Come to the Colorado Air Quality Control Commission Public Hearing
February, 19th 12:00 pm – 3:00 pm and 5:00 pm – 7:00 pm
Aurora Municipal Center
15151 East Alameda Parkway, Aurora, 80012
The Colorado Legislature has declared it to be the policy of the state to “achieve the maximum practical degree of air purity in every portion of the state,” to attain and maintain Federal standards on air quality, and to prevent the significant deterioration of air quality in places where the air quality is better than federally mandated. The Air Quality Control Commission of the State of Colorado is charged with making these policies into enforceable regulations. This is a commission of 9 volunteers appointed by the Governor who care passionately about air quality. This is not the Colorado Oil and Gas Control Commission, who some see as having the interests of a small group of constituents at heart. The Commissioners of the AQCC are working hard to ensure that the air quality regulations they enact are the best possible regulations for public health.
Rewind to November, when Governor Hickenlooper stood with representatives of Environmental Defense, a former EPA Region 8 administrator, and the “big three” oil and gas developers in the state, Anadarko, Encana, and Noble Energy. These groups worked to come to a consensus on rules that will positively impact public health as well as will be attainable by the developers. Do these rules promise to allow zero oil and gas emissions to escape into the air? No. Will they go a long way toward cleaning up the VOC’s and methane that are part of today’s development? Yes. They can be stronger, but they must not be any weaker.
Over the past three months, small developers and industry groups have worked hard to attack these rules in hopes that they will be weakened. The rules are long and tedious, but can be understood to address two issues. First, they will require the oil and gas industry to use better technology – technology that the big three may already be using – to reduce VOC and methane emissions. Second, the rules require the industry to inspect their infrastructure and fix leaks when they are detected.
Price is not the only economic variable to consider in deciding what kind of generation a utility should build. Different kinds of power have different risks associated with them. This is important even if we set aside for the moment the climate risk associated with fossil fuels (e.g. the risk that Miami is going to sink beneath the waves forever within the lifetime of some people now reading this). It’s true even if we ignore the public health consequences of extracting and burning coal and natural gas. As former Colorado PUC chair Ron Binz has pointed out, risk should be an important variable in our planning decisions even within a purely financial, capitalistic framing of the utility resource planning process.
Utility financial risk comes largely from future fuel price uncertainty. Most utility resource planning decisions are made on the basis of expected future prices, without too much thought given to how well constrained those prices are. This is problematic, because building a new power plant is a long-term commitment to buying fuel, and while the guaranteed profits from building the plant go to the utility, the fuel bill goes to the customers. There’s a split incentive between a utility making a long-term commitment to buying fuel, and the customers that end up actually paying for it. Most PUCs also seem to assume that utility customers are pretty risk-tolerant — that we don’t have much desire to insulate ourselves from future fuel price fluctuations. It’s not clear to me how they justify this assumption.
What would happen if we forced the utilities to internalize fuel price risks? The textbook approach to managing financial risk from variable commodity prices is hedging, often with futures contracts (for an intro to futures check out this series on Khan Academy), but they only work as long as there are parties willing to take both sides of the bet. In theory producers want to protect themselves from falling prices, and consumers want to protect themselves from rising prices. Mark Bolinger at Lawrence Berkeley National Labs took a look at all this in a paper I just came across, entitled Wind Power as a Cost-effective Long-term Hedge Against Natural Gas Prices. He found that more than a couple of years into the future and the liquidity of the natural gas futures market dries up. In theory you could hedge 10 years out on the NYMEX exchange, but basically nobody does. Even at 2 years it’s slim!
Natural gas produced from shale formations, commonly referred to as “shale gas”, has become increasingly important in the energy supply market for the U.S. and worldwide. Obtaining natural gas from shale reserves was not considered economically feasible until recently because of low permeability of the shale rock formations. New developments in hydraulic fracturing technology have led to a boom in domestic shale gas production since massive scale utilization in 2003. The United States has experienced economic benefits via revenue and job creation in predominantly rural areas while simultaneously increasing the energy security of the U.S. by decreasing dependence on foreign oil supplies. However, the resounding question remains: at what cost? In order to realize the implications of this question we first need to understand some basics about the hydraulic fracturing process and the uncertainties that continue to surround the shale gas industry. In this report I will primarily focus on the environmental impacts of hydraulic fracturing and well development, but it is important to realize that direct impacts on the environment can and will extend to affect human health.
Hydraulic fracturing, or “fracking,” is a stimulation process used to extract natural gas, and in some cases oil, from deep shale reserves 5,000-8,000 feet below the ground surface. This process allows energy companies to access previously unavailable energy sources in states that have deep oil and gas reserves. The fracking process involves pumping a mixture of water, chemicals and sand at high pressure into a well, which fractures the surrounding rock formation and props open passages that allow natural gas to freely flow from rock fractures to the production well. Once the well is developed, the carrying fluid can then flow back to the ground surface along with the gas.
Geothermal energy is the Earth’s own internal heat. It’s a huge potential resource, but so far it’s seen only very limited use. Traditional geothermal power can only work where there are naturally existing hydrothermal systems that bring the heat of the interior to the surface. A new technique called enhanced (or engineered) geothermal systems (EGS) may make geothermal power much more widely available. If it can be scaled up commercially, EGS will enable us to create hydrothermal systems anywhere there’s hot rock not too deeply buried — which includes a large swath of Colorado. This is potentially significant in the context of creating a zero-carbon electrical system because like hydroelectricity, and unlike wind and solar, geothermal power can be dispatchable: you can turn it on and off at will. This makes it a great complement to intermittent renewable power, as it can be used to fill in the gaps then the wind’s not blowing or the sun’s not shining. It remains to be seen whether it’s technically feasible, and if so at what price, and on what timeline, but it’s certainly worth investigating.