October 24, 2013

The Energy Industry's Positive Contribution to the U.S. Economy

By Paul Traub

The U.S. Census Bureau announced in August in its U.S. International Trade in Goods and Services Report for June 2013 that the petroleum[1] deficit had fallen to its lowest level ($17.4 billion) since August 2009 ($17.9 billion). This decline was the result not only of declining imports but also of an increase in exports. The petroleum trade deficit was reported to be down $34 billion dollars, year over year, through June. The use of new technology and techniques to extract natural gas and other petroleum products has allowed the U.S. to go from being a net importer of refined petroleum to being a net exporter. What impact will this new technology have on U.S. economic growth in the years to come?

According to an August 18, 2013, Financial Times article, “the value of petroleum and coal exports more than doubled from $51.5 billion in the year to June 2010 to $110.2 billion in the year to June 2013.” To look deeper into the role the U.S. will play in the future in the global energy markets, we constructed a combined energy trade category using U.S. Census Bureau’s trade data by North American Industry Classification System (NAICS), among other sources.[2] Chart 1 shows just how much the balance in energy related trade has changed since 2002 by quarter.

Based on this total energy trade category, the United States imported about 10 times more petroleum related products than it exported in 2002, as indicated by the bars in the chart. This ratio of imports to exports grew to as high as 14 in the fourth quarter of 2005. The lines in the chart show that this happened while exports and imports grew by relatively the same ratio compared with 2002. However by 2006:Q4, this relationship started to change. Even with the sharp decline in both imports and exports during the recession in 2008, the ratio of imports to exports continued to decline. The latest data for 2013:Q2 indicate that the U.S. is exporting about 12 times more energy related products than it did in 2002, bringing the import to export ratio down to 2.8. This represents a 360% reduction in the trade deficit for these combined categories, with almost all of that achieved in the past six years.

According to the U.S. Energy Information Administration (EIA), the U.S. is one of the world’s leading producers of crude oil and petroleum products. Table 1 below shows the total value of exports and imports by NAICS classification and their share by category for calendar years 2002 and 2012.

Although the deficit did grow from 2002 to 2012, in 2002 crude petroleum and natural gas accounted for almost 85% of the total trade deficit, while petroleum refinery products accounted for about 70% of exports. Also in 2002, coal[3] was the only product of the four NAICS classifications that made a positive contribution to the trade balance. By 2012, crude petroleum accounted for almost the entire energy-related trade deficit, while the contribution to the deficit from liquid natural gas had fallen to just 0.3%. In addition, petroleum refinery products’ positive contribution to the trade balance jumped past coal’s to reach 81% of the total energy-related export products.

So far in 2013 the picture has improved even more. The following charts show just how much faster the exports of each of these energy-related products have grown relative to imports to the degree that three of the four categories shown here had a positive contribution to the trade balance in Q2 2013 evidenced by the exports to imports ratio of less than one. In fact, in Q2 2013 the U.S. exported three times more liquefied natural gas than it imported. In addition, the exports of petroleum refinery products have grown by an astonishing 1,380% since 2002.

Coal exports, which had grown 1,000% by 2011, have slowed more recently, likely reflecting slowing economic growth in China and falling prices in Asian markets.[4] As the chart 6 suggests, U.S. energy exports and the pace of emerging market growth have gone hand in hand in the past.

Given the somewhat slower global growth expectations for this year and next, it is reasonable to assume that U.S. energy exports are being somewhat limited by the global slowdown of emerging economies in particular, implying that the U.S. trade deficit reduction might otherwise have been even greater this year.

For January through June 2013, the petroleum trade deficit was reported to be down $34 billion dollars, year over year. If we include coal and refined petroleum products, the trade deficit decline was somewhat smaller at $31 billion, when adjusted for inflation, mostly due to a slowing global demand for coal. However, this trend is expected to reverse itself in the near future, according to the EIA International Energy Outlook for 2013. The EIA forecasts that global demand for all types of energy[5] will continue to grow at an annual rate of 1.5% for the next 30 years; and that, by 2015, the world’s demand for energy will increase by 9.1% compared with 2010 and an additional 10.1% by the year 2020. Also, by 2015, global demand for natural gas and coal is expected to increase by 9.3% over 2010 levels and an additional 9.5% by 2020. All of this is good news for the U.S. trade balance, because most of the growth in demand is expected to come from other countries. Based on EIA’s 2013 projections, non-OEDC countries will account for 86% of the total increase in energy consumption between 2015 and 2040.

Through the first two quarters of 2013, the U.S. economy is thought to have grown by just $227.2 billion compared with the first half of last year, while energy trade accounted for a $31 billion reduction in the trade deficit for the same period. This means that through the first half of 2013, while the total U.S. economy is estimated to have grown by just 1.5%, the increase in energy exports accounted for 13.6% of total growth in this period by significantly reducing the trade deficit.

Since 2008, the global demand for energy has continued to increase; it is presently expected to grow by 1.2% in 2013 compared with just 0.7% in 2012. This projected increase in global demand for energy should contribute further to economic growth in the U.S. through additional reductions in the trade deficit.
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[1]The petroleum products aggregated in the end-use commodity classification system include virtually the same energy related products as those aggregated in the Standard International Trade Classification (SITC). The end-use petroleum products, however, include some products such as ethane, butane, benzene, and toluene which are included in “Manufactured Goods” in the SITC. (Return to text)

[2]The “Total Energy Trade” category contains the following NAICS series: Crude Petroleum and Natural Gas (211111), Liquid Natural Gas (211112), Coal (excluding Anthracite) and Petroleum Gases (212112), and Petroleum Refinery Products (324110). (Return to text)

[3]Coal (excluding Anthracite) and petroleum gases will be referred to as coal throughout the remainder of the article. (Return to text)

[4]Chen, Sarah. “China Coal Prices Fall to a Four-Year Low Amid Economic Slowdown” Bloomberg.com, Bloomberg News, 29 July 2013. Web. 28 Aug. 2013. (Return to text)

[5]EIA Energy classifications are defined as liquids, natural gas, coal, nuclear and other. (Return to text)

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February 25, 2013

Conference to Explore the Economic Impacts of Enhanced Domestic Energy Production from Shale Gas and Oil Extraction

New technologies and techniques to extract natural gas and gas liquids, as well as petroleum, from shale rock have greatly altered expectations for North America’s capacity to produce energy products. As a result of innovations such as hydraulic fracturing, some government, industry, and academic observers have predicted that the United States will soon become energy self-sufficient and possibly become a net exporter of natural gas and petroleum.

Leaders from both specific markets and regions are looking at the opportunities and challenges associated with the so-called energy production revolution ushered in by the new means to access natural gas and other fuels. Indeed, many from potential energy-producing regions are assessing the trade-offs between economic growth associated with expanded gas and oil production and the risks to the environment that this production may pose. For those from other regions, an energy boom based on shale gas and oil extraction may present opportunities in many different arenas. For instance, some regions will especially benefit from lower consumer prices for home heating and cooling. Similarly, switching to natural gas from diesel in the long-haul trucking industry to take advantage of low natural gas prices may help bring about lower delivery costs for a wide spectrum of household and business goods. Additionally, several parties in regions historically reliant on manufacturing, such as the Midwest, are hoping that low energy prices will bring about new development and jobs in energy-consuming manufacturing sectors, such as chemicals and plastics. Furthermore, greater energy production and chemical manufacturing may lead to more supply chain linkages, which can be developed by regional and local economies.

Our April 8–9, 2013, the Chicago Fed’s Detroit Branch will host an event to discuss the impact of enhanced domestic recovery of natural gas and other fuels on industries and regional economies. The conference will focus on the shifting markets, development opportunities, and economic outcomes resulting from greater shale gas and oil extraction in the United States. We will be meeting at our Detroit Branch from the afternoon of April 8 through early afternoon the next day.

For further details on the conference, including its agenda, and information on accommodations, please click on this conference link.

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December 10, 2012

Fossil Fuel Prospects and Location

In mid-November, the International Energy Agency forecasted that “extraordinary growth in oil and natural gas output in the United States will mean that … the United States becomes a net exporter of natural gas by 2020 and is almost self-sufficient in energy, in net terms, by 2035.” Similarly, the U.S. Energy Information Administration recently revised its long-term outlook, and reported U.S. energy production growing faster than consumption through (at least) year 2040. This startling turnabout is due, in no small part, to recent advancements in U.S.-born technologies in the drilling and recovery of hydrocarbon fuels—natural gas, gas liquids, and petroleum. Already over the past several years, U.S. production of these fuels has boomed due to commercial development arising from these technologies.

