Integrating Variable Renewable Electric Power Generators and the Natural Gas Infrastructure November 2011

white paper Integrating Variable Renewable Electric Power Generators and the Natural Gas Infrastructure November 2011 Summary While there has been extensive discussion and analysis of the requirements for integration of renewable electricity generators with the electric grid, there has been much less focus on the interactions with the natural gas grid, which, nevertheless, could be significant. There is widespread agreement that gas-based generation will be an important component of renewable integration but there has been little detailed analysis to date of the potential interactions between the electric and natural gas systems. There is already significant variability in daily gas use due to weather and other factors: (1) residential and commercial gas loads fluctuate significantly with changes in weather, (2) electric load also fluctuates with weather and by time of day, which in turn drives fluctuations in gas demand for power generation, and (3) variability in loads from these sources will change as the amount and nature of load changes over time. Projected impacts of renewable generation variability make up a relatively small portion of total gas load variability, but the variability associated with responding to renewable generation will grow as renewable capacity increases. Although it will still remain a small part of total gas load variability, renewable integration can have a significant effect on local infrastructure and operational requirements. Overall, the issue is not total gas volume changes, but rather changes in operations and infrastructure and requirements. Plans must be made to account for the potential variability associated with gas-fired generation used to support variable renewable generation. The purpose of this ICF White Paper is to provide a better understanding of the implications for natural gas infrastructure requirements and operation resulting from the integration of significant amounts of variable renewable generation on the electric grid. This ICF White Paper is based on several recent ICF studies as well as some internal studies that have heretofore not been published. 1,2,3 I. Introduction Wind generation is the primary example of variable renewable generation, since it is the largest and fastest growing source, in terms of installed capacity, of variable renewable generation. To the extent that variable renewable generation changes the composition of generation capacity and operation of the U.S. power grid, there will be changes in requirements for gas infrastructure, operations, and contractual agreements for gas-fired generators. Increased use of variable renewable generation affects the power grid in a variety of ways, and gas-fired power plants will play a key role in responding to these changes. The issue is less one of changing total gas volumes which overall will decrease as a result of wind additions. Rather, the issues are primarily operational, infrastructure requirements, and cost recovery. The focus of operational issues for power and gas reflects the fact that peaking power plants, which respond to short-term variations in demand, are mostly gas-fired. Similarly, most of the recently built base load power plants and nearly all non-renewable power plants projected to be built in the near future are gas-fired. Furthermore, nearly all incremental quick-start peaking capacity will be gas-fired. As a result, the operational and capacity expansion changes associated with increased use of variable renewable generation have implications for the design and operation of the natural gas infrastructure that supplies these plants. 1 INGAA Foundation, Firming Renewable Electric Power Generators: Opportunities and Challenges for Natural Gas Pipelines, prepared by ICF International for the INGAA Foundation, March 16, 2011. 2 Wyoming Infrastructure Authority, Wyoming Wind Collector System and Integration Study, Prepared by ICF International for the WIA and Wyoming State Energy Office, February 2011. 3 The Value of Natural Gas Storage and the Impact of Renewable Generation on California s Natural Gas Infrastructure. California Energy Commission, PIER s Energy Systems Integration-Strategic Natural Gas Program. CEC-500-2009-004. http://uc-ciee.org/all-documents/a/lbrsearch/page-11 1 icfi.com

Whereas conventional generators can be dispatched as needed to respond to electric demand, the output of variable renewable resources is determined by the wind or sun, which cannot be controlled by electric system operators. The remainder of this paper provides: Background on implications of the integration of variable renewable energy sources Three illustrative scenarios Selected gas infrastructure implications Conclusions II. Background on implications of the integration of variable energy resources The underlying driver for the renewable integration issues addressed in this white paper is the variability of renewable generating resources such as wind. Whereas conventional generators can be dispatched as needed to respond to electric demand, the output of variable renewable resources is determined by the wind or sun, which cannot be controlled by electric system operators. There is a societal benefit to using these resources as much as possible