Thursday, January 19, 2017

The Local Economic and Welfare Consequences of Hydraulic Fracturing

Exploiting geological variation within shale deposits and timing in the initiation of hydraulic fracturing, this paper finds that allowing fracking leads to sharp increases in oil and gas recovery and improvements in a wide set of economic indicators. At the same time, estimated willingness-to-pay (WTP) for the decrease in local amenities (e.g., crime and noise) is roughly equal to -$1,000 to -$1,600 per household annually (-1.9% to -3.1% of mean household in-come). Overall, we estimate that WTP for allowing fracking equals about $1,300 to $1,900 per household annually (2.5% to 3.7%), although there is substantial heterogeneity across shale regions.
...
Conclusions
Using a new identification strategy based on geological variation in shale deposits within shale plays, we estimate the effects of fracking on local communities. There are four primary findings. First, counties with high fracking potential produce roughly an additional $400 million of oil and natural gas annually three years after the discovery of successful fracking techniques, relative to other counties in the same shale play. Second, these counties experience marked increases in economic activity with gains in total income (4.4 - 6.9 percent), employment (3.6 - 5.4 percent), and salaries (7.6 - 13.0 percent). Further, local governments see substantial increases in revenues (15.5 percent) that are larger than the average increases in expenditures (12.9 percent) though the increased expenditures seem largely aimed at supporting the new economic activity, with little effect, for example, on per pupil expenditures in public schools. Third, there is evidence of deterioration in the quality of life or total amenities, perhaps most notably marginally significant estimates of higher violent crime rates, despite a 20 percent increase in public safety expenditures....
Image result for Hydrofracking epa
by Alexander W. Bartik, Janet Currie, Michael Greenstone and Christoper R. Knittel
The University of Chicago Becker Friedman Institute for Research in Economics
Working Paper 2016-29; December 21, 2016
Keywords: Public Policy, Environment, fracking, economic impact, economic growth

Rooftop Solar Arrays on Five Fire Stations Expected to Reduce Electric Costs 30% for Less Than $1,500

The Dubuque City Council recently approved agreements with Eagle Point Solar of Dubuque for the installation of rooftop solar arrays on five of the City’s six fire stations. The project is expected to reduce electricity costs at the stations by more than 30 percent.

The contract award follows a request for proposal process which generated responses from five firms. The City Council unanimously approved a power purchase agreement and a collateral assignment agreement with Eagle Point Solar for the installation of rooftop solar arrays....

Once installed, the arrays are expected to permanently reduce the City’s cost of each kilowatt hour (kWh) of electricity utilized in the five fire stations by more than 30 percent. Specifically, the terms of the contract include a $0.085/kWh initial rate with a three percent inflation rate. This compares with the current aggregate Alliant Energy rate for the fire facilities of $0.116/kWh. The only upfront funding required for this project from the City is for equipment upgrades to allow internet connectivity for the solar arrays, not to exceed $1,500.The percentage of electricity use offset and carbon dioxide offset at each station varies, due to available roof space and usage at that site:

  • Headquarters 66.15 kW Electric Offset 37% CO2 Offset 1,651 tons
  • Station 2 35.28 kW Electric Offset 96% CO2 Offset 887 tons
  • Station 3 27.72 kW Electric Offset 55% CO2 Offset 697 tons
  • Station 4 15.75 kW Electric Offset 26% CO2 Offset 377 tons
  • Station 5 5.04 kW Electric Offset 28% CO2 Offset 128 tons
  • Total System Size 150.8 kW Carbon Offset 3,740 tons
According to Eagle Point Solar, the combination of the five solar arrays, over their lifetime, will offset the equivalent of: planting 87,141 trees, the reduction of 7.48 million automobile miles driven (or 381,480 gallons of gasoline), recycling 11,818 tons of waste rather than landfilling it, displacing carbon dioxide emissions from the annual electricity use of 425 homes, or 1,822 tons of coal burned.

Wednesday, January 18, 2017

Defensive Investments and the Demand for Air Quality: Evidence from the NOx Budget Program