In the past month, two experts on emerging developments in this area reported at conferences held by the Federal Reserve Bank of Chicago. At the recent Economic Outlook Symposium, Loren C. Scott discussed U.S. and global energy developments. He presented a sanguine view on U.S domestic production from natural gas and petroleum resources.

In fact, promising geological formations for gas and oil production can be found throughout the globe (See map). However, the U.S. has been far out in front in developing the technologies to extract these resources, as well as the commercial foundation that has enabled production enterprises to bring them to market.

On the production side, Scott argued that the recent development of these fuels has been aided by fortuitous conditions in the U.S.—conditions that will not soon be replicated elsewhere in the world. Not only were the technologies developed here, but necessary pre-conditions of development were in place. In particular, property rights for minerals located beneath privately held land belong to landowners here, and these can be readily sold and transferred to would-be developers. Such conditions do not hold in most other nations, where mineral rights may be ill-defined or owned by the government. Furthermore, opposition from environmental groups is far more vociferous in other nations, especially in many parts of Europe, which is also home to significant geological deposits.

The availability of a network of pipelines to transport natural gas is another pre-condition for development that has already been met in parts of the U.S. Owing to previous generations of energy exploration, development, and delivery of fossil fuels across the U.S., much of the pipeline infrastructure is already in place to transport gas from field to consumers.[1]

On the demand side, Scott said that expanding supplies of natural gas will in turn expand market usage by 2–3 trillion cubic feet annually, or about 10% of recent domestic consumption. In particular, natural gas will find two ready markets, possibly three.

For one, domestic manufacturers—especially in several chemical sectors—stand ready to absorb available natural gas at favorable prices. In particular, producers of ammonia nitrate fertilizers use natural gas as a primary feedstock. Similarly, ethylene is derived from natural gas liquids, and is used for plastics and vinyl in a wide range of products from housewares and toys to vinyl pipes. Currently, ethylene is derived from petroleum products in Europe, which puts producers there at a serious price disadvantage relative to U.S. producers.

Natural gas will also easily become a more important boiler fuel in electric power generation. Scott forecasted that natural gas will displace increasing amounts of coal-fired generation, especially two to three years from now when environmental regulation of coal-fired facilities begins to tighten in earnest.

A third source of possible market expansion is U.S. exports. Currently, global trade in natural gas (in liquefied form) is very small compared with petroleum, for example. One reason for that is that extensive infrastructure is needed to liquefy, load, and transport natural gas. Even so, such investment may be motivated by the wide price differentials between the U.S.’s output and that of potential importing nations. For example, Scott cited spot market prices at $2–3 per million btu in the U.S., versus import prices of $11 in Europe and $16 in Japan. Despite these favorable price spreads, the development of exports from the U.S. will be challenged by both costly new infrastructure need for global shipment, and by resistance from domestic gas users, who will likely push for statutory trade restrictions on exports.

With regard to legal impediments to shale field production and sale, Scott argued that the widespread location of resources across the U.S. will likely keep federal regulation and restrictions contained. At a November 27 conference on Farmland Leasing, Ross H. Pifer of Penn State University reported on the leasing of mineral rights in the Marcellus shale region of New York, Pennsylvania, Ohio, and West Virginia. As the map shows, shale deposits are widespread across the nation, including some deposit locations in each of the Seventh District states. The Energy Information Administration reports “active plays,” involving development or pre-development in parts of the Antrim Basin in Michigan and in the New Albany Basin of southern Indiana (and northern Kentucky).

Across the U.S., several areas of shale have been producing natural gas in recent years, ranging from Texas to North Dakota to the Northeast states. Looking ahead, however, Pifer cited a 2009 assessment of the location of recoverable gas reserves that reported a high geographical concentration in the Marcellus shales. In that report, the EIA estimated that the Marcellus shales contained 410 trillion cubic feet of natural gas (tcf), representing 54.7% of the Lower 48’s “reserves.” In contrast, the Antrim deposits (Michigan) were estimated to contain approximately 20 tcf, and the New Albany deposits (Indiana) 11 tcf.[2] To put these quantities in context, the U.S. consumed approximately 24 tcf of natural gas in 2011.

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[1] One exception to this is the so-called Bakken Field located in western North Dakota, eastern Montana, and across the border in Canada. There, sufficient pipeline infrastructure to market is inadequate for carrying petroleum and other liquids to markets and refineries. (Return to text)

[2] Note that estimates of reserves can vary widely and with great uncertainty. Note also that these reserves report on natural gas reserves only, excluding petroleum. Several formations also contain significant petroleum reserves. (Return to text)

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November 14, 2012

Will America’s Boom in Energy Production Give Manufacturing a Boost?

Falling prices for natural gas have encouraged those who believe that manufacturing activity will rebound in the years ahead. While abundant supplies and dampened prices for natural gas are certainly positive developments for U.S.[1] manufacturing, the impacts may be modest in sum. Energy materials and fuel costs are important to many types of manufacturing processes and industries, but such factors are not always commanding considerations in manufacturing production and siting decisions. Additionally, while the outlook for domestic energy production looks robust, the outlook for large price declines may be limited because of the competing uses for natural gas, both at home and abroad.

The domestic recovery of fossil fuels—especially that of natural gas—has been on the rise in recent years. Since the middle of the previous decade, technological breakthroughs in natural gas recovery have boosted natural gas production and supplies. These enhanced recovery techniques include horizontal drilling through shale rock in search of gas deposits, accompanied by pressurized fracturing of shale rock, which releases gas (and energy liquids) for recovery. Accordingly, natural gas production from shale deposits has expanded rapidly, increasing its share of overall U.S. gas production to 23% in 2010 from less than 7% in 2007. One long-term forecast concludes that this trend will continue—more specifically, under the assumption that current laws and regulations will stay the same over the projection, shale gas production is predicted to rise “from 5.0 trillion cubic feet per year in 2010 (23 percent of total U.S. dry gas production) to 13.6 trillion cubic feet per year in 2035 (49 percent of total U.S. dry gas production).” As a result of this additional fossil fuel recovery, it is projected that overall domestic gas production will expand by 30% on an annual basis by the year 2035.

So far, expanded production of natural gas has translated into falling prices. Earlier this year, prices for natural gas on the spot market (i.e., the cash market, in which this commodity is traded for immediate delivery) plummeted following a period of extensive exploration and recovery activity.[2] From the late fall of 2009 to the spring of 2012, the spot price for natural gas per million British thermal units) fell from $6 to $2 (see the chart below). Since that time, drilling and recovery activity have been curtailed in response to plummeting prices, so that prices have recovered to some extent. The firming of prices has also been bolstered by the greater use of natural gas (instead of coal) in generating electric power.


Source: Wall Street Journal/Haver Analytics

Whether or not enhanced natural gas production will translate into lower domestic prices for industrial users over the long haul will depend on several factors. For one, as just mentioned, natural gas can be substituted for competing fuels in other sectors. Currently, for example, natural gas is being substituted for coal in the electric generating industry. Competing demands such as these may tend to buoy the price of natural gas, even as overall supplies are increasing.

The transportation sector is the largest fuel-consuming sector in the United States (outside of the electric power generating sector), and it is almost wholly dependent on gasoline derived from petroleum. In the event that a larger percentage of cars and trucks were modified so that they could use natural gas, the competing demand for this fuel might also sustain upward pressure on its price. Currently, natural-gas-powered vehicles consume a small fraction of the transportation sector’s overall fuel use. The service fleets of vehicles that are maintained by commercial businesses and governments account for most of the natural gas consumption within the transportation sector. However, the technology to adapt vehicles for natural gas consumption is well developed.[3] The major impediment to broader modification of vehicles so that they are powered by natural gas is the additional infrastructure required to transport natural gas from wells and pipelines to commercial filling stations across the country.

The ultimate impact of rising domestic production of natural gas on our manufacturing may also be affected by international demand for natural gas. A set of complex dynamics will affect whether the nation imports or exports (on net) natural gas. To date, the United States has been a net importer of natural gas from neighboring countries. However, in the event that domestic production continues to grow rapidly, market conditions may one day encourage U.S. producers to export the product. If so, the price of U.S.-produced natural gas would then become more in line with global energy market prices.[4] To the extent this were to happen, the use of natural gas as a domestic input to manufacturing would be discouraged by the higher prices that could be commanded in international markets.[5]

Even if we assume that natural gas prices remain depressed here, we may still ask if the fuel is an important part of the cost structure for manufacturing. If natural gas turns out not to be a major factor in this cost structure, then the choices in the siting of manufacturing plants that favor the United States would be somewhat limited.