due to their low operating cost and zero emissions, but the electrical system must be able to supply power from other sources when the variable sources are not available. The variability is manifested at different time scales and these must be addressed through different planning and operational measures. Exhibit 1 shows this variability of wind generation and electric load over the entire year for parts of the western U.S. The top chart shows electric load by month (vertical axis) and hour of the day (horizontal axis). Red signifies higher load and blue signifies lower load. The chart shows the highest periods of electric load during the summer afternoons, fall and spring mornings, and winter nights. The bottom chart shows wind generation over the same time periods. It shows generally low generation throughout the summer months and the highest generation during the early spring days. While there is significant electricity generated from the wind plants over the year, there is a poor correlation between load and generation in this case. While the correlation may be better in other regions, this example makes the point that variable renewable generators are not dispatchable in the same way as conventional power plants to provide power when most needed, whereas system operators must ensure that the overall generating mix can supply the required generation at all times by building sufficient conventional resources to meet load even when variable generating resources are not available. In addition to ensuring that there is enough dispatchable capacity to meet the total demand, system planners and operators must ensure that the system has the right mix of technologies to meet the day-to-day and minute-to-minute requirements. Electric load is constantly changing during the day, and supply must follow it continuously and instantaneously. System operators develop day-ahead predictions of load over the day but must also be able to respond to sudden increases or decreases in demand or supply during the day. There is always the possibility that a conventional generating unit will go off-line or that demand will change suddenly. The addition of variable renewable generators is one more factor in this mix of potentially varying supply and demand. Different types of generators have different abilities to respond to changes in demand. Baseload power plants may take days to start up from a shutdown and hours to respond to a major change in load. Intermediate load plants can respond in hours or less. Peaking plants can come on line in less than one hour and some quick-start or fast ramp peaking units can come on line within 10 minutes. System operators also employ spinning reserve, which is a mix of different types of plants that are on-line and can provide additional capacity immediately. System operators plan daily how to dispatch these resources to meet the next day s load based on forecasts of expected load over the day and availability of generating resources, including expected output of renewable generators based on predicted weather. Power plants are committed over the course of the day, i.e., turned on to be ready to dispatch to meet the expected load. The lead time from initial start-up to synchronization of production of power varies depending on the type of resource. Once committed and synchronized with the grid, the units can be dispatched (i.e., operated to meet expected electricity demand). 2 icfi.com

Exhibit 1. Example Electric load versus wind generation Regional Wind Generation Regional Electric Load Source: WACM Wind Production Summary Overview, Western Area Power Administration, October 2006. Although electricity supply and load are forecast daily, there can always be deviations from the forecast. Exhibit 2 shows that the forecast error can result in the need for either more or less generation at any given time. 4 Additional gas-fired and/or other units need to be committed to ensure the electric system s operating reserve is adequate each day to account for the difference between the supply forecast to be available and what is actually available to meet load, as well as differences between forecasted and actual load. The unit commitment requirement to address forecast error is usually the net of many load and supply variations and the exact amount required depends on local conditions including the nature of the load and the relative inter-connectedness of the grid. The additional supply uncertainty associated with variable renewable resources 4 The specific forecast error depicted in Exhibit 2 is the day ahead forecast error for a collection of wind resources in Wyoming. (See footnote 2.) 3 icfi.com