Abstract:      
The demand for air quality depends on health impacts and defensive investments that improve health, but little research assesses the empirical importance of defenses. We study the NOx Budget Program (NBP), an important cap-and-trade market for nitrogen oxides (NOx) emissions, a key ingredient in ozone air pollution. A rich quasi-experiment suggests that the NBP decreased NOx emissions, ambient ozone concentrations, pharmaceutical expenditures, and mortality rates. Reductions in pharmaceutical purchases and mortality are valued at about $800 million and $1.5 billion annually, respectively, in a region covering 19 Eastern and Midwestern United States; these findings suggest that defensive investments account for more than one-third of the willingness-to-pay for reductions in NOx emissions. Further, the NBP’s estimated benefits easily exceed its costs and instrumental variable estimates indicate that the estimated benefits of NOx reductions are substantial.
nitrogen oxide cycle
by Olivier Deschenes 1, Michael Greenstone 2 and Joseph S. Shapiro 
1. University of California, Santa Barbara - College of Letters & Science - Department of Economics;
1. National Bureau of Economic Research (NBER); IZA Institute of Labor Economics
2. University of Chicago - Department of Economics; National Bureau of Economic Research (NBER)
3. Yale University, Department of Economics; National Bureau of Economic Research (NBER); Yale University - Cowles Foundation
Social Science Research Network (SSRN) www,SSRN.com
June 1, 2016, Number of Pages in PDF File: 74
Keywords: willingness to pay for air quality, cap and trade, ozone, pharmaceuticals, mortality, compensatory behavior, human health

Got A Favorite 2017 Energy Forecast? Technology Will Make It Obsolete

... The U.S. Energy Information Administration (EIA) ... just released its latest Annual Energy Outlook. The Outlook offers predictions about the future of energy prices, production and consumption in the United States.... EIA has found that its own predictions of crude oil and natural gas prices differ from realized prices by 30 to 35%. Their forecast errors for renewables are sometimes even larger.

The EIA is not alone in making bad predictions. Professional oil price forecasters and futures market participants make bets about future oil and gas prices that routinely turn out to be completely wrong.   But contrary to what you might think, these forecasting errors should not be viewed as evidence that the EIA or any of these forecasters are doing a bad job, or even as mistakes at all.  Instead, they point to the key role that changing technology—and specifically supply-side technology—has played in the energy landscape in recent years. The history of forecasting errors in the U.S. natural gas market is a perfect example of this phenomenon.
...
Consider EIA's 2000 forecast of natural gas markets in 2015: 25 trillion cubic feet (TCF) of production at an average price of about $5 per thousand cubic feet (MCF).  Actual production in 2015 was about 27 TCF at an average price of $3.37 per MCF—we got more gas at a lower price than expected....

77% of EIA's forecasting errors are best interpreted as forecasting errors about the supply curve for natural gas, as opposed to the demand curve.  This is true for forecasts made before the shale gas boom (80%) as well as for more recent forecasts (72%). The figure also shows that EIA's forecasts made before the start of the shale gas boom tended to overestimate supply (66% of the time), while forecasts made after tended to underestimate supply (63% of the time).

Why has supply been harder to predict than demand? Over the last 20 years, there have been two large shocks to the “technology” of natural gas production: an unexpected decrease in natural gas discoveries in the Gulf of Mexico starting in the early 2000s, followed by the unexpected boom in shale gas development more recently.

Until the mid-2000s, the EIA forecasted about 5 TCF of offshore gas production per year.  In reality, offshore gas production decreased in nearly every year since 1997, and now stands at just 1.3 TCF.  An important cause of this decline in production has been a 70% drop in the rate of new offshore gas field discoveries since 2000. Because discoveries had been stable at about 2 TCF per year for the 15 years leading up to 2000, it is fair to say that this absence of technological progress, and therefore negative shock to supply, was rather unexpected.
Credit: Wikimedia Commons
Wikimedia Commons
The opposite is true for onshore gas fields, where rapid and unexpected improvements in hydraulic fracturing technology helped gas production far outpace forecasts in places like Texas, Louisiana, Pennsylvania and West Virginia. Although EIA correctly anticipated as early as 2000 that shale gas resources would grow in importance, they underestimated the speed and magnitude of this change.   As recently as 2005, EIA still forecasted less than 10 TCF of shale gas production per year for the then foreseeable future. In reality, U.S. shale gas production is now more than 15 TCF per year.
...
Recently, this uncertainty has been driven by the emergence of new ways of getting more gas inexpensively. However, it is important to remember that this uncertainty can also be caused by technological “misses,” like declining exploration success in the Gulf of Mexico.... Forecasts of future supply can be too optimistic just as often as they are too pessimistic.

by Thomas Covert, Contributor
Energy Policy Institute at the University of Chicago
January 5, 2017

Study Shows Electricity Markets Are More Cost-Effective Than Cost of Service Regulation - Natural experiment using the U.S. electricity system shows regions using a market approach save about $3 billion a year.

Are markets more cost-effective than cost of service regulation and other approaches? Despite markets’ imperfections, a new natural experiment using the U.S. electricity system points to yes. The study finds that regions using a market approach to buy and trade electricity save about $3 billion a year because of the increased efficiencies and coordination the markets bring.

“While many have compared major differences in economic systems across countries—where there are many moving parts and it’s difficult to convincingly identify the true source of those differences—this study focuses on a single industry that has undergone a profound reorganization,” says Steve Cicala, the author of the study and an assistant professor at the University of Chicago Harris School of Public Policy. “The study is an additional piece of evidence that, while not perfect, markets perform well relative to the alternative.”