Undoubtedly, industrial processes (including those of the manufacturing sector) consume large quantities of natural gas and other fuels. For 2011, industrial uses accounted for one-third of overall U.S. natural gas consumption; and the industrial sector counted natural gas as its single largest fuel source, just ahead of petroleum (see below).


Source: Author's calculations based on data from the U.S. Energy Information Administration

However, as a share of industrial production costs, energy inputs are a somewhat modest component at the present time.[6] The chart below illustrates the energy content of overall U.S. manufacturing as measured against output (i.e., “value added”). The manufacturing sector’s overall consumption of all energy-type products—including electricity, energy product feedstock, and natural gas—amounts to close to 8% of value added in 2010. (Natural gas alone makes up a smaller share, nearly 3%.) In contrast, labor costs makes up almost 26% of value added in 2010.[7]


Sources: Census Bureau/Haver Analytics and U.S. Energy Information Administration

Though energy costs do not make up, on average, a large share of the overall value added of the U.S. manufacturing sector as a whole, this is not the case for certain manufacturing subsectors. The first table below ranks U.S. manufacturing subsectors from highest to lowest according to non-electricity fuel intensity from all sources. The highest ranking industry subsector, nitrogenous fertilizer, is a huge user of energy material, most of it being natural gas (see second table below). The nitrogenous fertilizer industry spends 125% of value added on non-electricity fuel products and 117% of value added alone on natural gas—principally as a feedstock into the production of fertilizer. However, many of these energy intensive subsectors are small and do not make up large shares of overall U.S. manufacturing production at the present time. All told, for example, the top 15 most fuel-intensive industries account for less than 10% of total U.S. value added in manufacturing. The top 15 natural-gas-consuming industries account for less than 4% of total U.S. manufacturing production.


Click to enlarge.
Source: Author's calculations based on data from the U.S. Energy Information Administration
Note: Both consumption and expenditure exclude purchases of electricity.


Click to enlarge.
Source: Author's calculations based on data from the U.S. Energy Information Administration

Despite this modest share of energy-intensive industries in overall U.S. manufacturing, low energy costs (and the greater availability of energy) in certain states do tend to attract the most energy-intensive industries. The table below ranks those states having the most energy-intensive mix of industries as measured by the consumption of fuel product per dollar of manufacturing (second column). Energy-producing states tend to dominate the list because energy products are abundant there and because fuel prices are lower closer to the point of production (on account of the lower transportation costs). In contrast, although much more overall manufacturing activity is located in the Seventh Federal Reserve District relative to the nation (last column), the District’s industry mix tends to be less intensive in average fuel use.


Click to enlarge.
Source: Author's calculations based on data from the U.S. Energy Information Administration
Note: Physical energy includes raw energy materials consumed in the electric generating process. Expenditure includes purchases of electricity.

The table below specifies the employment concentration of the nation’s 25 most natural-gas-intensive industries. Many of these industries have tended to locate in the Seventh District, and they may choose do so to a greater extent in the future should natural gas become cheap and abundant here.[8]


Click to enlarge.
Source: Author's calculations based on data from the County Business Patterns, U.S. Department of Commerce.

The boom in natural gas production in the U.S. will undoubtedly encourage some manufacturing activity. However, under several scenarios, the benefits of abundant natural gas are likely to be spread broadly across the U.S. and Midwest economies rather than being concentrated in the manufacturing sector alone. In particular, natural gas usage will likely make inroads into many sectors, such as electric power generation and transportation. In this way, the (lower) price effects, should they come about, will also be distributed across many sectors. If so, these competing demands will tend to limit the potential price decline of natural gas and the associated upside in manufacturing activity. Similarly, the possibilities for exporting natural gas will tend to buoy its price for domestic purposes, including those for the industrial sector (dampening its increased level of activity).

Note: Thanks to Norman Wang for excellent research assistance, and to Han Choi for editorial work.

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[1] See, for example, “Europe Fears U.S. Energy Gap,” Financial Times. (Return to text)

[2] Note that most natural gas is not sold on the spot market; rather, it tends to be sold under longer-term contracts. Accordingly, these prices do not generally reflect the average prices paid for natural gas consumed. (Return to text)

[3] See Conference on “Energy Use in the U.S. Trucking Sector,” Resources for the Future. (Return to text)

[4] The U.S. Department of Energy’s baseline forecast expects that because of the expansion of natural gas production, the United States will eventually become a net exporter of natural gas by early in the next decade. Longer-term projections by the U.S. Energy Information Administration (EIA) predict that real prices will remain largely flat over the next ten years. (Return to text)

[5] However, high transportation and production costs of domestic natural gas for export would mean that its price would remain somewhat lower for domestic use. And again, there are large infrastructure investments to be made to achieve capacity to export natural gas.+(Return to text)

[6] This qualification may be an important assumption. Presumably, if energy costs fell very dramatically, the industry mix of manufacturing in the United States would shift, perhaps decidedly, toward those types of products and processes that heavily consume energy. (Return to text)

[7] Note also that the energy efficiency of U.S. manufacturing (blue line) has been increasing over time. Here, we take a broad view of energy intensity—i.e., including all fuels rather than natural gas alone—because fuel substitution may be widely feasible in many production processes. (Return to text)

[8] For a current map of the location of both feasible shale rock formations, along with “current plays” in producing natural gas, see here. (Return to text)

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June 8, 2012

Natural gas and the Seventh District

U.S. energy markets are undergoing significant upheaval because of the surging domestic production of natural gas and accompanying falling prices for this commodity. Enhanced production of natural gas has come about because of technological gains in gas extraction—namely, enhanced techniques for the fracturing of shale deposits and horizontal drilling. One of the main motivations for exploring domestic soil for more natural gas is the climbing prices of petroleum products that the U.S continues to import to a significant degree. If environmental concerns associated with extracting shale deposits can be resolved, natural gas offers an abundant, widely available, and secure energy source in the lower 48 states.

As seen below, wholesale natural gas prices have fallen considerably in recent months. For gas purchased on the spot market (where transactions for gas needed within a matter of days, rather than months, are completed), prices have fallen by over one-half. Unfortunately, though such spot market prices are telling, they do not reflect the ultimate prices paid by end-users. That is because much of the natural gas product is purchased on long-term contracts, whereby the prices do not yet reflect recent production capabilities and output. Equally important, it takes much infrastructure, especially pipeline and storage, to bring the product to the location where it can be productively used. And so, depending on the location of use, and the type of user, natural gas prices vary to a great degree.

For example, falling prices for natural gas have not helped much in the transportation sector, since existing infrastructure does not (yet) allow much natural gas to replace gasoline and other fuels. However, in other sectors of the U.S. economy, the use of natural gas is much more important. Overall, natural gas accounts for 25% of total U.S. energy use (though petroleum fuels and products are about one-third higher than that).[1]

Fuel use is changing somewhat, however. Much of the nation’s electric power generating industry burns natural gas in its processes. As a result of the favorable price movements for natural gas, electric power generation has been recently moving away from coal to natural gas. Year-to-date in 2012, for example, purchases of coal by the electric industry have fallen by 4.5%, while purchases of natural gas have risen by 28%.[2] The switch to natural gas has helped moderate electricity price hikes to end-users over the past two years. More specifically, electricity price containment has been most apparent among industrial users whose overhead and delivery costs for power have not been so prominent.[3]

States and regions will be affected differently by swings in fuel prices for a variety of reasons—for instance, their differing economic structures, as well as the particular options of fuels and facilities that their electric utilities and power producers have chosen historically. To illustrate the effects of such differences, the U.S. Energy Information Administration (EIA) produced the map below. The size of the circle denotes the per capita natural gas usage across all uses in each individual state. It is not surprising to find that per capita use of natural gas is very large in those states where it is produced, such as Texas, Louisiana, and Oklahoma. Using natural gas near the point of production saves on the costs of transporting this fuel. And so, for example, since natural gas is used as feedstock in many chemical industries, these facilities have been sited in South Central states to high degree. Moreover, as "shale gas" is increasingly being extracted in several northern climes, certain industries in the plastics and chemicals sectors have begun to follow.