Exhibit 2. Responding to forecast error changes Requirements for grid operation 70% 60% Excess generation ramps down other generation Actual wind generation Forecast wind generation Wind capacity factor 50% 40% 30% 20% 10% 0% Additional generation needed from conventional generation and/or electric storage 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour of day Source: ICF In the U.S., the binding system generation reliability constraint is the need to meet expected peak demand plus 12 to 20 percent reserve requirements. Thus, a system with an expected 10,000 MW peak needs 11,200 to 12,000 MW of firm capacity equivalent. typically increases this forecast error component. It does not necessarily require the addition of new generating units if the renewable capacity is added to a system with adequate existing peaking generation, or if system planners have had adequate information and foresight to include the requirements in construction planning. In other cases, additional gas-fired capacity, especially peaking units, will need to be built to meet this requirement. Finally, there can be sudden changes in gas-fired generation in response to very short term (10-minute or less) fluctuations in load or generation, and this increasingly includes variable generation levels that deviate from one time period to the next. Real-time plant operation to handle unexpected conditions is referred to as system regulation and focuses on minutes or seconds. These requirements must be met by spinning reserve and quick-start peaking units designed to come on-line very quickly. Exhibit 3 illustrates these power planning and operations processes and the technology issues associated with integrating variable generation sources. The figure emphasizes the time dimension of power processes including: Long-term planning Resource and capacity planning needs to account for variability and reliability differences between variable energy resources and dispatchable fossil plants in order to meet planning reserve margin requirements. That is, on a multi-year basis, planning to build sufficient dispatchable generation to meet system peak load. In the U.S., the binding system generation reliability constraint is the need to meet expected peak demand plus 12 to 20 percent reserve requirements. Thus, a system with an expected 10,000 MW peak needs 11,200 to 12,000 MW of firm capacity equivalent. Because of the variable nature of their output, variable renewable generators primarily supply energy (MWh) rather than firm capacity (MW) to the electric system. Nonetheless, electric system operators typically allow approximately 10 to 20 percent of the variable renewable capacity to count toward system planning reserve margins compared to almost full capacity credit for conventional generators. The remaining demand growth and reserve requirements must be met by conventional generation, which in today s industry will primarily be natural gas generating facilities. Thus, in planning to meet demand 4 icfi.com

Exhibit 3. Power system planning and operation Slower (years) Planning and operation process Resource and capacity planning (Reliability) Technology issues Capacity valuation (UCAP, ICAP) and long-term load growth forecasting Faster (seconds) Time frame Unit commitment and day-ahead scheduling Load following (5 minute dispatch) Frequency and tie-line regulation (AGC) Day-ahead and multi-day forecasting Hour-ahead forecasting and plant active power maneuvering and management Real-time and autonomous protection and control functions (AGC, LVRT, PSS, Governor, V-Reg, etc.) Source: The Effects of Integrating Wind Power on Transmission System Planning, Reliability, And Operations, Page 1.5, GE Energy prepared for NYSERDA, March 2005. growth, variable renewable capacity must be accompanied by substantial dispatchable generating resources to ensure system reliability This requirement does not apply where the renewable capacity is not intended to meet demand growth. Even in that case, however, integration of increased variable renewable generation may require investment in more or different kinds of peaking units, as discussed below. Integration of variable renewable resources can, in some cases, decrease the amount of natural gas capacity needed to meet demand growth by 10 to 20 percent of the wind capacity added (the generally assigned wind capacity credit toward meeting reserve margin requirements). It can also change the mix of conventional power plants (base load, intermediate, peaking, quickstart) that should be built. For example, it may decrease the use of intermediate gas-fired units like combined cycles and increase the use of gas-fired peakers. In particular it may decrease the amount of conventional peaking gas-fired capacity (i.e., gas-fired peaking power plants with slower start-up and ramping capability) and raise the need for quick-start, high ramp-rate power plants as the need to respond to rapid and unexpected fluctuations in grid conditions increases. In some cases, renewable variable generators significantly increase the required amount of gas-fired capacity if variable renewable generators are required to account for forward forecast error outside the context of a utility system, i.e., renewable generators must account for the difference between day-ahead and actual wind output without reference to the interaction between electricity demand and utility supply variation. This case is discussed below. Day-to-day operation Unit dispatch and commitment For operations closer to a day 5 icfi.com

