Tag Archives: Energy Information Agency

Critical Infrastructure: Oil and Gas Pipelines

Peter Lobner

Background on the oil and gas industry

In a 2013 report by the American Petroleum Institute (API) and PricewaterhouseCoopers (PwC) entitled, “Economic Impacts of the Oil and Natural Gas Industry on the US Economy in 2011,” it was reported that:

“Counting direct, indirect, and induced impacts, the industry’s total impact on labor income (including proprietors’ income) was $598 billion, or 6.3 percent of national labor income in 2011. The industry’s total impact on US GDP (gross domestic product) was $1.2 trillion, accounting for 8.0 percent of the national total in 2011.”

Table 1 of this report, which is reproduced below, defines the scope of the U.S. oil and natural gas industry included in this analysis.

Composition of oil & gas industry

In the table footnote you can see that the API – PwC economic assessment was limited to the oil and gas industry itself, and their results did not include the economic value of the many downstream businesses whose operations are dependent on one or more of the various products delivered by the oil and gas industry (i.e., plastic and synthetic material manufacturers, airlines, trucking, power plants, etc.). If we counted the economic values of these oil and/or gas dependent businesses, then the overall contribution of the oil and gas industry to the U.S. economy would be significantly higher than stated in the API – PwC report. You can get this report at the following link:


U.S. oil and gas pipeline infrastructure

Pipeline systems are a key element of the oil and gas industry infrastructure, enabling timely and efficient transportation of the following products:

  • Crude oil
  • Petroleum products from crude oil and other liquids processed at refineries, including transportation fuels, fuel oils for heating and electricity generation, asphalt and road oil, and various feedstocks for making chemicals, plastics, and synthetic materials
  • Hydrocarbon gas liquids (HGL), including natural gas liquids (paraffins or alkanes) and olefins (alkenes) produced by natural gas processing plants, fractionators, crude oil refineries, and condensate splitters, but excluding liquefied natural gas (LNG) and aromatics
  • Natural gas

The U.S. has over 200,000 miles of liquids pipelines that, in 2014, transported 16.2 billion barrels of crude oil, petroleum products and HGL. More than 17,000 miles of liquid pipelines were added to the network in the five-year period from 2010 thru 2014. The U.S. has over 300,000 miles of interstate and intrastate natural gas transmission pipelines. That’s adds up to more than a half million miles of major oil and gas pipelines in the U.S.

Most pipelines are installed underground, with pumping / compressor stations at grade level. The Trans-Alaska pipeline system is a notable exception, with its above-grade pipeline in permafrost regions.

The U.S. Energy Information Agency (EIA) maintains the U.S. Energy Mapping System, which is a geographic information system (GIS) that can display a great deal of energy infrastructure information. The user can select the map area to be viewed, the map style, and the data to be displayed on the map. Once you’ve created the map of your choice, you can zoom and scroll to explore map details. You can access the U.S. Energy Mapping System at the following link:


The following maps prepared using the U.S. Energy Mapping System show the distribution of oil and gas pipeline systems in the U.S. (except Alaska & Hawaii) and Canada. The source of pipeline mileage data is the Pipeline and Hazardous Material Safety Administration (PHMSA). The source of liquid capacity data is the Association of Oil Pipe Lines (AOPL).

Crude oil pipelines:

  • 73,300 miles of interstate and intrastate pipelines in 2015 (PHMSA)
  • Delivered 9.3 billion barrels (bbl) of crude oil nationwide in 2014 (AOPL)

Crude oil pipelines

Petroleum product pipelines:

  • 62,588 miles of interstate and intrastate pipelines in 2015 (PHMSA)
  • The petroleum product pipelines and the HGL pipelines together delivered 6.9 billion barrels (bbl) of products nationwide in 2014 (AOPL).

Petroleum product pipeline 

HGL (natural gas liquids) pipelines: 

  • 67,577 miles of interstate and intrastate pipelines in 2015 (PHMSA)

 HLG pipeline

Natural gas pipelines:

  • 2,509,000 total miles of natural gas pipelines in 2015 (PHMSA)
    • 301,242 miles of interstate and intrastate transmission pipelines
    • 1.28 million miles of gas distribution main lines (smaller than the transmission pipelines)
    • 913,085 miles of gas distribution service lines
    • 17,727 miles of gathering mains that collect gas from wells and move it through a series of compression stages to the main transmission pipelines
  • Natural gas transmission pipeline capacity was approximately 443 billion cubic feet per day in 2011 (QER 1.1)

Natural gas pipelines

All of the above maps combined, including international border crossings:

Combined map

The high density of pipeline systems in many parts of the nation is evident in the last map. On the EIA’s U.S. Energy Mapping System website, you can recreate and explore any of the above maps.