In the same figure, the divisions within each circle show the uses of natural gas within the state—for the generation of electric power, for industrial purposes, or for residential and commercial uses. The last category is principally for space heating of residences and other buildings. Though coal remains the principal fuel for electric power generation, natural gas for this particular purpose figures large in some states of the Far West, South, and Northeast. In the Midwest, natural gas tends to be used for heating residences and other buildings and for industrial purposes. Virtually all states in the lower 48 use natural gas in one or major sectors. States of the Seventh District are no exception, so that favorable developments in the production and delivery of the fuel will be especially helpful in the region’s industrial, residential, and commercial sectors. While District states do not tend to use gas in electric power generation to the same extent as the U.S., even here the District would tend to benefit from falling prices. To the degree that coal and natural gas fuels compete in national markets, falling gas prices and enhanced usage will tend to dampen price pressures on coal as well.


Source: U.S. Department of Energy, U.S. Energy Information Administration.
Click to enlarge

Data from the EIA’s State Price and Expenditure Database offers a finer breakdown of natural gas usage in the Seventh Federal Reserve District, which comprises all of Iowa and most of Illinois, Indiana, Michigan, and Wisconsin. In the table below, natural gas consumption in 2010 is normalized by the size of each state’s gross economic output (GSP). Overall, one can see that the Seventh District economy depends on natural gas to a modestly greater extent than the national average per dollar of GSP. The residential and industrial sectors are the largest natural-gas-consuming sectors in the Seventh District.

In residential and commercial sectors, each state of the Seventh District tends to use natural gas more intensively than the U.S. In contrast, relative to the nation, Seventh District states tend to use other fuels for generating electricity—coal in Wisconsin, Indiana, Michigan, and Iowa and nuclear power in Illinois. On average, the Seventh District’s industrial use of natural gas is on par with the nation’s, though with notable state-by-state differences. For instance, Iowa and Indiana are heavy users of natural gas in their industrial processes.


Sources: U.S. Energy Information Administration (EIA) and U.S. Bureau of Economic Analysis.
Click to enlarge

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[1]These data are drawn from the Consumer Price Index for all urban consumers nationally. Motor fuel prices represent prices for unleaded regular gasoline. Home heating fuel price reflects piped gas to residences.(Return to text)
[2]These values are reported as measured in physical units. See U.S. Department of Energy, U.S. Energy Information Administration (EIA), 2012, Electric Power Monthly, Table ES2.A.(Return to text)
[3]U.S. Department of Energy, U.S. Energy Information Administration (EIA)., 2012, Electric Power Monthly, Table 5.3.(Return to text)

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May 1, 2012

Recent Energy Price Movements in the Midwest

Households in the region and nationwide have been affected by rising motor fuel prices in recent months; this follows an earlier spike that took place in 2007–08. Such price spikes ordinarily pinch household incomes and spending on non-fuel items. However, at the same time, natural gas prices have been trending downward, thereby providing some relief to household budgets. This is especially true in the Midwest, where most homes are heated with natural gas that is piped in by utility companies. So, to what extent has the favorable trend in natural gas prices been offsetting the unfavorable trend in motor fuel prices?

The chart below displays prices paid by household consumers for both types of fuel[1]. Prices for both natural gas and gasoline have typically moved in tandem. In many instances, this is because the two fuels are substitutes in several important markets and uses. For example, if either petroleum products or natural gas can be used in applications such as heating industrial boilers or homes, the price of one could not easily fall out of line with the other. If it started to do so, consumers would switch to the cheaper product, thereby raising its price.


Sources: Bureau of Labor Statistics /Haver Analytics. Motor fuel price represents regular unleaded fuel as reported in the CPI-U.

However, in the near term, limits on infrastructure for either transporting fuel or using it can allow fuel prices to diverge. Beginning in 2009, petroleum prices began to climb, largely reflecting its scarcity on world markets. And so, motor fuel prices are up sharply “at the pump.” On the other hand, domestic natural gas tends to be more of a locally traded commodity with little ready adaptability for use in highway transportation. In addition, technological developments in on-shore natural gas production have meant that the available supply has been climbing rapidly. On-shore producers of natural gas have used a combination of hydraulic fracturing of gas trapped in shale rock formations, along with horizontal drilling techniques, to greatly expand U.S. natural gas production since 2005. As a result, natural gas prices “at the wellhead” have fallen to near-record lows in recent months. For instance, the spot market price at a well-known trading point called the “Henry Hub”[2] has fallen to close to $2 per thousand cubic feet, far below its average of $5 since 2008.

However, natural gas prices for home uses have not fallen nearly so steeply. That is because the price of home heating fuel reflects much more than the fuel price; it also reflects a sizable infrastructure of pipelines (and underground storage systems) that are necessary to deliver the fuel to far-flung residences. For all of 2011, the estimated price of natural gas delivered to residences averaged $10.80 per thousand cubic feet, which was well over 2.5 times the wellhead price.[3]

Falling prices for natural gas have been very welcome news to Midwest households, who have seen their home utility bills for natural gas edge downwards in recent years. In addition, due to abnormally mild temperatures this past winter, lower consumption of home heating fuel also helped to ease pressures on household budgets. Midwestern households rely on natural gas more than the national average, especially for home heating purposes. As of 2009, an estimated 72 percent of the region’s households received piped gas at their homes versus 57 percent for the rest of the U.S.[4]

However, average annual expenses for home heating do not approach annual expenses for motor fuel—even for midwesterners. At 2010 prices, for example, we estimate motor fuel expenditures to have been 3.2 times average expenses for residential natural gas in the broad Midwest region.[5] For this reason, the declines in residential gas prices since 2010 have not offset the rises in motor fuel. Yet, the boom in domestic production of natural gas, and its moderating effect on natural gas prices at the wellhead, have acted as a stablizing influence on household incomes in the region.


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[1]These data are drawn from the Consumer Price Index for all urban consumers nationally. Motor fuel prices represent prices for unleaded regular gasoline. Home heating fuel price reflects piped gas to residences.(Return to text)
[2]The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange. (Return to text)
[3]www.eia.gov/naturalgas/monthly/pdf/table_03.pdf.(Return to text)
[4]Estimates derived from U.S. Dept. of Energy, Energy Information Administration (EIA), Fuel Use Survey, table HC1.9. Of those receiving piped gas, over 90 percent use it as their primary space-heating fuel. Due to continued production expansion of shale gas, the Energy Information Administration forecasts continued stable to falling home heating fuel prices in the years ahead. (Return to text)
[5]Per household, the 2010 figures average $2,019 for annual motor fuel and motor oil expenditures, $634 for residential heating. Residential energy expenditures (principally for home heat) are from EIA, State Price and Expenditure Database. Residential motor fuel prices, households, and consumption are from U.S. Department of Labor, Bureau of Labor Statistics, Consumer Expenditure Survey. The Midwest geography is here defined as the states of OH, MI, IN, WI, IL, MN, IA, MO, NE, ND, SD, and KS.(Return to text)

Posted by Testa at 8:09 AM | Comments (0)

August 13, 2008

Energy Prices and Where We Live and Work

For those of us who are aged 50 and older, it is easy to forget that younger generations did not experience the energy crunch of the 1970s nor the many (often failed) public policy responses to the OPEC oil price run-ups. With today’s similar developments in energy markets, it is fascinating to compare the two eras. In some ways, history repeats itself. In other ways, it does not.

The auto industry upheaval appears to be repeating the 1970s. As then, domestic automakers (and their fuel-consuming fleets) are suffering dearly from the sudden hike in gasoline prices; foreign-domiciled automakers, not so much. In both the 1970s and today, the vehicles of Asian automakers tend to be smaller and more fuel-efficient. Unlike the 1970s, however, today even Toyota is paying for its lurch toward large vehicles such as its large pickup truck, the Tundra.

Another apparent similarity between the eras is that some analysts are predicting that rising fuel costs will reshape our patterns of living and working toward more compact urban forms, to the detriment of far suburban and rural areas. However, the actual shifts that took place in the landscape of America surprised us somewhat during the 1970s and early 1980s.

The U.S. was already well-suburbanized by the mid-1970s. But in response to higher fuel prices, it was commonly thought that beleaguered central cities were in store for some respite from the population flight that they had been experiencing. With their denser housing patterns, high job concentrations, and well-developed public transit systems, large cities would offer shelter from high gasoline prices. In suburban and rural areas, where driving distances were long, residents would pay the price. The pace of suburban sprawl would slow, the pace of rural shrinkage would accelerate. For those of you too young to remember, these predictions did not come to pass.

These same predictions are being made today as gasoline prices have doubled. In a recent study, Joseph Cortright offers evidence that shifts toward more compact cities are already underway, as households eschew housing on the urban fringe where commuting distances are long. Indeed, in large metropolitan areas like Chicago, housing prices in closer-in neighborhoods have been holding up relatively well over the past year. The era of urban sprawl has been pronounced dead, with households and employers expected to favor greater density as a way to economize on energy-related travel costs.

