Concerns about power generating margins and water shortages have led Texas to a policy crossroads which, argue Daniel Bullock and Paul Cauduro, could lead to another wave of CHP developments in the state’s industrial and commercial sector.

With its oppressive temperatures, unprecedented drought and historic wild fires, the summer of 2011 will be long remembered in Texas. Daytime temperatures routinely soared past the century mark (100°F/38°C), driving the average summer temperature to an all-time high of 86.8°F (30.4°C).

With a statewide average rainfall accumulation of only 2.4 inches (6.1 cm), it was also the driest summer on record. In fact, October 2010 through September 2011 was the driest 12-month period since the state began keeping rainfall records back in 1895. The dry weather contributed to a terrible wild fire season during which nearly 3.5 million acres of forest were consumed.

The extreme summer conditions also exposed some serious cracks in the state’s electrical grid operated by the Electric Reliability Council of Texas (ERCOT). As temperatures soared last summer, the state’s all-time peak load record of 65,776 MW from 2010 was comfortably exceeded on several occasions, with a new record of 68,379 MW set on 3 August.

With tight power supplies across the state, power prices are beginning to reflect increasing scarcity. Throughout the summer, wholesale power prices in ERCOT spiked to the maximum allowable price of $3000 per MWh, and the state grid teetered precariously close to emergency rolling blackouts many times.

The hot, dry weather is predicted to continue this year, which is raising additional concern about power reliability this coming summer. ERCOT is currently projecting a reserve margin this summer of about 12% – well below its 13.75% requirement – and that could get a lot worse. Of paramount concern is a recent report released by ERCOT identifying nearly 11,500 MW of electricity generating capacity, roughly 18% of the grid’s total installed capacity, relying on water sources that are at historically low levels.

When these conditions are combined with increasing power needs driven by economic recovery and continued high population growth, ERCOT forecasts the reserve margins for 2014 and 2015 at roughly 7.6% and 3.6%, respectively.

Adding to the uncertainty are proposed Environmental Protection Agency (EPA) mercury emission rules and concerns over water consumption and transported air pollution from ageing power plants, which call into question the economic value of some of the Texas fleet’s older generating assets. The bottom line is that the reliability of the state’s power grid is becoming increasingly precarious and ensuring power reliability requires immediate solutions.

In addition, the costs of the state’s renewable energy programmes are now having greater price impacts. For example, a programme to build transmission lines to accommodate additional wind power in the state is coming in nearly 40% higher than initially thought. With the price tag now at about $6.8 billion, the transmission lines are expected to cost the average residential ratepayers about $600–800 over the next decade.

As these issues are unfolding, a constant drumbeat of news suggests that abundant natural gas supplies will keep the price of the fuel at multi-year lows for the foreseeable future. The economics of CHP development are, therefore, expected to become increasingly attractive, driving more adopters to seek CHP for both its economic value proposition and for power reliability.

State policymakers will also find value in the vast quantities of water that can be saved in the power sector by deploying additional CHP. As a result, the impending power and water crunches in Texas could be important drivers for additional CHP development in the state over the next few years.


Beginning with a 2 MWe unit built back in 1921, Texas boasts 125 CHP facilities with a combined capacity of about 17,000 MWe. This is the largest CHP fleet of any state in the union and it generates about 20% of Texas’s electricity. The bulk of the current fleet is comprised of large (100–1000 MWe+) systems at industrial sites along the Texas coast. But the recent trend has been towards smaller systems that better match the thermal requirements at smaller industrial, commercial and institutional sites. Many of the systems developed over recent years are 50 MWe and smaller.

Figure 1. Texas CHP capacity additions (MWe)
Source: US DOE Gulf Coast Clean Energy Application Center

Historical CHP capacity additions are shown in Figure 1. The graph illustrates how an aggressive policy agenda to support CHP could increase the size of the fleet by more than 10,000 MWe by 2025. The CHP industry has experienced strong growth of this order before, due, in part, to sound policy directives from the Public Utility Commission in the lead-up to restructuring of the electricity industry in 1999. As a result, industry added about 10,000 MWe of new CHP capacity between 1995 and 2002.

But remaining economic and policy barriers limit further gains, especially in smaller CHP systems. The state is, again, at a crossroads where the implementation of smart policies supportive of CHP could stimulate another burst of CHP development.

Given the coming power crunch, support for additional gas-fired power generation is expected to increase. A business-as-usual approach would maintain the status quo regarding relative market penetration of traditional power generation technologies, with much of the additional focus directed towards developing additional utility-scale combined-cycle power plants.