Integration of variable renewable units is likely to increase the commitment of natural gas-fired units to ensure available generation to handle deviations from forecast levels. ahead of the real time electricity market, the reliability of the bulk power system is secured by ensuring that there is adequate generation supply with proper characteristics available to meet the forecast demand and its expected variation while maintaining bulk power system reliability. This involves increased unit commitment (i.e., start-up) of power plants to ensure load and unit commitment variability can be met with dispatchable units (e.g., if a unit is scheduled to be offline for maintenance). Integration of variable renewable units is likely to increase the commitment of natural gas-fired units to ensure available generation to handle deviations from forecast levels. On the other hand, the increased use of renewable gener tion typically will decrease the dispatch of natural gas and other plants that are displaced by the generation from variable energy resources. Approaching and including real time supply In the period a few hours to a few minutes ahead of load requirements, the electric system operator requires a forecast of demand and generation at much higher accuracy and will also more closely consider the ramp-rate capability of the resource fleet within or outside its Balancing Area to ensure that these resources are available and can be dispatched or maneuvered to ensure supply-demand balance while maintaining bulk power system reliability. This requires the availability and use of quick-start units. Integration of variable renewable generators will require increased use of quick-start gas-fired power plants to regulate short-term supply and demand balance. III. Three illustrative scenarios examined This White Paper discusses three hypothetical power industry scenarios that serve to illustrate the potential impacts of variable renewable generation on natural gas-fired power plants and gas infrastructure (see Table 1). Each scenario involves the same amount of wind capacity expansion, however the power sector circumstances differ. Scenario I Scenario I is a situation in which the electric system is assumed to be planning for long-term electricity demand growth requiring 800 MW of incremental capacity to meet planning reserve margin requirements. The system planners can fully integrate new generating resources with the utility load. In this scenario, it is initially assumed that 800 MW of gas-fired capacity would be added. However, the system planning situation is changed, with 800 MW of wind being added instead. This is assumed to occur due to either market or regulatory factors or both. Scenario II Scenario II is one in which utilities are planning to meet a Renewable Portfolio Standard (RPS) through the installation of 800 MW of wind capacity. Scenario II assumes no growth in electricity demand but system planners and operators must address the requirements of the added renewable capacity. Scenario III Scenario III differs from the other two in that the integration is not handled in the context of a utility system Table 1. Incremental gas generation capacity requirements in response to wind capacity additions Three scenarios Scenario I Long-term utility planning II Utility RPS planning III Renewables eliminate forward forecast error outside utility context Description Utility s plan is to meet 800 MW of demand growth with gas-fired capacity, but changing circumstances results in 800 MW of wind additions. Utilities add 800 MW of wind to meet RPS. There is no planning for forecast electrical load growth. Variable renewables responsible for forward forecast error Incremental wind capacity (MW) +800 +800 +800 6 icfi.com

where supply and demand interactions are occurring. Rather, the renewable producers for contractual, regulatory, and/or system conditions must, on their own, arrange or eliminate the deviation in wind output from forecasted output within the day or a shorter period (e.g., a few hours). In Scenario III, the wind plants need to arrange to compensate for the difference between the wind supply forecast and actual wind output without reference to demand fluctuations, and do so by arranging for gas-fired generation capacity and operation. This likely represents a worst case situation from the perspective of wind generators. The scenarios are useful constructs to think through the implications of increasing amounts of variable renewable generation on the power grid and natural gas infrastructure. They capture a wide range of potential utility planning conditions under which large amounts of wind are added. 5 They also address requirements on wind generators to match wind forecast and actual delivery themselves. In reality, a combination of these scenarios may apply to a given situation. To analyze the important integration issues, we make the simplifying assumption that gas-fired and variable renewable generation sources are the only two alternative sources of incremental power supply. We also note that many of these power/gas integration issues pre-exist the large scale introduction of variable renewable generation to some degree. 