Pipeline safety

The Department of Transportation’s (DOT) Pipeline and Hazardous Material Safety Administration (PHMSA), acting through the Office of Pipeline Safety (OPS), administers the DOT national regulatory program to assure the safe transportation of natural gas, petroleum, and other hazardous materials by pipeline.

PHMSA has collected pipeline incident reports since 1970. PHMSA defines “significant incidents” as any of the following conditions that originate within the pipeline system (but not initiated by a nearby external event that affects the pipeline system).

  • Fatality or injury requiring in-patient hospitalization
  • $50,000 or more in total costs, measured in 1984 dollars
  • Highly volatile liquid releases of 5 barrels (210 gallons) or more, or other liquid releases of 50 barrels (2,100 gallons) or more
  • Liquid releases resulting in an unintentional fire or explosion

PHMSA data are available at the following link:


A summary of all reported pipeline incidents over the past 20 years is presented in the following PHMSA table.

PHMSA significant events table

The 20-year averages (1996 – 2015) are:

  • Incidents: 560
  • Fatalities: 18
  • Injuries: 69
  • Total cost: $343,109,598

The latest data for 2016 (possibly not final) are:

  • Incidents: 620
  • Fatalities: 17
  • Injuries: 82
  • Total cost: $275,341,057

Clearly, the oil and gas pipeline business is quite hazardous, and the economic cost of pipeline incidents is very high, even in an average year. Since the mid-1990s, the number of incidents per year has almost doubled (367 average for 1996 – 2000 vs. 641 average for 2011 – 2015) as has the total cost per year ($128.4 million average for 1996 – 2000 vs. $331.6 million average for 2011 – 2015).

In June 2015, Jonathan Thompson posted the article, “Mapping 7 Million Gallons of Crude Oil Spills,” on the High Country News website, at the following link:


In this article, High Country News mapped the last five years of PHMSA data, which included more than 1,000 crude oil pipeline leaks and ruptures. Key points made in the High Country News article are

  • Over the five-year period, 168,000 barrels (more than 7 million gallons) of crude oil were spilled as a result of reported incidents. That’s an average of about 1.4 million gallons (33,600 barrels) per year leaking or spilled from 73,300 miles of crude oil pipelines that delivered 3 billion barrels of oil annually in 2014. That annualized amount of leakage also is equivalent to the amount of oil carried in about 47 DOT-111 rail cars.
  • Commonly reported causes included poor material condition (corrosion, bad seals), weather (heavy rains, lightning), and human error (valves being left open, people puncturing pipelines while digging).
  • Many of the spills were small, releasing less than 10 barrels (420 gallons) of oil, but a few were much larger. For example, a 2013 lightning strike on a North Dakota pipeline caused a 20,000-barrel (840,000 gallon) leak.

Cleanup after these spills and leaks is included in the PHMSA total cost data.

Aging infrastructure

Is August 2014, Jordan Wirfs-Brock posted the article, “Half Century Old Pipelines Carry Oil and Gas Load,” on the Inside Energy (IE) website at the following link:


Using PHMSA data, the author mapped the age of the U.S. pipeline infrastructure and determined that, “About forty-five percent of U.S. crude oil pipeline is more than fifty years old.” The following chart shows the age distribution of U.S. crude oil pipelines.

Crude pipeline age

In April 2015 Administration issued the First Installment of the Quadrennial Energy Review (QER 1.1). This report included the following chart showing the age distribution of U.S. natural gas transmission and gathering pipelines. It looks like more than 50% of these natural gas pipelines are more than 50 years old.

Gas pipeline age

Source: QER 1.1 Summary

The high percentage of older pipeline systems places the overall integrity, reliability and safety of the critical national pipeline infrastructure at risk.

Pipeline modernization

In a previous post, I described the Quadrennial Energy Review (QER) initiated by the Obama Administration in January 2014. The first QER report, QER 1.1, released in April 2015, provides a good overview of issues related to oil and gas pipeline system risks and opportunities to modernize this critical infrastructure.