However, the contrast between expectations in the 1970s and what actually came to pass may give us pause in assessing today’s predictions. Just the opposite took place in the 1970s era. Central cities of large metropolitan areas, especially in the Northeast and Midwest, experienced their worst decade of the century. Population tended to flee to the suburbs, especially middle and upper middle income residents. The apparent reasons for flight included rising crime, school desegregation, and the near-completion of an interstate highway system that funneled homeowners to cheap and abundant housing on the perimeter.

While rural areas in some areas of the U.S. did continue to decline, on the whole the 1970s was hailed as the decade of the “urban to rural turnaround.” The charts below indicate population growth over past decades for metropolitan versus nonmetropolitan counties. Though energy expenditures were higher on average for rural households, rising energy prices for coal, natural gas, and petroleum raw materials spurred a boom in exploration and mining in many parts of the U.S. Rural rebound was also spurred by a resurgence in prices and exports of agricultural commodities and processed foods. The falling exchange value of the dollar against world currencies following the dollar’s detachment from gold in 1971 was accompanied by favorable prices for U.S. foodstuffs on global markets. Faltering agricultural production in some foreign nations such as the former Soviet Union contributed to rising U.S. farm income. So too, thanks in part to the interstate highway system, some types of manufacturing began to discover rural areas as hospitable sites for production.


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Will these surprising patterns repeat themselves in the current era of high prices for energy materials? Rural areas are once again finding themselves amidst an energy and food commodity boomlet. Surging agricultural demand from developing nations has contributed to rising U.S. exports and commodity prices. The falling value of the U.S. dollar since 2002 has also contributed, as have the U.S. legal mandates and subsidies for the use of corn-based ethanol as a transportation fuel. In the Seventh District, the growth pattern in farmland prices looks much like the late 1970s and early 1980s, rising at double digits annually through the decade.

In other regions, coal mining and energy exploration activity are buoyant.

However, this time around, conditions would seem to favor central cities versus rural and far suburban areas more than in the 1970s. Rates of crime declined over the 1990s in most major U.S. central cities. Central city schools continue to struggle to educate and graduate low-income students, in particular. Yet, most such school systems enjoy greater financial stability, and many have innovated and expanded their offerings to serve populations who are diverse culturally, as well as economically. Rather than shunning large cities, many highly educated households are finding the older architecture, diverse community, and rich array of amenities in central cities attractive. To some degree, employers have followed educated employees back into central cities; or they have found that the density of the central city makes for more productive business activity in the “new economy,” which rewards face-to-face contacts in conjunction with sophisticated telecommunications. Should these recent trends continue, higher gasoline prices may only add one more advantage to the higher density of older central cities.


These trends may leave some suburbs on the fringe as the losers in the current era. The map below illustrates the average commuting time for suburban areas of the Chicago metropolitan area. Many households who buy or rent in suburban areas choose the low housing prices that such areas offer at the expense of longer trips to work. The sudden rise in gasoline prices may have left many such households with larger shocks to household budgets than their more urban counterparts. The Center for Neighborhood Technology in Chicago has constructed neighborhood maps of U.S. metropolitan areas which estimate average household expenditures for commuter travel. For Chicago and most other metropolitan areas, these estimates show that average household energy expenditures climb on the fringes of metropolitan areas. Even as measured as a share of household income, far-suburban households are more severely affected by rising fuel costs.


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Some revisionist interpretations of the 1970s experiences of “urban to rural” turnaround have also been made by analysts such as Paul Gottlieb. And it seems that the turnaround of that period has been overstated by an inherent bias of measurement—the tendency to overstate the population growth of nonmetropolitan counties during periods in which household growth is robust nationally. In such periods, population growth in nonmetropolitan counties can flip their defined status from nonmetro to metro, thereby inflating the measured pace of growth in consistently defined “nonmetro” counties.

Given the experience of the 1970s, it is difficult to draw firm and rapid conclusions concerning whether an era of higher fuel costs will reshape our urban, suburban, and rural landscape and, if so, how. To be sure, higher fuel costs have changed the desirability of work and residential locations. But we also know that households and businesses can adapt to such marked price shocks in other ways than moving. In particular, as today’s fleets of autos and trucks wear out, they will surely be replaced by more fuel-efficient vehicles, thereby allowing many long commutes and delivery trips to resume at moderated cost. Such was the case following the energy price shocks of the 1970s.


Note: Thanks to Vanessa Haleco-Meyer, Bill Sander, and Graham McKee for comments and assistance.

Posted by Testa at 10:33 AM | Comments (2)

September 25, 2007

Transportation and GHG regulation

On October 15, the Detroit Branch of the Federal Reserve Bank of Chicago will convene a conference examining various policy approaches to reducing carbon dioxide and other greenhouse gases (GHGs). Following electric power generation, the transportation sector is the second largest source of carbon dioxide emissions in the Midwest, as well as in the overall U.S. (Carbon dioxide emissions generally arise from the burning of fossil-based transportation fuel—gasoline more so than diesel fuel.)

Following the energy price spikes of the early 1970s, federal regulations were issued to improve fuel-efficiency of cars and light trucks. Corporate Average Fuel Economy (CAFE) regulations place fleet-wide fuel-efficiency limits on manufacturers for their passenger cars and separate standards for their light trucks (including so-called minivans and sport utility vehicles, or SUVs).

The CAFE standards are sometimes credited with maintaining fuel-efficiency during the late 1980s and throughout the 1990s, when gasoline prices plummeted and one might have otherwise expected vehicle size and fuel consumption to have grown once again. Nonetheless, CAFE standards are often criticized. For one reason, the added cost of introducing new fuel-efficiency technologies into the latest models may be counterproductive. That is because, in confronting higher vehicle costs, automotive buyers may delay scrapping their old vehicles, thereby keeping an older (and less fuel-efficient) fleet of vehicles on the road.

Fuel-efficiency standards have also been criticized for imposing unnecessary and distorting restraints on consumers’ choices of vehicles. Logically speaking, penalties to modify behaviors to align with socially desirable outcomes should be fashioned to most closely target those behaviors that give rise to social costs. Accordingly, rather than forcing fuel-efficiency standards on specific types of vehicles, a preferable approach would be to penalize the actual behaviors that give rise to carbon emissions regardless of vehicle type. That is, a tax on fuel at the pump would be preferred to vehicle fuel-efficiency standards. And a tax per unit of carbon associated with a particular fuel—such as gasoline over diesel—would be preferred to a general fuel tax. Nonetheless, to date, fuel-efficiency regulations have been more palatable to the American public than alternatives such as direct gasoline taxes.

Midwest-domiciled automakers, especially the Detroit Three (Chrysler LLC, Ford Motor Co., and General Motors Corp.), have so far found it more difficult than other manufacturers to achieve CAFE fleet standards on cars and light trucks. Going back to the 1970s and earlier, Detroit Three automakers have tended to offer larger vehicle models for sale, and this specialization has continued into recent years.

The figure below displays the reported average fuel economy in 2006 for major companies selling vehicles in the U.S. market. For both passenger cars and light trucks, the measures of fleet average fuel-efficiency for both Toyota and Honda easily exceed those of the Detroit Three. Indeed, for passenger cars, the fleet fuel economies of Honda and Toyota already approach the hypothetical standard that is being considered for the year 2020.


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CAFE standards may soon become even more onerous for automakers. In June 2007, the U.S. Senate passed legislation mandating stricter standards on both passenger cars and light trucks. By the year 2020, fuel-efficiency standards would rise for such vehicles so that they must achieve 35 miles per gallon. (Such revised CAFE standards will likely be considered by the U.S. House of Representatives during the fall of 2007).

The vehicle fuel-efficiency of major automakers has been changing in recent years. Per the figure displaying the fuel economies of passenger cars below, Toyota’s and Honda’s have gained markedly over those of the Detroit Three during the decade. In contrast, these Japanese automakers have not widened their fuel-efficiency advantages in the light truck category. Within the category, Honda and Toyota have been selling more models that are heavier and less fuel-efficient than they had before; these models would include the Honda Pilot and Toyota Land Cruiser SUV.


