U.S. Energy Industry, Market, Regulation & Prices


The U.S. Energy Information Administration (EIA) indicates:

Growth in crude oil production from tight oil and shale formations supported by improved identification of resources and technology advances in extraction have supported a nearly fourfold increase in tight oil production from 2008, when it accounted for 12% of total U.S. crude oil production, to 2012, when it accounted for 35% of total U.S. production. U.S. production of tight oil has increased dramatically in the past few years, from less than 1 million barrels per day (MMbbl/d) in 2010 to more than 3 MMbbl/d in the second half of 2013.

The net import share of petroleum and other liquids consumption, which increased steadily from 27% in 1985 to about 60% in 2005, has fallen since 2005, to roughly 40% in 2012.

In 2012, energy consumption by light-duty vehicles (LDVs) accounted for 61% of all transportation energy consumption in the United States, or 8.4 million barrels of oil equivalent per day, and represented nearly 10% of world petroleum liquids consumption. LDV energy use is driven by both LDV fuel economy and travel behavior, as measured by LDV vehicle miles traveled (VMT). LDV VMT per licensed driver peaked in 2007 at 12,900 miles per year and decreased to 12, 500 miles in 2012.

In 2012, coal-fired and nuclear power plants together provided 56% of the electricity generated in the United States. The role of these technologies in the U.S. generation mix has been changing since 2009, as both low natural gas prices and slower growth of electricity demand have altered their competitiveness relative to other fuels. Many coal-fired plants also must comply with requirements of the Mercury and Air Toxics Standards (MATS) and other environmental regulations. Of the total installed 310 gigawatts (GW) of coal-fired generating capacity available at the end of 2012, 50 GW, or 16%, is projected to be retired by 2020. Despite those projected retirements, coal continues to account for the largest share of the electricity generation mix through 2034, after which it is overtaken by natural gas. However, throughout the projection the coal share of total generation remains significantly below its 49% share in 2007, when coal set its annual generation record.

Recent trends in the electric power industry have resulted in both declining revenues and increased operating costs for coal plants. Because natural gas often is the marginal fuel and thus sets prices in Regional Transmission Organization (RTO) markets, and natural gas influences wholesale electricity prices in non-RTO markets, the decline in natural gas prices beginning in 2008 tends to reduce electricity prices and the payments received by all generators for the electricity they produce (natural gas prices have become the key determinant of wholesale electricity prices, which in turn are a significant component of retail electricity prices). Lower natural gas prices also improve the competitiveness of natural gas combined-cycle (NGCC) power plants relative to coal-fired plants. When lower natural gas prices drive the cost of generating electricity from an NGCC plant below that of a nearby coal-fired plant, the coal plant is dispatched, or operated, less often and earns less revenue.

Although electricity demand fell in only three years between 1950 and 2007, it declined in four of the five years between 2008 and 2012. The largest drop occurred in 2009 (Figure IF8-1). One contributing factor was the steep economic downturn from late 2007 through 2009, which led to a large drop in electricity sales in the industrial sector. Other factors, such as efficiency improvements associated with new appliance standards in the buildings sectors and overall improvement in the efficiency of technologies powered by electricity, have slowed electricity demand growth and may contribute to slower growth in the future, even as the U.S. economy continues its recovery.

In the United States, retail, residential consumers are charged a fixed rate for the electricity they use regardless of the time of day. The wholesale price to purchase electricity in the retail market are higher during the peak us day market and lower during the overnight market but billing does not reflect the cost of electricity at time of purchase. Consumer billing is calculated by multiplying the amount of Kilowatt hours (KWh) of electricity consumed by a rate designed to allow the utility to recapture the cost of operations plus a predetermined amount of profit.