One positive step was taken on 16 April 2015 by the Federal Energy Regulatory Commission (FERC) when it announced a new policy, Cost Recovery Mechanisms for Modernization of Natural Gas Facilities. This policy sets conditions for interstate natural gas pipeline operators to recover certain safety, environmental, or reliability capital expenditures made to modernize pipeline system infrastructure.

Given the scale of the national oil and gas pipeline infrastructure, and the age of significant portions of that infrastructure, it will take decades of investment to implement system-wide modernization. The political climate, economic climate, and maybe the stars need to be in alignment for this enormous, long-term modernization effort to deliver the needed results.

Dispatchable Power from Energy Storage Systems Help Maintain Grid Stability

Peter Lobner

On 3 March 2015, Mitsubishi Electric Corporation announced the delivery of the world’s largest energy storage system, which has a rated output of 50 MW and a storage capacity of 300 MWh. The battery-based system is installed in Japan at Kyushu Electric Power Company’s Buzen Power Plant as part of a pilot project to demonstrate the use of high-capacity energy storage systems to balance supply and demand on a grid that has significant, weather-dependent (intermittent), renewable power sources (i.e., solar and/or wind turbine generators). This system offers energy-storage and dispatch capabilities similar to those of a pumped hydro facility. You can read the Mitsubishi press release at the following link:


The energy storage system and associated electrical substation installation at Buzen Power Plant are shown below. The energy storage system is comprised of 63 4-module units, where each module contains sodium-sulfur (NaS) batteries with a rated output of 200 kW. The modules are double stacked to reduce the facility’s footprint and cost.

Buzen Power Plant - JapanSource: Mitsubishi

The following simplified diagram shows how the Mitsubishi grid supervisory control and data acquisition (SCADA) system matches supply with variable demand on a grid with three dispatchable energy sources (thermal, pumped hydro and battery storage) and one non-dispatchable (intermittent) energy source (solar photovoltaic, PV). As demand varies through the day, thermal power plants can maneuver (within limits) to meet increasing load demand, supplemented by pumped hydro and battery storage to meet peak demands and to respond to the short-term variability of power from PV generators. A short-term power excess is used to recharge the batteries. Pumped hydro typically is recharged over night, when the system load demand is lower.

Mitsubishi SCADA

Above diagram: Mitsubishi BLEnDer® RE Battery SCADA System (Source: Mitsubishi)

Battery storage is only one of several technologies available for grid-connected energy storage systems. You can read about the many other alternatives in the December 2013 Department of Energy (DOE) report, “Grid Energy Storage”, which you can download at the following link:


This 2013 report includes the following figure, which shows the rated power of U.S. grid storage projects, including announced projects.

US 2013 grid  storage projectsSource: DOE

As you can see, battery storage systems, such as the Mitsubishi system at Buzen Power Plant, comprise only a small fraction of grid-connected energy storage systems, which currently are dominated in the U.S. by pumped hydro systems. DOE reported that, as of August 2013, there were 202 energy storage systems deployed in the U.S. with a total installed power rating of 24.6 GW. Energy storage capacity (i.e., GWh) was not stated. In contrast, total U.S. installed generating capacity in 2013 was over 1,000 GW, so fully-charged storage systems can support about 2.4% of the nation’s load demand for a short period of time.

Among DOE’s 2013 strategic goals for grid energy storage systems are the following cost goals:

  • Near-term energy storage systems:
    • System capital cost: < $1,750/kW; < $250/kWh
    • Levelized cost: < 20¢ / kWh / cycle
    • System efficiency: > 75%
    • Cycle life: > 4,000 cycles
  • Long-term energy storage systems:
    • System capital cost: < $1,250/kW; < $150/kWh
    • Levelized cost: < 10¢ / kWh / cycle
    • System efficiency: > 80%
    • Cycle life: > 5,000 cycles

Using the DOE near-term cost goals, we can estimate the cost of the energy storage system at the Buzen Power Plant to be in the range from $75 – 87.5 million. DOE estimated that the storage devices contributed 30 – 40% of the cost of an energy storage system.  That becomes a recurring operating cost when the storage devices reach their cycle life limit and need to be replaced.