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From a Midwest perspective, the region’s light vehicle production facilities tend to be those of companies that will likely find it most difficult to meet more stringent standards. The map below displays the assembly plant locations of the Detroit Three automotive companies, as well as those of the foreign-domiciled automakers. A large majority of the Detroit Three’s light vehicle production facilities are located in Midwest states. In the northern part of the U.S. automotive corridor, which includes the states of Ohio, Michigan, Indiana, Illinois, Wisconsin and Missouri, 24 of its 31 light vehicle plants are owned by the former Big 3 domestics. Accordingly, the region’s residents will be interested to see that any prospective carbon reduction policies are as cost-effective as possible.


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Not everyone believes that GHGs from human activity are significantly contributing to global climate change or, if so, that mitigation policies are advised. Still, it would appear that mitigation policies, including more stringent CAFE standards, will be forthcoming. An informed and judicious choice of alternative policies can contribute to achieving cost-effectiveness while reducing GHG emissions.

Posted by Testa at 12:10 PM | Comments (1)

May 10, 2006

Economists and Rising Energy Prices

With energy price spikes grabbing the headlines, economists are rushing to provide perspectives and context on the impacts of today’s fossil fuel scarcity. Because energy prices were so low for such a very long time, some of us had gotten out of the habit of focusing in our policy discussions on the role of markets in determining price and availability, and how market prices can help economies adjust to temporary scarcity. Now, to our general horror, there are scenes of people picketing gasoline stations in protest of high prices and the like. Perhaps we have neglected to educate the public about how energy prices are generally set competitively in global markets. More importantly, from a longer term perspective, we need to remember that rising energy prices are often the best policy to encourage conservation by consumers and to enhance supply by producers.

By the standards of recent history, households are not generally in an energy crisis. In a recent Chicago Fed Letter, staff economists David Cashin and Leslie McGranahan examined U.S. household energy consumption over time and across groups. They report that recent shares of household expenditure on energy have not approached their historic highs. Energy consumption amounted to roughly 7% of household expenditures between 1990 and 2004, on average, versus the highs of 11% experienced in the early years of the 1980s. As of 2005, the share had only crept up to 8.5%. While the authors offer no projection for 2006, I can offer a rough appraisal.

Rising prices for gasoline will likely raise these 2005 consumption shares somewhat, though not up to the 11% range. The most recent forecast of gasoline prices for this year by the U.S. DOE suggests a 13.4% increase over 2005 (below). Motor fuel comprises the largest share of consumers’ annual average expenditure share, at about 4% of annual household expenditures. The second largest energy consumption share, at 3% to 4%, is spent on home electricity. Price averages for electricity across the U.S. for 2006 are forecast to be essentially flat. Home heating fuel costs are up moderately, but their shares of household energy consumption are modest in comparison to gasoline and electricity. Accordingly, if recent DOE forecasts hold for 2006, energy consumption shares would rise by another one-half percentage point, to the 9.0% range.




Of course, averages often belie the varying impacts that high energy prices exert on different households. Cashin and McGranahan address these impacts by examining the consumption shares of identifiable groups. For example, poorer households—especially the working poor—tend to spend a larger share on energy both because energy in general is a necessity that comprises a large share of modest incomes and because of the more specific necessity of driving to the workplace. Accordingly, the working poor are being more sharply impacted by recent hikes in gasoline prices and home heating fuels. In contrast, elderly households tend to spend more on home heating, yet this is largely offset by lower motor fuel spending on transportation, presumably because commuting to work is less common. Such findings suggest that individual circumstances will vary considerably with respect to price hikes of particular fuels.

The impacts of energy price changes also vary geographically. A few regions remain energy producers, whose economies may be helped by rising energy prices. Texas has long been notable as a petroleum and natural gas producer. Yet Steve Brown and Mine Yucel of the FRB of Dallas have found that the salutory impact of rising oil prices on the Texas economy is now a small fraction of what it was in the years from 1970 to 1987. Apparently, the Texas economy that we once thought of in terms of oil fields and cattle has given way to computer peripheral production and semi-conductors.

Chicago Fed economist Rick Mattoon has recently examined energy markets and the Midwest economy. From a household consumption side, there are offsetting factors across regions that dampen price and price-impact differences. On the household side, Midwest households demand more fuel (principally natural gas) for home heating, but also benefit from fewer cooling degree days in non-winter seasons.

From the perspective of the energy impact on a region’s industries, Mattoon finds that there are again offsetting effects that tend to mitigate overall regional differences in economic impact. As an input to production, manufacturing activity tends to consume more energy than other major sectors. But, while manufacturing remains much more concentrated in the Midwest, the sector’s share of total output has been falling (as it has elsewhere), even while the sector’s energy efficiency is much better in comparison to the early 1980s. So too, there are significant producers of mining and petroleum extraction equipment found in parts of the industrial Midwest, and their business activity is booming.

Still, several individual industries continue to be energy-gobblers in the Midwest, such as steel and aluminum production in Indiana and forest products in Wisconsin. Moreover, the automotive fleet composition of the domestic automakers—Ford and GM—tends toward larger energy-hungry SUVs and full-sized pickup trucks in comparison to competitor fleets. To some extent, rising motor fuel prices are holding back sales of these particular products and softening Midwest automotive production.

In general, economists are correct in concluding that the sky is not (yet?) falling with respect to rising energy prices. Yet, Mattoon may have put his pen down on the important element—energy price volatility. Energy shocks—should they take place—remain a prominent risk to the forecasts of most economists. Adjustments to higher prices for fuels such as gasoline are fairly small and ineffective in the near-term period following energy price spikes. For example, at least for the first year or two, household driving behavior is little affected by rising gasoline prices. And on the supply side, as the early OPEC experience showed, it can take several years before (inevitably) fossil fuel discovery and enhanced delivery take place. In some cases, such as for the liquified natural gas that is globally available for importation to the U.S., it will take years to site and construct the docking and unloading infrastructure.

And so, while current energy price impacts are not yet outsized, concern and worry over potential energy shocks that may arise from political instability around the world are not misplaced. And unlike previous price shocks, rising global demand for energy rather than supply interruptions has helped to bring about energy scarcity. Such market pressures may prove to be more long-lived than the cartel-induced oil price spikes of the 1970s.

Even so, if fuel scarcity does develop, we must be patient in allowing markets themselves to untangle the knot. As Tim Schilling has recently brought to our attention in a quote by Charles Woodruff Yost, one time writer for the Christian Science Monitor, in his book The Age of Triumph and Frustrations, "Any system that doesn't take the long run into account will burn itself out in the short run."

If we are to avoid policy blunders by political leaders, we economists need to educate the public about how well markets can work to solve problems of scarcity when left to their own devices. When a commodity such as fossil fuels is scarce, the market mechanisms by which rising prices encourage producers to eventually supply more fuels and encourage households and industry to conserve energy will typically bring about the best result. That result is (1) greater energy conservation (2) expanded supplies of fuels and (3) lower price and greater availability at lower overall cost in comparison to any other policy.

On the other hand, mis-informed policies to short-circuit rising prices through the legal system and populist legislation frequently prove to be counter-productive. Palliatives such as the wellhead natural gas controls that were in effect for much of the 1970s and early 1980s only aggravated scarcity and ultimately drove prices higher for consumers.

Posted by Testa at 12:52 PM | Comments (0)

February 14, 2006

Innovation in Electric Power?

Electric power is often considered the most transformative technology of the past 100 years. Its near universal adoption in our homes and workplaces (e.g., to power appliances, communications, and computers) is indeed remarkable. As a result, the electric industry today boasts $600 billion in assets in the U.S., as well as yearly sales of $260 billion (double that of the telecom industry). However, many believe that the business model by which the U.S. and Midwest produces and delivers electric power is outmoded and subpar. Movement toward a more competitive framework can be expected to produce innovations that would achieve significant cost reductions, greater reliability, and a cleaner environment.

The executive director of the Northeast-Midwest Institute, Dick Munson, has recently written a book entitled From Edison to Enron, which recounts the history of electricity and suggests an innovation-based vision for the future of the power industry.

In it, Munson describes major shifts in the electric power industry since its inception. At the dawn of the twentieth century, Chicago mogul Samuel Insull combined many small neighboring electric generation facilities, which achieved economies of scale and balanced loads throughout the day. In doing so, Insull was able to lower prices and increase reliability, thereby expanding the market and use of the product. At the time of his company’s peak in the 1920s, it served 4 million customers in 32 states.

Insull’s innovations transcended the physical production process. Tired of dealing with (and compensating) many local governments for the rights to serve fragmented local markets, Insull successfully pushed for state level regulation of electric power. And so, the state-regulated monopoly model eventually became the national norm. This bargain provided reliable power at regulated prices to consumers in return for state-sanctioned rates of return on investment for utility owners.

