Gas: A Bridge to Nowhere?

Recently the Environmental Protection Agency announced the first federal carbon pollution standard that will effectively halt the construction of conventional coal-fired generation. The EPA stressed that the "proposed standard reflects the ongoing trend in the power sector to build cleaner plants that take advantage of American-made technologies, including new, clean-burning, efficient natural gas generation, which is already the technology of choice for new and planned power plants."

Ironically, this announcement is received by an industry more apt to retire rather than build new coal-fired generation in response to low natural gas prices. In fact the economics are already so one-sided that a predominance of gas-fired power plants are slated to be built over the next decade. Superficially, it appears that the displacement of coal by natural gas has already played a role in reducing U.S. power plant emissions.

Yet, it is unclear that substituting one fossil fuel for a slightly cleaner fossil fuel will significantly advance the country's long-term environmental agenda. To deflect such criticisms, it has been suggested that the transition to increased natural gas dependency for electric power generation is a temporary 'bridge' until reliable renewable sources can be deployed.

However, there are cautionary signs that the transition to increased natural gas use might not prove short-lived. Further, and perhaps more worrisome, is the possibility that the near term environmental advantage of switching away from coal and onto natural gas diminishes over time. Is there a policy road-map to transition the nation off of its emerging natural gas dependency? If not, what does this suggest about long-term natural gas prices?

Renewables stall

One of the obvious problems with the bridge argument is that natural gas is currently so inexpensive that the interest in investing and deploying renewable resources appears to be stalling. Investor interest in renewable generation has fallen off sharply with the slowdown in the U.S. economy. Solar and wind investment peaked around 2008 and have since declined by 70%. Further, the inability to extend federal tax credits (set to expire at the end of this year) has dampened most interest in the sector for 2012. With a modest 1,800 megawatts of new renewable investment announced so far this year, it appears that investment commitments will be cut in half compared to last year. In contrast, announcements of new gas generation projects total a robust 5,500 megawatts, or triple that for renewables.

In 2012, slightly more renewable generation capacity will come online compared to natural gas or coal-fired generation (8,800 metawatts versus 6,800 and 4,900 megawatts respectively). Yet, in view of unfavorable project economics and the paucity of federal funding support for alternative energy, gas-fired generation captures the largest market share for U.S. new-build additions beginning next year. According to the Energy Infromation Administration analysis, conducted a little more than a year ago, the cost of building a new gas-fired combined cycle plant was less than half that of the least expensive renewable project.

The sharp decline in natural gas prices since has only improved the odds that most of the new construction over the next decade will be gas-fired. To be sure, there are multiple factors that suggest that the switch over to increased natural gas use within the electric power industry is unlikely to be short-lived. Rather, increased use of gas may become a growing fossil-fuel habit that will be difficult to part with.

MIT study

Notwithstanding the potential renewable resource shortfall, more notably, the absence of a comprehensive policy limiting green-house gas emissions, suggests that the near-term environmental advantage offered by natural gas fuel-switching may diminish over time.

A recent Massachusetts Institute of Technology study highlights the risk of raising U.S. dependency on natural gas for power generation. The authors warn that treating shale gas as a bridge to a low carbon future may curb growth of sustainable renewable resources as well as the development of emissions control technologies, like carbon capture and storage.

Even under a best case scenario for U.S. climate policy, a nation-wide renewable requirement of 25% coupled with a 50% retirement of operating coal plants, the MIT study found that the use of renewable resources would stagnate while green-house gas (GHG) emissions would rise over time. The major driver of these findings was the hefty rise in natural gas demand stimulated by low-cost shale resources.

Because of shale gas affordability, demand for the fuel by utilities trebled over the simulation period. Meanwhile, renewable resources stagnated at regulated rates while GHG emissions climbed 13% over 2005 levels by 2050. Additionally, the carbon capture and storage technology, needed to meet more ambitious climate policy targets, remained largely uneconomic and therefore undeveloped over the long term.

To underscore the influence of low-cost shale gas, the MIT researchers ran an alternative scenario using the same regulated level of renewable generation and coal retirements but assumed an absence of low-cost shale gas. The resulting 20% cost inflation for natural gas led to a 15% reduction in total energy use and a 2% reduction in GHG emissions below 2005 levels by 2050.

In a recent interview to discuss this analysis, the lead researcher cautioned that if "shale gas is a great advantage to the U.S. in the short-term" it is also "so attractive that it may threaten other energy sources we ultimately will need (to reduce GHG emissions)."

And if these predictions are not sufficiently gloomy, a more probable environmental policy scenario in our view (of lower coal retirements and limited mandated renewables) would see GHG emissions soar above the double-digit level suggested by the MIT study. A real-life test case, of whether the country will be able strike a balance between low-cost natural gas and clean renewables, appears to be unfolding in California as the state prepares to implement rules to cut GHG emissions next year. The Global Warming Solutions Act (Assembly Bill 32 or "AB 32", as it is typically referred) mandates that the state lower its GHG emissions by 2020 to 1990 levels. This ambitious policy, a 25% reduction in emissions from current levels, aims to set an example for the rest of the nation that carbon cap-and-trade policies were not a recipe for economic disaster.

In order to meet California's climate goals, significantly less natural gas will have to be consumed, which will have an inevitable impact on U.S. supply/demand balances given the state's burn-rate. California is the second largest consuming state. It accounts for slightly more than 10% of total U.S. gas demand largely due to the fact that over half of state's generation is supplied by natural gas plants. Ironically, the state currently exemplifies MIT's best case scenario of relatively high renewables and low coal-fired generation.