An alternative approach is to encourage more efficient CHP generation, which could be distributed throughout the state at a greater number of industrial, institutional and commercial enterprises. While adding any type of gas-fired generating asset would enhance system reliability in ERCOT, the second option has the following additional advantages. CHP would:

  • increase the energy efficiency over the combined-cycle by up to 33%;
  • reduce water consumption by the power sector;
  • reduce emissions of nitrogen oxides (NOx) and sulphur oxides (SOx);
  • improve power reliability at adopter sites;
  • enhance industrial competitiveness and job retention.

This article analyses the benefits of two alternative approaches available to the State of Texas as it works to enhance the reliability of the power grid while simultaneously addressing water shortages and air quality.


Although the state has a large amount of CHP today and more than 120 of the best industrial sites have already implemented the technology, there are still many sites where CHP projects could be successfully developed. A 2008 Public Utility Commission of Texas report estimated that an additional 13,400 MWe could be economically developed in Texas by 2023.

To extend that 2008 report, one of the authors undertook a white paper study to evaluate the potential environmental and economic benefits of developing CHP on that scale. Completed in 2011, the study compared two alternative scenarios for CHP uptake through 2025 and evaluated the impacts of each on natural gas and water consumption, and on the emissions of carbon dioxide, NOx and SOx. The two alternatives included in the study are:

  • Case 1: business-as-usual (CHP remains at 20% of total power production);
  • Case 2: expanded CHP (CHP increases to 35% of total power production).

Achieving substantial development of new CHP capacity as described in Case 2 would likely require the consideration of a wider range of industrial sites than has been done previously, and more focus on opportunities at commercial and institutional sites. How the development of CHP might proceed in the two cases is presented in Table 1.


The business-as-usual case represents a continuation of the state’s current policy approach up to the study horizon in 2025. The case assumes that the expansion in the existing base of generating technologies is consistent with historical growth rates and that – in line with reasonable expectations – additional units could come on line under future regulatory regimes. The following assumptions were made:

Coal-fired power plants

Currently available electricity production by coal-fired power plants is assumed to increase at 0.75% per year, but unused capacity is brought on line to meet load growth. In this scenario, environmental pressures are anticipated to slow growth in coal use to half the rate of increase in overall load, as emerging EPA regulations on air quality, water use and ash disposal could result in the retirement of some units.

Table 1. CHP market comparison in 2025 under competing alternatives

Combined heat and power

CHP facilities are expected to grow in line with their historical growth rate and to continue to supply about 20% of total statewide electricity. Significant CHP capacity was built during the 1980s and is now about 30 years old. These systems will likely be retired and replaced with newer, more efficient gas tubine technology.

The CHP growth rate is expected to average about 1% per year through 2025. Because CHP systems are tied to a host facility requiring steady supplies of thermal energy, CHP plants are anticipated to have ‘must-run’ status and achieve a high capacity factor of between 56% and 60%, consistent with the existing fleet’s 56% capacity factor achieved in 2010.

Natural gas-fired power plants

The use of natural gas combined-cycle and simple-cycle generators is assumed to remain on the margin in the state. The use of the state’s existing fleet of natural gas generators is assumed to grow at a rate of 0.8%, which is about half of the overall load growth, but slightly faster than the growth of coal.

Nuclear power plants

Nuclear power plants continue to run indefinitely at a high capacity factor of more than 90%, with no further increase in output projected. The analysis assumes zero growth in nuclear output, as safety, cost, water-use and financial issues are assumed to rule out an expansion of the current facilities by 2025.

Wind power

The average annual rate of growth for wind is 6.4%, although the rate is higher between 2012 and 2016. This is consistent with the current plan developed with CREZ to double wind capacity to about 18,000 MW in the next 5–10 years.

Other resources (such as hydroelectric, photovoltaic, biomass)

Today, non-wind renewable energy resources serve about 0.4% of the state’s electricity needs. In the future, the annual growth of non-wind renewable energy resources is projected to average 17.5% through 2025, which reflects adoption of a 500 MW carve-out in the Renewable Portfolio Standard for non-wind renewable energy. The growth rate used is consistent with achieving about 500 MW of non-wind renewable energy technologies by 2025.

The results of the Case 1 analysis are shown in Figure 2, which illustrates the amount of energy provided by each resource over the planning horizon.

The analysis assumes that throughout the planning horizon, the use of each resource remains consistent with its historical deployment levels. All resources, therefore, continue to provide increasing energy, although their relative ranking is unchanged except for wind power. Wind power is seen to eclipse nuclear power as an energy resource around 2016. Continued growth in wind power and, eventually, in non-wind renewable energy is anticipated to be sufficient to meet the additional growth in demand.


This case examines specific assumptions whereby the state moves towards greater electricity generation using natural gas and less from coal. Specifically, this scenario involves a shift in energy planning and policy towards more natural gas-fired combined heat and power technologies. As a result, the existing CHP resource base grows rapidly throughout the planning horizon, building from the current 20% of total electricity to 35% by the end of the study horizon in 2025.