Though this model remained intact for most of the twentieth century, Insull’s business empire eventually collapsed amidst charges of corrupt business practices. Munson draws a thoughtful parallel between Samuel Insull’s business and Kenneth Lay’s Enron Corporation. Laying aside the later collapse of Enron, its futuristic business model for electric power production and delivery, trading across the broad geography of the United States, continues to shape the industry today. It is a model of competitive power production and, in some instances, competitive delivery, in which individual power producers have the incentive to innovate because they have a broad market in which to sell their product.

What are the possible gains (i.e., possible innovations) in following this new business model? According to Munson, the costs to businesses of power interruptions are on the order of $120 billion per year under the existing state-regulated monopoly model. Yet, under this older model, almost no research and development (R&D) takes place by the industry. At a recent book chat at the Chicago Fed, Munson said, “Last year, R&D expenditures by the dog food industry exceeded those of public utilities.”

Munson believes that we are on the verge of a vast array of innovations, if only they are not blocked by existing legislation and the old business model. In particular, progressive techniques for co-generation and other recycling of energy and waste energy are capable of producing remarkable efficiency gains. For instance, Scandanavian countries such as Finland are leading the way in co-generation, achieving upwards of 80% energy efficiency in electric power–heat production. And from an environmental perspective, efficiency gains from such techniques are every bit as “clean” as those touted from alternative fuels.

The Great Lakes region could become a leader in reforming its power industry if it chose to do so. However, if the region is to acheve a workable model of competition, a large and well-managed infrastructure must be put into place which would allow buyers and sellers to readily trade electric power (link).

In the meantime, the monumental price-spike disaster in California five years ago, following its experiment to decouple power production from the distribution of electric power, continues to give policymakers great pause. For instance, Illinois passed the Restructuring Act of 1997 that began to decouple power generation businesses from the power delivery and service businesses. In northern Illinois, very large customers (e.g., big corporations) began to negotiate their own purchases of electric power, while their local utility company typically maintained the responsibility for delivering it. For smaller customers, particularly residential customers, decoupling was deferred until 2007, and rates were frozen (actually lowered 20 percent) until that time. In the meantime, independent power producers were encouraged to get on to the delivery network. After 2006, the utility company, Commonwealth Edison (CE), will act as a purchasing agent for residential customers, buying power from independent producers through an auction process and passing along both distribution charges and power costs to consumers.

After the rate freeze expires, CE will require a rate increase to pay for its infrastructure investments in the distribution system since 1997. In 2005, some critics feared that the particular process by which CE would bid for power would raise customer rates unduly. And so, the prospect of a price spike for residential customers when the price freeze expires contributed to an outcry over CE’s plans to move to the auction process in 2007. Nonetheless, plans for this next phase of deregulation were approved by the state’s regulatory authority.

Much like residential and small customers in most of the nation, those in Illinois have enjoyed a long period of stable or declining prices. From 1995 to 2005, the real or inflation adjusted price of electric power has declined by an annual average of 4.4 percent. Of course, electric bills have climbed along with the increasing consumption of electricity in powering home electronics and electrical appliances.

The chart below displays average electric revenues (so-called average prices) for providing electric power to residential customers in the Seventh District states. Price rises since have been tame or have declined in real terms.



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However, residential electric prices will soon be rising, on average, in the Midwest and nationwide. That is because fuel costs, including those for natural gas, coal, and petroleum, have been rising sharply for power generators, much as they have been rising in other end-use sectors (link). Because of lags in the passing through of fuel costs in the quasi-regulated environment, small customers in the residential sector have not yet felt the impact of fuel price rises (which typically make up two-thirds or so of delivered electricity costs for residential consumers). But the pass-through of rising fuel costs is now “in the pipeline.”

The rising prices for electric power are likely to confuse and frustrate many customers who will associate price hikes with the shifting regulatory structure of the industry, especially those who remember the mistaken path to deregulation taken by California. It will be a shame if their confusion and frustration over rising prices stalls the necessary innovations in power production that Dick Munson envisions for the Midwest in the years ahead.

Posted by Testa at 3:47 PM | Comments (0)

October 6, 2005

Hurricane Impacts and Energy Prices

As the water recedes and the human toll accumulates in the hurricane-impacted Coastal regions, discussion has turned to the economic impact. Many areas and communities immediately surrounding the Gulf Coast are experiencing increased business and real estate activity as evacuees try to refocus their lives and homes, even as local governments and charitable organizations struggle mightily to lend assistance and resettle evacuees. Midwest economic activity will pick up in several ways during the coming months, but these will likely be outweighed by rising energy prices—-especially for natural gas, which is used to heat Midwest homes.

Hurricanes and other natural disasters are often accompanied by interruptions in economic activity and are followed by upswings and regional diversions in economic activity. Parts of the Midwest have felt the disruption through our ties to the Gulf Coast economy. Shipment delays and sharp price spikes for petroleum-based chemicals have slowed production for Midwest manufacturers of tires and furniture. Midwest grain shipments down the Mississippi were delayed and diverted by Hurricane Katrina, though they have now largely resumed or been diverted in other directions.

In other ways, the hurricane impacts are boosting Midwest economic activity. Some evacuees have taken refuge in Midwest communities, and now reside with relatives or in donated facilities. In response, government operations such as schools must bolster their payrolls. The added spending of the new families will be an infusion into Midwest income and spending streams.

As for “export” industries, mobile and trailer home construction in northern Indiana and other areas of the Midwest have been called into hot demand by FEMA. Emergency workers, evacuees, and homeowners who are in the process of rebuilding their properties must have housing—-at least temporarily. And the region’s manufacturers of earth-moving and construction equipment, such as Caterpillar, and makers of other rebuilding tools, such as electric equipment and generators, will experience some added sales. And of course, flood-damaged autos and homes will require such Midwest staples as motor vehicles and home appliances. Chicago also has gained several upcoming conventions dropped from the New Orleans calendar.

But rising natural gas prices loom large as the Midwest approaches the home-heating season, due to supply disruptions from the Gulf. Other cold-weather regions, such as New England, burn home heating oil. The Midwest enjoyed low home heating bills from the late 1980s to the mid-1990s when natural gas prices were very low and gas utilities were paying about $2 to $3 per thousand cubic feet of natural gas (mcf). But in recent years, natural gas prices have been rising because of higher demand for gas from electricity utilities and from its use as a substitute for petroleum.

In the regional newsletter of the Federal Reserve Bank of Dallas, veteran energy economist Steve Brown investigates the relationship between petroleum prices and natural gas prices (Southwest Economy July/August 2005). Although the two fuels are no longer common substitutes in electric generation, Steve finds that the two fuel prices continue to move in tandem—-with two exceptions. Natural gas prices are higher in the winter, and they also depend on how much is stored during the summer for use in the winter. In the Midwest, natural gas is stored in the summer in underground aquifers, salt caverns, and abandoned gas wells. According to Brown, if 10 percent less gas is stored now than the average in the previous five years, natural gas price prices will go up 23 cents nationally.

What can cause these shortfalls in stored volumes? Winter cold snaps for one, whereby vendors drain their stored reserves to meet demand. Cold snaps contributed to price spikes during the winter of 2000-2001 and 2002-2003 when the spot price approached $10 and $12 per mcf. Abnormally hot weather during the summer can also contribute to a shortfall. The hot spell in the Midwest this past summer increased natural gas prices and slowed storage as some electric power generators fired up on natural gas to feed air conditioning units. And finally, of course, supply interruptions such as those from Hurricanes Katrina and Rita can slow the pace of storage. This is a particular problem for the Midwest since most of our natural gas supplies come from the Gulf Coast area.

How much will natural gas prices rise this winter as a result of the Gulf hurricanes? Not quite as much as current rises in spot market prices and contract prices for future delivery suggest. During the heating season, gas distributors blend new spot market purchases with the natural gas already purchased and stored or pre-contracted. Likewise, the delivered price to homes reflects a price blend of the stored gas, as well as gas purchased under long-term contract, with augmented or spot market purchases. A colder-than-normal winter, or low volumes of stored or pre-contracted gas, would tend to tilt the blend toward higher-priced spot market purchases, which could deliver a ruder heating bill shock to Midwest households.

The figure below shows that reported spot prices do follow the acquisition, or “city gate,” prices that gas distribution utilities pay for natural gas. This past summer, and intermittently since 2000, the measure of spot price was running roughly double that of the 1990s. Due to the current supply disruptions, the prices for delivery under futures prices on the NYMEX were running double that of this past summer at over $14 for December 2005 and January 2006 delivery, though falling in the years thereafter.

