UC Santa Barbara

As the world transitions toward a low-carbon energy economy, two features of natural gas set it apart from other fossil fuels. First, the combustion of natural gas generates about half as much carbon dioxide as coal. Second, gas-fired electricity generation can be ramped up and down quickly and efficiently, making it well-suited for balancing out intermittently available wind and solar energy. These two factors lead many to believe natural gas will play an extended role in the electricity generation mix. However, there are many ways in which current markets for natural gas not well-adapted for its role in the energy transition. This dissertation explores two areas where natural gas markets can be improved for its efficient utilization in the transition to low-carbon energy. The first two chapters develop policy tools to help reduce methane emissions from the natural gas supply chain, and the third chapter investigates a previously unknown market failure that can arise in interconnected natural gas and electricity markets.

The first chapter of this dissertation empirically estimates the cost of reducing methane emissions from the extraction segment of the natural gas industry. Although natural gas has important climate benefits, it is composed of about 90 percent methane, which is itself a greenhouse gas that is far more potent than carbon dioxide. A small fraction of emitted gas (in the form of equipment leaks and intentional venting) can therefore have severe warming effects. This chapter estimates the cost of reducing these emissions by examining how production facilities' emission rates respond to changes in natural gas prices. Because firms mitigate emissions up to the point at which their marginal cost of mitigation equals their marginal private benefit of being able to sell captured gas, an estimated relationship between emission rates and prices can be used to determine mitigation costs. Results indicate that methane emissions from natural gas production can be reduced at very low cost relative to other sources of greenhouse gas emissions. For example, an emissions price equivalent to the social cost of methane is predicted to decrease emissions by about 76 percent while increasing the net cost of natural gas extraction by less than one percent.

Building on this result, the second chapter explores how emissions pricing can be used to regulate methane emissions in practice. Previously, emissions pricing programs have been implemented based on the carbon content of fossil fuels or by using continuous emissions monitoring sensors placed in smokestacks. However, because methane emissions from the natural gas industry are released from many different sources in a variety of different ways, comprehensively monitoring them is prohibitively costly at this time. This chapter outlines a novel estimate-based approach for implementing emissions pricing in this setting. Rather than monitoring emissions at all facilities continuously, the regulator randomly selects a subset of each firm's facilities to perform measurements at. The regulator then uses these measurements to develop a firm-level estimate of emissions, which can then be used to apply an emissions tax or account for the use of permits. A theoretical model demonstrates that this approach preserves the efficiency benefits of emissions pricing with comprehensive measurement. Furthermore, a simulation calibrated to be representative of the U.S. natural gas industry predicts that this approach can achieve climate mitigation benefits roughly two orders of magnitude greater than the cost of measurement.

The third chapter, which is coauthored with Charles F. Mason, Kristina Mohlin, and Matthew Zaragoza-Watkins, explores a market failure that can arise from the increasing interdependence of natural gas and electricity markets. It develops a theoretical model that illustrates conditions under which a firm that owns both electricity generation plants and contracts for natural gas pipeline capacity may find it optimal to withhold those contracts from secondary markets. By artificially limiting the available supply of pipeline capacity on constrained days, this behavior increases electricity prices in the downstream electricity generation market, which benefits non-gas generators owned by the withholding firms. We document pipeline scheduling patterns exhibited by two firms in New England that are consistent with this behavior. We then estimate the impacts of this behavior, finding that it increased wholesale natural gas and electricity prices by 35 percent and 18 percent, respectively. We estimate that substitution from natural gas generation to coal and oil generation due to these artificial supply constraints resulted in economic losses of $1.5 billion over a three-year period. While this behavior may have been within the firms' contractual rights, these findings underscore a need to improve regulation and coordination of these increasingly linked energy markets.