The Energy Information Agency (EIA) defines capacity factor as the ratio of a generator’s actual generation over a specified period of time to its maximum possible generation over that same period of time. EIA reported the following installed generating capacities and capacity factors for U.S. wind and solar generators in 2015:

US renewable power 2015

Currently there are 86 GW of intermittent power sources connected to the U.S. grid and that total is growing year-on-year. As shown below, EIA expects 28% growth in solar generation and 16% growth in wind generation in the U.S. in 2016.

Screen Shot 2016-03-03 at 1.22.06 PMSource: EIA

The reason we need dispatchable grid storage systems is because of the proliferation of grid-connected intermittent generators and the need for grid operators to manage grid stability regionally and across the nation.

California’s Renewables Portfolio Standard (RPS) Program has required that utilities procure 33% of their electricity from “eligible renewable energy resources” by 2020. On 7 October 2015, Governor Jerry Brown signed into law a bill (SB 350) that increased this goal to 50% by 2030. There is no concise definition of “eligible renewable energy resources,” but you can get a good understanding of this term in the 2011 California Energy Commission guidebook, “Renewables Portfolio Standard Eligibility – 4th Edition,” which you can download at the following link:


The “eligible renewable energy resources” include solar, wind, and other resources, several of which would not be intermittent generators.

In 2014, the installed capacity of California’s 1,051 in-state power plants (greater than 0.1 megawatts – MW) was 86.9 GW. These plants produced 198,908 GWh of electricity in 2014. An additional 97,735 GWh (about 33%) was imported from out-of-state generators, yielding a 2014 statewide total electricity consumption of almost 300,000 GWh of electricity. By 2030, 50% of total generation is mandated to be from “eligible renewable energy resources,” and a good fraction of those resources will be operating intermittently at average capacity factors in the range from 22 – 33%.

The rates we pay as electric power customers in California already are among the highest in the nation, largely because of the Renewables Portfolio Standard (RPS) Program. With the higher targets for 2030, we soon will be paying even more for the deployment, operation and maintenance of massive new grid-connected storage infrastructure that will be needed to keep the state and regional grids stable.

Is EPA Fudging the Numbers for its Carbon Regulation?

Peter Lobner

In my 2 July 2015 post, I commented on significant deficiencies in the U.S. Environmental Protection Agency (EPA) Clean Power Plan proposed rule. On 3 August 2015, the EPA announced the final rule. You can read the final rule for existing power plants, the EPA’s regulatory impact analysis, and associated fact sheets at the following link:


The Institute for Energy Research (IER) is a not-for-profit organization that conducts research and analysis on the functions, operations, and government regulation of global energy markets. The IER home page is at the following link:


On 24 November 2015, the IER published an insightful article entitled, Is EPA Fudging the Numbers for its Carbon Regulation?, which I believe is worth your attention. The IER’s main points are:

  1. U.S. Energy Information Agency’s (EIA) Annual Energy Outlook (AEO) is the data source usually used by federal government agencies in their analysis of energy issues.
  2. EPA stands out as an exception. It frequently chooses not to use EIA data, and instead develops it’s own duplicative, different data.
  3. In the case of the Clean Power Plan, the EPA’s own data significantly underestimates the number of coal plants that need to be retired to comply with the Plan. The result is a much lower estimate of the economic impact of the Plan than if EIA data had been used.

It appears to me that the EPA created and used data skewed to produce a more favorable, but likely unrealistic, estimate of the economic impact that will borne by the U.S. power industry and power customers as the Clean Power Plan is implemented. Form your own opinion after reading the full IER article at the following link:


Update 19 Feb 2016

On 8 February 2016, the American Nuclear Society (ANS) released their, “Nuclear in the States Toolkit Version 1.0 – Policy Options for States Considering the Role of Nuclear Power in Their Energy Mix.” The toolkit catalogs policies related to new and existing nuclear reactors for state policymakers to consider as they draft their Clean Power Plan compliance strategies.   The Toolkit identifies a range of policy options that individually or in aggregate can make nuclear generation a more attractive generation alternative for states and utilities.

You can download this document at the following link:


On 9 February 2016, the U.S. Supreme Court issues a stay on implementation of the EPA’s Clean Power Plan (CPP) pending the resolution of legal challenges to the program in court.

The ANS noted that, “….the stay provides them (the states) an opportunity to take a new look at the carbon offsets that existing nuclear plants provide, which they weren’t encouraged to do under the CPP rules.”