FIGURE 1

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Rising gas city gate prices push up home heating bills, though less than proportionately because home heating bills also include distribution and delivery costs, which are more stable. The figure below compares past city gate prices in the Midwest to home heating bills. Heating bills rise only moderately less steeply than city gate prices. Natural gas expenses per household in the Midwest for the November–March heating season averaged $445 from 1996-97 through the 1999-2000, but had climbed to an estimated $732 last winter (which was a mild winter). In its recent “Short Term Energy Outlook,” published just after the Katrina and before the Rita disruptions, the U.S. Department of Energy estimated that home heating bills in the broader Midwest, under normal heating circumstances, will be 71 percent above last year.

FIGURE 2

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The U.S. Department of Energy (DOE) does not include any measurement of uncertainty in its model forecasts, so these estimates should be taken as nothing more than a rough guess … not only because of the vagaries of the weather, but because little is known about the amount of gas stored at Midwest utilities or purchased under long-term contracts for later delivery. The extent of damage to production of natural gas in the Gulf region is only now being assessed, but early indications are that Rita was less damaging than the initial assessment. Until we know how long it will take to restore lost production, and its effects on spot price, winter heating costs remain a big question mark.

In any event, despite some possible benefits from the hurricanes for the regional economy, most Midwest households will wish they had never heard the names Katrina and Rita as they feel the frosts and pull out their checkbooks to pay the bills this winter. In our 2001 Chicago Fed Letter, Thomas Klier and I found that the cold weather snap took a 1.74 percent bite out of Midwest disposable income (versus 1.01 percent for the U.S.) during the winter of 2000-01, up from 1.05 percent the previous winter (Chicago Fed Letter). And gasoline prices, though up sharply that year, averaged $1.40 in the Midwest in 2001. They’ve averaged $2.19 so far this year in the Midwest, with a 40 cent jump after Hurricane Katrina. Who said that hurricanes could only damage coastal regions?

Posted by Testa at 10:44 PM | Comments (0)

September 23, 2005

Ethanol and Midwest Rural Communities

Those who are interested in the prospects of Midwest rural areas will want to peruse the presentations from Dave Oppedahl’s recent conference on “Ag Biotech and Midwest Rural Development.” Right now, the papers and presentations are posted (see conference link). Dave will soon be summarizing the conference for an upcoming issue of Chicago Fed Letter.

One topic of the conference was the rising prominence of ethanol production in rural communities, and the associated economic benefits. Ethanol raises hopes in many rural communities because of agriculture’s shrinking role in supporting rural jobs and income. But while ethanol production appears to be a boon to many rural communities, some question the efficacy of the subsidies for the overall nation.

As both Dave Oppedahl and I covered in our September 8 presentations, production agriculture has been shrinking profoundly as the basis for income and jobs in many rural areas, and government support payments make up sizable shares of what remains. But while direct income and jobs are shrinking in production agriculture, some rural income and work is being created downstream in transportation of the voluminous crops, along with financing and service support of production agriculture. In addition, related manufacturing has become more important in many Midwest rural counties in the form of “food processing,” such as oil seed crushing, meat processing, packaged foods, and prepared packaged foods. It is somewhat insightful to consider how we count the processing of food in our economic statistics and in what particular industry we place food processing. If food is prepared (grown) on the farm, it is agriculture. If it is prepared in a factory as a frozen meal, it is “manufacturing.” If it is prepared in a grocery store at the deli department, it is retail. And in a restaurant, it is in the services industry. And if it is prepared at home, it is not counted in our measure of national output, GDP, at all!

The concentration of food processing (manufacturing) in rural counties in the U.S. has doubled since the 1970s and accounts for about one-fifth of rural manufacturing earnings according to the U.S. Bureau of Economic Analysis. Economies of transportation is one reason that much of the processing activity remains in rural areas. By processing raw farm product near the farm, the products shed weight and volume before delivery to market.

In this regard, the ethanol industry is closely akin to food processing. This alternative fuel to gasoline is most widely processed from corn, and done so nearby to corn production. In production of ethanol, Iowa is the leading state, followed closely by Illinois (these two states also lead the nation in corn production).

The domestic market for ethanol was encouraged by the Clean Air Act Amendments of 1990. Concerns about urban ozone pollution, relating largely to breathing difficulties, led non-attainment areas to require additives to gasoline that diminished emissions of compounds that are thought to be precursors to (ground level) ozone formation. Today, such encouragement primarily takes the form of a federal $0.50 per gallon tax exemption at the wholesale level for ethanol as compared to gasoline. Some states such as Minnesota and Iowa add additional incentives.

As a result, ethanol demand has more than doubled since 2000 and annual production will likely exceed four billion gallons for the year 2005. At the September 8 conference, John Miranowski of Iowa State University reported that 30 new plants ethanol plants have been added over the past 3 years, with many more in progress or on the drawing board.

Many rural communities have welcomed and encouraged ethanol plants for the associated jobs and income at the plant. And again, the economics of transportation savings has meant that local corn farming operations typically receive higher prices than they would otherwise. In addition, some of the by-products from the ethanol processing can be used as livestock feed. This livestock production too contributes to the local community’s economy. And as usual, some enterprising economists have estimated the indirect and “multiplier” impacts of an ethanol production atop the direct local economic impacts.

From a national perspective, the advantages and sustainability of the ethanol industry are not very clear. We don’t know how well ethanol would compete in an unfettered marketplace, without subsidies. At the oil prices of two years ago, and without the very large subsidies, ethanol production today would have been much lower. However, at today’s petroleum prices, ethanol is looking more attractive. Further, some would argue that, as the infrastructure to transport and distribute ethanol are developed and attain greater scale, ethanol might find a place in the market without its very large subsidies.

Subsidies are sometimes justified for the alleged environmental benefits to ethanol in reducing urban ozone. But to the contrary, others argue that today’s engines burn so much more cleanly that there are no ozone benefits to burning ethanol rather than gasoline in urban markets. In addition, ethanol evaporates more readily in comparison to gasoline, thereby possibly aggravating urban ozone. In rebuttal, many point out that ethanol is advantaged because it does not release as much carbon into the atmosphere, and thereby helps out “global warming.”

Energy security is also an elusive idea. Buffer stocks of vital materials are an alternative to subsidizing domestic fuel industries, and possibly less costly. So too, in other countries such as Brazil, ethanol can be produced more cheaply than in the U.S., from cane sugar. Even if ethanol displaces a small portion of our imported petroleum, would we not find that we can securely and cheaply import ethanol from South America? At least one conference participant suggested that domestic ethanol interests may soon be fighting for further trade protections against ethanol imports.

In all likelihood, we will never know the answer as to how ethanol would fare on a level playing field, or whether subsidies already in place are justified on the basis of non-market considerations such as environmental features and energy security. That is because ethanol’s future in the U.S. seems quite robust since the recent federal energy bill has mandated consumption of 7.5 billion gallons in the U.S. by 2012. As one visitor to our bank commented, “apparently, U.S. industrial policy is not quite dead.”

Surprisingly, despite the many analytic tools that economists have to inform public policy, no one at the conference could report that there had been any comprehensive and respectable benefit-cost study conducted to evaluate subsidies and mandates for ethanol production and use. There has been a prominent debate as to whether the ethanol production process consumes more energy than it produces. But the study results are highly sensitive to the assumptions of each researcher as to what is the corn yield per acre of land, for example. But even aside from these vagaries, the “energy balance” approach is not really very helpful in deciding the issue--the way a market test would be helpful. In the generation of electricity, for example, there is an enormous loss of energy as scientifically defined. The heat content of coal used, for example, is far more than the electricity produced. Yet, it goes without saying that electricity is quite valuable, and end users are willing to pay for it. As for spillover benefits relating to the environment, economists are learning to use shadow prices obtained from surveys, for example, to put dollar values on environmental emissions so that lower pollution can be evaluated using a value yardstick.

Whether or not national ethanol policy would be seen favorably by a thorough cost-benefit analysis, many rural communities would welcome an ethanol plant, and some will get that chance.

The Midwest Economy “Blog”

Anything resembling an opinion or viewpoint contained in the blog are my own, and do not necessarily represent the views of anyone else at the Federal Reserve Bank of Chicago or in the Federal Reserve System.

Coming topics:

Impact of biotech on agriculture

Midwest economic conditions and recent hurricanes

Chicago area economy

Funding and access to higher education

Posted by Testa at 5:39 PM | Comments (1)


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