Learning Where to Drill: Drilling Decisions and Geological Quality in the Haynesville Shale
We often link increasing productivity in resource extraction to innovation in how firms extract. Yet resource quality—where firms extract—is a key driver of productivity. Using a structural model and data from Louisiana’s Haynesville shale, I disentangle the impacts of how and where firms extract natural gas. Mineral lease contracts, learning about geology, and prices actually explain more than half of growth in output per well—not just technological change. Neglecting this may lead to over-optimistic long-run supply forecasts. I also show that growth in output per well masked large distortions caused by mineral lease contracts, which reduced resource rents.
The Economics of Natural Gas Flaring and Methane Emissions in U.S. Shale: An Agenda for Research and Policy
Natural gas flaring and methane emissions (F&M) are linked environmental issues for U.S. shale oil and gas (O&G) operations. In this paper, we lay out an agenda for researchers and policymakers. We describe why F&M are linked, both physically and in terms of policy. We perform an interdisciplinary literature review on measurement of F&M. We marshal granular industry data to identify constraints in the natural gas system correlated with upstream F&M. Motivated by this descriptive analysis, we discuss the economic and physical causes of F&M. We then discuss the external cost of F&M. We calculate that the climate costs of estimated methane emissions are an order of magnitude larger than the climate costs of reported flaring and venting after accounting for hydrocarbon content and flare efficiency. Finally, we discuss both existing policies and economic insights relevant to future policies.
(Co-authored with Ben Gilbert, CO School of Mines, and Gregory B. Upton Jr, LSU. The previous version “The Economics of Natural Gas Flaring: An Agenda for Research and Policy” contains more descriptive analysis of flaring.)
Financial Liabilities and Environmental Implications of Unplugged Wells for Gulf of Mexico and Coastal Waters
Plugging and abandoning (P&Aing) wells is a policy priority because unplugged wells present potential financial and environmental risks to the public. Offshore wells, compared with land wells, generally produce more, cost more to P&A and present different environmental risks. Here we estimate that the cost to P&A all 14,000 unplugged, non-producing wells in US Gulf of Mexico offshore waters, inland waters and wetlands is US$30 billion. Wells in shallower waters closer to shore make up 90% of inactive wells but only 25% of total P&A costs. They also present larger environmental risks. Prior owners of wells in federal waters (deeper and farther from shore) can be held liable for P&A costs if the current owner does not P&A them. We find that 88% of outstanding P&A liability in federal waters is associated with wells currently or formerly owned by one of the large, financially stable ‘supermajor’ companies.
(Co-authored with Siddhartha Narra, Brian Snyder, and Gregory B. Upton Jr. This paper updates Columbia CGEP Report “Considering Federal Program to Permanently Plug & Abandon Offshore Oil and Gas Wells”)
Anatomy of a Shale Boom: Optimal Leasing and Drilling with Costly Search
U.S. shale plays tend to first see an initial land rush as firms lease minerals, followed by a long delay before drilling picks up. Based on the characteristics of the mineral leasing process and descriptive statistics from South Texas’ Eagle Ford shale, I argue that this is due to search frictions in the market for mineral rights. I construct a dynamic, general equilibrium model of firms’ joint leasing and drilling decisions when costly search for leases is required, and I characterize the equilibrium path of leasing and drilling using continuous time optimal control methods. The model shows that along the optimal path of leasing and drilling, firms accelerate leasing activity to avoid high search costs when unleased acreage becomes scarce. This dynamic does not arise in a frictionless market unless there is uncertainty in price. In addition to leasing, I also include technological change and a capital-intensive oilfield services sector. With the addition of these two features, the model can explain the qualitative dynamics of shale development in South Texas’ Eagle Ford shale.
Decomposing Crude Price Differentials: Domestic Shipping Constraints or the Crude Oil Export Ban?
Published in The Energy Journal. https://doi.org/10.5547/01956574.40.3.mage
Over the past decade the U.S. domestic crude benchmark, WTI, diverged considerably from its foreign counterpart, Brent. Some studies pointed to the crude oil export ban as the main culprit for this divergence, but pipeline capacity was also scarce during this time. To understand the drivers of domestic crude oil discounts, we estimate the extent to which transportation constraints can explain price differentials. We find that scarce pipeline capacity explains half to three quarters of the deviation of mid-continent crude oil prices from their long-run relationship with Brent crude. We are unable to find evidence that refining constraints contributed significantly to this differential. This implies that the short-run deleterious effects of the export ban may have been exaggerated. (with Gregory B. Upton Jr, LSU)
Employment Impacts of Upstream Oil and Gas Investment in the United States
Published in Energy Economics. https://doi.org/10.1016/j.eneco.2016.12.012
We use dynamic panel methods at the state level to understand how the increase in exploration and production of oil and natural gas since the mid 2000s has impacted employment. We find robust statistical support for the hypothesis that changes in drilling do, in fact, have an economically meaningful and positive impact on employment. The strongest impact is contemporaneous, though months later in the year also experience statistically and economically meaningful growth. Once dynamic effects are accounted for, we estimate that an additional rig count results in the creation of 31 jobs immediately and 315 jobs in the long run. Robustness checks suggest that these multipliers could be even bigger. Our results imply that the national impact of upstream investment remains small, perhaps due to the sector’s small size and inter-state migration. (with Peter R. Hartley, Kenneth B Medlock III, and Ted Temzelides)
Global LNG Pricing Terms and Revisions: An Empirical Analysis
Published in The Energy Journal. https://doi.org/10.5547/01956574.38.1.mage
Asian long-term contracts for LNG are generally thought to index LNG prices to oil prices. This should mean that LNG and oil prices are cointegrated. However, statistical tests do not bear this out for Japanese prices. To resolve this puzzle, I examine 16 Japanese, South Korean, Taiwanese and Spanish LNG import price series and allow for multiple, unknown structural breaks. This resolves the puzzle, and I provide estimates for the timing of breaks and the underlying average pricing terms. I relate these to count, volume and duration data on long-term contracts. This paper complements existing work on gas market integration, which largely ignores how discrete changes in oil-indexed long-term contracts will affect empirical relationships.