6 Scenario I Long-term utility planning for demand growth Scenario I addresses the integration of variable renewable generation into a utility system that is planning for electricity demand growth. In Scenario I, the utility plans initially to add 800 MW of natural gas plants to meet future demand. However, due to economic or regulatory conditions (e.g., high gas prices or new RPS rules), 800 MW of wind is added instead. The first impact is on planned gas-fired capacity expansion. As discussed above, electric system operators typically allow approximately 10 to 20 percent of the variable renewable capacity to count toward system planning reserve margins. Therefore, the total amount of conventional generating capacity required in addition to the renewable generation will be close to the original requirement and the total capacity of renewable resources (10-20 percent less due to the credit for the renewable generation). In this scenario, instead of adding 800 MW of gas-fired capacity as originally planned, 640 MW to 720 MW (-160 MW to -80 MW) of gas capacity is added in addition to the 800 MW of wind capacity. In addition to reducing the amount of conventional generating resources required, adding variable renewable generation to the mix can change the kind of conventional generating resources that will be required as well as the way those resources will be used. The renewable additions may partially shift the mix of conventional generating resources from base load and intermediate combined cycles to gas-fired peaking units. There can also be impacts on the type of gas-fired peaking units as regulation of short-term fluctuations becomes more challenging, requiring more quick-start peaking units. Increased use of variable resources will increase the requirement for unit commitment to account for predictable differences in output and load as well as the unexpected fluctuations in variable generation and load due to weather and other 5 For example, if one builds 800 MW and wants to know how much gas generation capacity is needed to have 800 MW count towards the utility reserve margin requirement, the answer is 640 to 720 MW or 80 to 90% of the wind installed capacity. 6 For example, there are no firm gas capacity fuel supply requirements for power plants even though there are reliability rules that result in very heavy power grid reliance on gas generation capacity. Costs of New Entrants (CONE), a regulatory construct helping to set compensation for new units in the power sector, lacks the costs of firm gas supply. 7 icfi.com

factors. Quick-start peaking units that can provide ten minute operating reserves are an important power system component for responding to rapid and variable fluctuations in load as well as renewable output. This quick-start capacity may already be present in an existing electric system or may be included in the power system planning processes. In this scenario, system planners could add quick-start capacity as part of the plan to integrate the new renewable capacity and potentially build less conventional intermediate or base load capacity due to the availability of the renewable capacity. Although increased variable renewable generating capacity only modestly changes the amount of conventional capacity that is required to meet peak demand under the current capacity planning rules, it can change the utilization of the conventional capacity on the system. The renewable generation replaces some conventional generation, reducing the utilization primarily of the intermediate load units on the system. In many markets, this is natural gas-fired generating units, but it could be coal depending on the local generating mix and the profile of wind generation. For example, Exhibit 4 shows how wind generation has reduced utilization of natural gas generators in Texas over the 2006 to 2010 period. Texas is the state with the largest amount of wind power plant capacity currently on line. Gas-fired and/or other units need to be committed to the daily generation mix to ensure the electric system s operating reserve is adequate each day to account for the difference between the supply forecast to be available and what is actually available to meet demand. This commitment requirement due to forecast error is usually the net of many load and supply variations and the exact amount required depends on local conditions including the nature of the load and the relative inter-connectedness of the grid, but it is typically larger when variable renewable resources are added to the system. There also Exhibit 4. Increased wind generation typically backs down gas generation 450 Texas electricity generation by fuel 1990-2010 (EIA) 400 350 hwmno M 300 250 200 Other renewables Natural gas Other Nuclear Coal 150 100 50 0 1999 2000 1990 1991 1992 1993 1994 1995 1996 1997 1998 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Data Source: EIA 8 icfi.com

If new generating capacity must be built, new local gas delivery capacity will be needed to supply it. may be sudden changes in gas-fired generation in response to variable generation levels that deviate from the forecasts. It does not necessarily require the addition of new generating units if the renewable capacity is added to a system with adequate existing peaking generation or if, as in this case, system planners have had adequate information and foresight to include the requirements in construction planning. In other cases, additional gas-fired capacity, especially peaking units, will need to be built to meet this requirement. The amount of natural gas actually used to meet these short-term, quick-start requirements is quite small, typically much smaller than the reduction in overall gas generation displaced by the renewable generation, so net gas demand typically declines with the addition of renewables. However, the increased use of the peaking generation affects requirements for and operation of the gas supply