The scenario envisions strong uptake of CHP among industrial sites, including waste heat recovery at industrial sites and natural gas compressor stations.

Figure 2. Case 1 – business-as-usual
Source: US DOE Gulf Coast Clean Energy Application Center

An expansion of smaller-scale CHP into relatively untapped commercial and institutional applications using microturbines and pre-engineered or ‘packaged’ CHP systems is also anticipated. As a baseload resource operating primarily at industrial locations, additional CHP implementation turns coal-fired power plants into the marginal units within ERCOT.

As a result, the scenario considers the increase in CHP output to exclusively displace the output from coal plants, while all other resources maintain the growth rate projected in the business-as-usual case. The following assumptions are used in Case 2:

Combined heat and power

The use of CHP is greatly expanded from the current production level of 20% of total electrical load to 35%. Growth is slower at first, but rapidly increases in 2015–20. CHP systems are anticipated to have ‘must-run’ status and to achieve a high capacity factor of 60–70%, consistent with, but somewhat higher than, the existing fleet’s 56% capacity factor achieved in 2010.

Coal-fired power plants

Coal-fired power plants become the marginal units in the state. Their production is displaced by the growth of more efficient and cleaner natural gas-fired CHP systems.

Natural gas-fired power plants

Same as Case 1.

Nuclear power plants

Same as Case 1.

Wind power

Same as Case 1.

Other resources (such as hydroelectric, photovoltaic, biomass)

Same as Case 1.

The results of the Case 2 analysis are shown in Figure 3. The increased use of CHP exclusively displaces coal-fired generation in the model, which represents a large switch in primary fuel for power generation from imported coal and Texas lignite to Texas natural gas.

The use of other resources remains consistent with their performance in the business-as-usual case. Wind power, again, eclipses nuclear power as an energy resource around 2016. Non-wind renewable energy, again, shows substantial growth later in the decade. Natural gas and nuclear trend lower on a percentage basis as in the business-as-usual case. Wind and non-wind renewable energy meet about 18% of total load by 2025. The use of coal is substantially reduced allowing many older, more inefficient facilities to be retired.

The growth of CHP from 20% to 35% of load necessitates an increase in energy production from CHP facilities from the current 80 TWh to nearly 175 TWh, a rise of about 95 million MWh. This will require many additional host sites and a significant investment in new facilities, possibly including expansion of CHP beyond the traditional industrial locations at large refining and chemical sites to smaller process and manufacturing plants, as well as many commercial and institutional applications.

At an estimated capacity factor of 60–70%, the increase in CHP output would drive economical capacity additions of about 14,075 MW, which is consistent with the 2007 Public Utility Commission report regarding CHP potential in Texas.

Figure 3. Case 2 – expanded use of CHP
Source: US DOE Gulf Coast Clean Energy Application Center

Many new, large industrial projects in the 50–100 MW range would be expected, although significant growth would also be needed in industrial and commercial projects under 20 MW in size. Many of the smaller projects could be under the 1 MW threshold, including potential projects at nursing homes, condominiums, high schools and similar facilities, which could be in the 100–1000 kW range.


Implementing CHP on the scale suggested in Case 2 would shift 15% of the state’s electrical consumption from coal to highly efficient CHP facilities fuelled by cleaner natural gas. The change would have a major impact on several high-profile natural resource and environmental issues in the state, including natural gas consumption, carbon dioxide emissions, sulphur dioxide emissions, nitrogen dioxide (NO2) emissions, and water used for power generation.

These impacts were estimated through a comparative study of the two cases, which involved calculating the impacts of each throughout the planning horizon.

Natural gas consumption

Expanding the use of CHP, as described in Case 2, increases natural gas consumption for power production from about 1500 billion cubic feet (Bcf) (42 billion m3) today to about 2250 Bcf (64 billion m3) by 2025. In the business-as-usual case, natural gas consumption increases more modestly to about 1600 Bcf (45 billion m3).

Case 2 would, therefore, be expected to increase natural gas consumption by about 3.3 trillion cubic feet (90 billion m3) between 2012 and 2025. At the current price of about $4.25 Mcf ($0.15/m3), the value of this gas increase to producers would be about $14 billion. The State of Texas may see additional revenues through the sale of state gas into this market and through the collection of additional severance tax revenues.

Carbon dioxide emissions

Expanding CHP, as in Case 2, would cut current annual carbon dioxide emissions from power production of about 300 million tonnes to about 250 million tonnes. In the business-as-usual case, carbon dioxide emissions increase by 12% over the same period.