Cicala used a unique policy shift within the U.S. electricity system to compare a market versus command-and-control regulatory structure. Periodically since the late 1990’s, some regions of the country changed overnight from using vertically-integrated local monopolies to make power decisions to a decentralized market-based auction system. Cicala constructed a virtually complete hourly characterization of U.S. electric grid supply and demand from 1999 to 2012 and compared the data in wholesale electricity markets versus regulated command-and-control areas before and after the market was introduced. In doing so, Cicala looked at two key measures: “out of merit” costs and trade across utility service territories.

The “out of merit” costs occur when power plant operators don’t use the lowest-cost available plants because those plants are forced to go off-line for maintenance or some other reason. The additional cost of output from the more expensive plants relative to the lowest-cost units is the out of merit cost. The study finds that power plant generators operating within markets are more likely to ensure their power plants are available to run when it is most economical for them to run. This means the lowest-cost plants are used 10 percent more often in market regions—reducing out of merit costs by nearly 20 percent.
Trade between utilities is also a factor. When importing electricity from another area, one could save having to fire up a more expensive unit. When exporting, one could gain any additional revenue beyond that required to generate the power. The study finds that generators operating within markets are able to better identify low-cost generators across areas and better coordinate the dispatch of power, increasing trade by 10 percent. The savings from these transactions increases by 20 percent a year.

“Some policymakers are right now deciding whether their state should join a market system, while others are deciding whether they should return to the regulated approach,” says Cicala. “While these markets are certainly vulnerable to market power, this study shows that previously unmeasured cost reductions far outweigh those losses."

January 9, 2017

Abstract:
This paper measures changes in electricity generation costs caused by the introduction of market mechanisms to determine output decisions in service areas that were previously using command-and-control-type operations. I use the staggered transition to markets from 1999- 2012 to evaluate the causal impact of liberalization using a nationwide panel of hourly data on electricity demand and unit-level costs, capacities, and output. To address the potentially confounding effects of unrelated fuel price changes, I use machine learning methods to predict the allocation of output to generating units in the absence of markets for counterfactual production patterns. I find that markets reduce production costs by $3B per year by reallocating output among existing power plants: Gains from trade across service areas increase by 20% based on a 10% increase in traded electricity, and costs from using uneconomical units fall 20% from a 10% reduction in their operation.

Tuesday, January 17, 2017

Utilisation of rice residues for decentralised electricity generation in Ghana: An economic analysis

Highlights
• Economic viability of decentralised electricity from rice residue in Ghana is studied.
• Electricity produced from straw combustion ranged between 11.6 and 13 US cents/kWh.
• Residue cost contribute 49–54% of electricity production cost from straw combustion.
• Husk gasification mini-grids are cheaper than other rural electrification options.
• Husk gasifiers should be promoted in remote rural communities of Northern Ghana.

Abstract
Developing countries, especially in Sub-Saharan Africa, face large challenges to achieve universal electrification. Using the case of Ghana, this study explores the role that rice residues can play to help developing countries meet their electrification needs. In Ghana, Levelised Electricity Costs (LEC) of a grid-connected 5 MWe straw combustion plant ranged between 11.6 and 13.0 US cents/kWh, based on region of implementation. Rice straw combustion is a viable grid-connected option in all regions, as the bioenergy Feed-in-Tariff is 29.5 US cents/kWh in Ghana. Residue supply cost contributes significantly (49–54%) to LEC of rice straw combustion.

LEC of husk gasification mini-grids ranged between 5 and 53 US cents/kWh for rural populations between 3000 and 250 people. Husk gasification mini-grids can be a suitable electrification solution for these un-electrified populations, as its LEC is lower than the average LEC of grid extension diesel mini-grids and off-grid solar systems for remote communities in Ghana. Electricity produced from husk gasification has the potential to cater to 7% of the needs of un-electrified communities in Ghana. The methodology and analysis of this study can support policymakers of similar countries decide the economic feasibility of decentralised bioenergy solutions while forming national electrification plans.
by Pooja Vijay Ramamurthi 1, , , Maria Cristina Fernandes 1, Per Sieverts Nielsen 2, Clemente Pedro Nunes 1
a CERENA/DEQ, Instituto Superior Técnico, Universidade de Lisboa, Av. Rovisco Pais, 1049-001 Lisboa, Portugal
b DTU Climate Centre, Systems Analysis, Department of Management Engineering, Technical University of Denmark, Denmark
Volume 111, 15; September, 2016; Pages 620–629
Keywords: Rice residues; Electricity access; Economic feasibility; Rural electrification; Levelized Electricity Cost; Ghana