Test case

In order to assess a possible national exit strategy off the emerging natural gas bridge, we look into aspects of California's AB 32 rule that could pertain to lowering emissions within the gas-intensive power sector. AB 32 focuses on reducing the state's GHG emissions by limiting smokestack and tailpipe emissions as well as encouraging lower energy use through conservation.

Under the reduction requirements of the rule, a cap-and-trade program sets limits on the heavier polluting industries responsible for roughly 85% of total state-wide emissions. Covered entities include large emission-intensive manufacturing sectors (such as cement, metal, glass and paper), power plants, refineries, gas utilities and pipelines that exceed thresholds of annual emissions.

The program covers roughly 350 businesses with a staggered time-line for compliance, starting in 2013 for power plants and large industrial facilities, and in 2015 for the remaining covered facilities. The way that the cap-and-trade program is expected to work is that a ceiling is placed on the amount of allowable GHG emissions and pollution allowances are granted for companies. Over time, the initial cap steadily declines toward the eventual target of lowering the state's emissions to 1990 levels.

During the first compliance period of the program, 2013 to 2014, the annual allowance cap will decline 2%. Thereafter, in the second and third compliance periods (2015 to 2017 and 2018 to 2020, respectively), the cap will decline by 3% annually. The most noticeable difference between the first and second compliance period is that the coverage universe expands to include the balance of the regulated industries. It is in the second compliance period that significant reductions will begin to take place.

Covered entities will initially receive a free allocation of roughly 90% of their historical emissions with reduced allocations made thereafter. The short-fall, between the allocation and the annual cap is expected to be made up through: (i) subsequent auction purchases (with a reserve price set at $10 per metric ton of CO2 equivalent), (ii) designated offsets and/or (iii) the adoption of operational changes that result in lower emissions for the covered entity.

The bottom line is that 40% of the state's emission reductions is anticipated to come from the electricity sector. This beckons the questions of whether these reductions are realistic, and if so, how are they going to be achieved.

First and foremost, about half of the electricity sector's emissions are actually imported along with a quarter of the state's electricity. Moreover, the out-of-state generation exhibits higher emission intensity if northwest hydro-electric imports are excluded. As a result, it would appear that the most expeditious route for lowering the state's GHG emissions would be to limit the coal-fired imports coming in from the southwest.

Not surprisingly, in conjunction with AB 32, legislation was passed to prohibit the purchase of power from plants that do not meet the state's stringent emissions standards. This rule will effectively limit the southwest imports.Unfortunately, many of the existing purchase agreements extend beyond the compliance period. In fact 40% of the out-of-state coal-fired generation contracted in 2011 will remain in place by 2020.

Therefore, while the slow attrition of high emitting imports might ultimately play a role in addressing California's climate goals, near-term reductions will likely occur by increasing renewables at the expense of gas-fired generation, which is exactly what the state intends to do.

A study commissioned by the California Public Utilities Commission found that the state could not meet its environmental goals if natural gas generation was used exclusively to meet new load requirements. Other scenarios that proved more promising for limiting emissions included the addition of a 20% renewable standard, referred to as the Reference case, and a more restrictive Accelerated Policy case that incorporates a 33% renewable requirement. The state has since adopted the Accelerated Policy which will require a significant ramp-up in the development of renewable resources to replace gas generation.

To effectuate this policy, the state requires that one-third of electricity demand be met by renewable sources by 2020. This requirement effectively triples the amount of the installed renewable generation required in California. Obviously, the challenge for removing natural gas from the state's dispatch will be attracting enough renewable investments.

According to the state's energy commission, 40% of the large-scale renewable resources will likely be built but will face an uphill battle without new transmission to effectively integrate these units into California's grid. The other 60% of the state's renewable requirements will come from distributed projects, largely unfunded, and that will also require new transmission investments.

The problem plaguing California then, as well as the rest of the nation, is that the relative economics do not seem to favor the level of investment required to switch away from gas and to renewables. For California's renewable projects to move forward, substantial tax breaks will need to be renewed. The California Energy Commission estimates that solar projects benefit the most from government support, with construction costs reduced by roughly 54% based on soon-to-expire tax-breaks. Given the sizeable short-fall in distributed solar projects within the state, there is some risk that the state will miss the off-ramp from natural gas generation dependency.

Forward gas prices

If the greenest state in the nation cannot wean itself off of inexpensive gas-fired generation, what hope does the rest of the nation have? Perhaps very little. Our long-held view is that natural gas will prove to be more than a provisional bridge fuel for electric power generation. In fact we believe that the roughly 1 billion cubic feet per day trend in annual electric power demand growth is relatively firmly entrenched.

With this in mind, we believe that long-term natural gas prices do not properly reflect the strong structural demand growth implied in our discussion above. As such, it appears to us that we face an unavoidable steepening of the futures strip. The timing of this shift will depend on the pace at which the market fully prices in the implications of current and future regulatory changes that increase the nation's dependence on natural gas. Ultimately, the combination of greater producer restraint, significant demand growth and a sharp rise in exports will allow U.S. natural gas prices to swiftly move beyond the current $4.25 to $4.50 per million British thermal units hurdle currently priced in for the 2015-2016 strip.

For industrial consumers and long-term investors, the optimal time to lock in low-cost gas prices appears to be now. While we generally believe that price recovery will likely be delayed past next year, the balance of the correction in relative prices along the longer dated strip of the curve may come sooner rather than later (or in other words the slope of the forward curve will steepen). In particular, the Cal14 strip priced below $4 is a bargain. For investors looking at prompt prospects, we see additional weakness in the near-dated maturities and suggest postponing initiating long-only position in the nearby liquid month until such time as a structural rise in demand begins to absorb surplus supplies.

Teri Viswanath is director of commodity strategy at BNP Paribas. This article was reprinted with permission from BNP Paribas.