nymex strip the best. “…[W]e all know that the forward curve is wrong; we just don’t know by what direction and by how much,” he said.
Production will be driven higher by producers forced to drill to hold leases, Bentek recently emphasized, but Viswanath believes this phenomenon will pass within about a year. While producers will have more discretion over their drilling activities, a more interesting story is unfolding on the demand side with power generation, she said.
“I think the fascinating story happens to be on the electric power side,” Viswanath said. “It’s relatively impressive that in the ’90s we retired roughly 4 GW of coal generation, and the announcements right now show that we have 20 GW online for retirement between 2010 and 2020.
Helping to drive expectations of coal plant retirements is the fact that 2012 is the first year that new emissions restrictions under the Environmental Protection Agency’s (EPA) recently proposed Clean Air Transport Rule (CATR) would take effect. The rule would require 31 states and the District of Columbia to significantly improve air quality by reducing power plant emissions that contribute to ozone and fine particle pollution in other states.
“Emissions reductions will begin to take effect very quickly, in 2012 — within one year after the rule is finalized,” EPA said. “By 2014, the rule and other state and EPA actions would reduce power plant SO2 [sulfur dioxide] emissions by 71% over 2005 levels. Power plant NOX [nitrogen oxide] emissions would drop by 52%.”
“We’re seeing that retirements are occurring at a faster clip, so really the upward band on [coal-fired power plant] retirements could be 40 GW of retirements,” Viswanath said. “We see gas taking the lion’s share of that.”
Jacobs said he expects the retirement of emissions-constrained coal-fired generators to be substantial. “Nationwide, we believe that new environmental regulations could lead to the retirement of 40 GW of capacity.” That number could go as high as 90 GW depending on the economics of coal-fired versus gas-fired generation, he said.
“…[I]t would have a material impact on the commodities the [power] industry uses as fuel. Retirements [of coal plants] at the upper end of the range I mentioned would translate into an additional 8-plus Bcf/d of demand for natural gas.”
To whatever degree gas picks up for retiring coal plants it will obviously be good for gas producers. But the jury is still out on how many coal plants will fall before EPA’s tougher regulations and how many gas-fired plants will stand up to take their place.
While the Barclays team noted that some are saying as much as 60 GW of capacity could be retired due to CATR, the analysts are less convinced that coal plants will be such a pushover.
“So far, the amount of capacity that has been announced for retirement is quite small,” the Barclays team said in a note last week. “If history is any indicator of the future, the amount of coal capacity that will be shuttered will fall below forecasters’ expectations, and the closures will be strung out longer than anticipated.”
Barclays analysts said plant retirements likely will be concentrated in a few market regions. States with the largest shortfall of sulfur dioxide (SO2) allowances are likely to be Pennsylvania, Georgia, Ohio, Indiana and Alabama. Combined, these states account for 53% of the total allowance shortfall among states whose sulfur dioxide (SO2) emissions will be constrained by CATR, Barclays said.
“In percentage terms, however, the steepest cuts in emissions would have to be achieved by Massachusetts, Maryland and Delaware, each of which would be required to cut SO2 emissions by over 75% from 2008 levels by 2012,” the analysts said.
They noted that choosing to add emissions controls or to shut down a coal plant is not a straightforward decision. “Considerations range from economics, to reliability, to local policy on energy infrastructure, to energy costs, to the end-users and many more.”
The analysis also often includes a comparison of the economics of coal- versus gas-fired generation. “While gas may be the default choice for capacity replacement, [state] regulators are still very hesitant to turn to natural gas,” the Barclays team said.
One member of the team recently attended a conference of the National Association of Regulatory Utility Commissioners and reported back that “gas prices are still viewed as being volatile; therefore, regulators are skeptical that gas will be a cheap alternative for new power generation. The memory of the gas price volatility of 2005 and 2008 is perhaps too recent. Coal prices, on the other hand, are viewed as stable, and stability has a strong advantage from the perspective of the regulators.”
Gas producers would prefer to keep the lid on volatility, too, just as long as prices are higher. For producers wondering how long the gas industry will be crossing its “bridge years” from the high prices of 2008 to the next period when “prices better reflect true lifting cost economics,” Viswanath suggests that the inflection point will be in 2012. While 2011 doesn’t offer much to get excited about, “2012 becomes sort of interesting,” she said.
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