In 2012 and 2013, operators of five nuclear power reactors representing 4.2 GW of capacity announced plans to retire the reactors by 2015. Four of the reactors—San Onofre 2 and 3, Kewaunee, and Crystal River—already have ended nuclear power production, and the fifth, Vermont Yankee, ended generation in December 2014. In addition, the Oyster Creek plant is expected to conclude operation in 2019 [2]. These are the first retirements of U.S. nuclear power plants since Millstone Unit 1 was retired in 1998. Retirements often are the result of unique circumstances, but some owners of nuclear power plants have voiced concerns about the profitability of their units, sparking discussion of possible additional nuclear retirements. However, there is no viable system for the disposal of spent nuclear fuel at decommissioned nuclear plants used for commercial power production. Two federal agencies—the Nuclear Regulatory Commission (NRC) and the Department of Energy (DOE)—are primarily responsible for the regulation and disposal of the nation’s spent nuclear fuel. NRC regulates the construction and operation of commercial nuclear power plants and spent fuel disposal facilities, as well as the storage and transportation of spent fuel. The federal geologic disposal site at Yucca Mountain for spent nuclear fuel and high-level nuclear waste from commercial nuclear power plants was never completed.   http://www.gao.gov/key_issues/disposal_of_highlevel_nuclear_waste/issue_summary

As existing coal and nuclear plants are retired, natural gas and renewables gain increasing shares of the generation mix. The strength of this trend depends on how much nuclear and coal-fired capacity is retired.

Solar and wind energy are expected to remain the primary sources of renewable capacity growth. Although geothermal, waste, and biomass resources have some favorable characteristics compared to wind and solar, such as the ability to provide operatordispatched power, each has significant limitations. The limitations include a limited resource base (geothermal, waste) or relatively high capital and/or fuel costs (biomass). Although wind and solar will continue to be capital-intensive technologies, they are expected to achieve cost reductions that—along with a larger resource base—result in higher growth than other renewables under favorable conditions (such as placement of an explicit or implicit value on CO2 emissions, or high natural gas prices). However, solar and wind resources also vary in availability and quality by region, and generation facilities are likely to be concentrated in the more favorable regions.

The Mercury and Air Toxics Standards (MATS) requires fossil-fuel steam electric generators to meet limits based on maximum achievable control technologies (MACT) to control emissions of acid gases, toxic metals, and mercury. The standards will take effect by April 2015 for electric generation units with capacities greater than 25 MW. The rule allows for state environmental permitting agencies to grant one-year compliance extensions, which is assumed will be granted in most states, and all applicable units must begin to comply with the rule at the beginning of 2016.

The Clean Air Interstate Rule (CAIR) is a cap-and-trade program aimed at reducing emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX) from fossil-fueled power plant units with capacities greater than 25 MW in 27 eastern states and the District of Columbia. The emissions caps went into effect in 2009 for NOX and in 2010 for SO2. Both caps are scheduled to be tightened in 2015.

U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014   http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf

U.S. Energy Information Administration (EIA), Primary Energy Production by Source   http://www.eia.gov/totalenergy/data/monthly/pdf/sec1_5.pdf

In March 2016, the U.S. Energy Information Administration (EIA) indicated wind added the most electric generation capacity in 2015, followed by natural gas and solar. Wind accounted for 41% of additional capacity. The data also show a record amount of distributed solar photovoltaic (PV) capacity was added on rooftops throughout the country in 2015.   http://www.eia.gov/todayinenergy/detail.php?id=25492

In December 2016, Bloomberg New Energy Finance indicated "as 2016 comes to an end, solar power, for the first time, is becoming the cheapest form of new electricity." "Now, unsubsidized solar is beginning to outcompete coal and natural gas on a larger scale, and notably, new solar projects in emerging markets are costing less to build than wind projects." A BNEF report, called Climatescope, ranks and profiles emerging markets for their ability to attract capital for low-carbon energy projects.   http://global-climatescope.org/en/

The World Economic Forum, Renewable Infrastructure Investment Handbook, indicates solar and wind is now the same price or cheaper than new fossil fuel capacity in more than 30 countries.   http://www3.weforum.org/docs/WEF_Renewable_Infrastructure_Investment_Handbook.pdf

The U.S. Energy Information Administration (EIA) indicated in 2016, U.S. utilities added 9.5 gigawatts (GW) of photovoltaic capacity to the U.S. grid, making solar the top fuel source for the first time in a calendar year   http://www.eia.gov/todayinenergy/detail.php?id=29212