Compared with the business-as-usual case, the CHP case reduces carbon dioxide emissions by about 511 million tonnes between 2012 and 2025. At completion of Case 2 in 2025, annual carbon dioxide emissions would be reduced by about 81 million tonnes per year.

Sulphur dioxide emissions

Expanding CHP, as in Case 2, would cut current annual sulphur dioxide emissions from power production of about 700,000 tonnes to about 420,000 tonnes. In the business-as-usual case, sulphur dioxide emissions continue to increase, reaching 800,000 tonnes at the end of the planning horizon in 2025.

Compared with the business-as-usual case, the CHP case reduces sulphur dioxide emissions by about 2.4 million tonnes between 2012 and 2025. At completion of Case 2 in 2025, annual sulphur dioxide emissions would be approximately 380,000 tonnes less than under the business-as-usual case – a reduction equivalent to retiring about 21 500 MW coal plants.

Nitrogen dioxide emissions

Expanding CHP, as in Case 2, would cut current annual nitrogen dioxide emissions from power production of about 285,000 tonnes to about 185,000 tonnes. In the business-as-usual case, nitrogen dioxide emissions continue to increase, reaching 320,000 tonnes at the end of the planning horizon in 2025.

Compared with the business-as-usual case, the CHP case reduces nitrogen dioxide emissions by about 850,000 tonnes between 2012 and 2025. At completion of Case 2 in 2025, annual nitrogen dioxide emissions would be approximately 140,000 tonnes less than under the business-as-usual case – a reduction equivalent to retiring about 22 500 MW coal plants.

Water use

In Figure 4, the difference between the lines in the graph shows the impact on water consumption of the expanded CHP case for specific years and – by looking at the total area between the two lines – throughout 2012–25.

In the business-as-usual case, water consumption would continue to increase, reaching 120 billion gallons (454 billion litres) in 2025.

Expanding CHP, as in Case 2, would in contrast cut water consumed in power production from the current level of about 110 billion gallons (416 billion litres) per year to about 95 billion gallons (360 billion litres).

At completion of Case 2 in 2025, annual water consumption would be reduced relative to the business-as-usual case by about 25 billion gallons (95 billion litres) per year. Between 2012 and 2025, the CHP case reduces water consumption by a total of about 161 billion gallons (609 billion litres).


Sufficient sites exist to expand the use of CHP in Texas to provide 35% of total statewide electricity. Achieving this goal would result in substantial economic and environmental benefits, while addressing the emerging power and water crunches in ERCOT.

Figure 4. Water consumption in billions of gallons
Source: US DOE Gulf Coast Clean Energy Application Center

Achieving this much new capacity will likely require more supportive actions by state policymakers, as investment decisions by individual companies, whether independent power producers or potential CHP adopters, are based on specific market conditions that may be unrelated to the needs of the statewide electricity system.

Important barriers that prevent companies from investing in CHP must be addressed to ensure projects can continue to be developed in traditional industrial markets and also in emerging markets, including at non-traditional industrial sites and at commercial and institutional sites.

Supporting actions include, for example, new rules regarding nitrogen oxide emissions permits for CHP systems. The Texas Commission on Environmental Quality (TCEQ), the state’s environmental regulatory commission, is developing new air permitting regulations specifically for CHP plants as a result of legislation from 2011.

Currently, CHP plants must adhere to air permitting regulations established for large utility-scale power plants. The new permit being developed is expected to reduce regulatory burdens and system costs.

This year, several energy issues are scheduled to be discussed by the Texas House and Senate during the interim period until the next legislature convenes. The issues include examinations of:

  • current state and federal laws and regulations to develop recommendations encouraging additional energy production;
  • new and proposed EPA rules that may impact permits for Texas facilities and recommendations for changes in state programmes or potential incentives to enable compliance;
  • the interplay of water and energy resources to determine the state’s current and future water needs for power generation;
  • the issues of resource adequacy in the Texas electricity market and how to best maintain adequacy.

Hearings on these issues and topics will provide ample opportunity for industry stakeholders to educate legislators about CHP’s potential and offer solutions. Much of what unfolds in 2012 will set the stage for legislative action when the 83rd Texas Legislature officially convenes in January 2013.

With the focus of regulators, legislators and the public on power reliability and water shortages, 2012 represents a unique opportunity for the CHP industry in Texas to offer a viable alternative to the business-as-usual scenario. Whether or not a shift in the state’s energy planning and policy positions will transpire is yet to be seen, but with so many positive attributes and an engaged CHP industry, a welcome rain of new CHP projects may be approaching.

Daniel Bullock is the Director of the US Department of Energy Gulf Coast Clean Energy Application Center and a Senior Research Scientist at Houston Advanced Research Center Email:

Paul Cauduro is the Executive Director of the Texas Combined Heat and Power Initiative Email: This article is available on-line. Please visit

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