infrastructure. If new generating capacity must be built, new local gas delivery capacity will be needed to supply it. Depending on the location of the generating resources, new mainline gas pipeline capacity also may be needed. In addition, the variability of the demand and the rapid response requirement change the way that gas contracts need to be established, change the way that the system needs to be operated to meet these new demands, and may require new investments in gas delivery infrastructure, even for existing generating facilities. In the recent INGAA Report, the analysis of the ten minute operating reserve needed to respond to short-term fluctuations in variable renewable generation indicates a requirement to commit and use conventional units with capacity equal to 10 to 15 percent of the renewable capacity (see Table 3). 7 Other ICF analysis not heretofore published shows a comparable range of 7 to 12 percent, and hence, corroborates the results from the INGAA Report and other studies. 8 Units that can supply ten minute operating reserves would typically possess quick-start and rapid ramp up capabilities, e.g., LM 6000, LMS100, or reciprocating engines. Scenario II Utility planning for RPS In Scenario II, renewable generation is added to an existing system for regulatory (e.g., RPS) or economic reasons but not in response to demand growth. Scenario II has much in common with Scenario I. First, the construction of variable renewable generation to meet the RPS decreases Table 3. Amount of quick-start natural gas generation capacity required per MW of wind added (percent) Region INGAA Internal ICF analysis California Wyoming 10% 12% Kansas Oklahoma 11% 12% New England 15% 7% 7 The range reflects information in Appendix 2 of the INGAA Report on fluctuations in ten minute demand, and wind supply. The wind supply is aggregated from multiple sites in a region. A sudden decrease in wind output is the key driver; the magnitude of the need is partly offset by demand changes. National Renewable Energy Laboratory study prepared by EnerNex Corporation. Eastern Wind Integration and Transmission Study. Subcontract Report NREL/SR-550-47078, January 2010. Internal ICF analysis cited data available from a National Renewable Energy Laboratory study prepared by GE Energy. Western Wind and Solar Integration Study. Subcontract No. AAM-8-77557-01, May 2010. 8 As a reference, an estimate of 9.4% increase in quick-start non-spinning operating reserves due to wind, (i.e., 9.4 MW for every 100 MW of wind), was derived from the ERCOT Wind Integration study performed by GE for installed wind capacity of 15,000 MW in ERCOT. See Executive Summary Analysis of Wind Generation Impact on ERCOT Ancillary Services Requirements, March 28, 2008, Page 12, prepared by GE Energy. The key parts of the derivation are: (1) For the 15,000 MW wind scenario, a 30-minute change in net load, greater than the maximum 30-minute change for load alone, occurs approximately 24 times per year. The maximum 30-minute rise in net load is 4,502 MW for this wind generation capacity scenario, compared to 3,101 MW for load alone. (2) GE observed few impacts until 5,000 MW of wind were added, and (3) nearly all variation in the 30 minute period occurred within 10 minutes (Figure 3, Page 5 in the report). See also Page 15 of the GE report where it is recommended that ERCOT add new non-spin reserve service with a startup time of ten to fifteen minutes. 9 icfi.com

natural gas-fired generation as renewable generation displaces some conventional generation. Second, there is also an increased need for quick-start gas-fired plants to respond to rapid and/or unexpected fluctuations in the renewable output. Thus, on net, there is a 7 to 15 percent increase in the need for quick-start gas-fired capacity as a percentage of wind additions (see Table 3). Some or all of this capacity may already be present in an existing system but some may be need to be added. There could also be an increased requirement for commitment of peaking resources to respond to both forecast error and system regulation. Both of these outcomes will affect the need for and characteristics of natural gas supply to the system. However, under Scenario II, there is no need to add natural gas-fired plants to meet planning reserve margin requirements. This is because the addition of wind is assumed to occur in a system not expecting electricity demand growth in which there is already sufficient conventional capacity to meet the reserve margin requirements. In fact, because there would be a lower need for capacity counting toward reserve margin requirements equal to 10 to 20 percent of the wind capacity added, this may facilitate retirement of existing gas capacity. Scenario III Renewables eliminate forecast error outside utility context Scenario III is a case in which compensation for forward forecast error (e.g., day ahead, hour ahead, or ten minutes ahead) is the responsibility of wind generators active outside a utility system. (This also involves operating reserve capacity needs, higher unit commitment, and power plant quick-start requirements). The wind generators must exactly meet the forecast of wind supply. Thus, it is not a situation in which demand fluctuations may offset wind supply decreases. This could be because of regulatory, contractual, and/or physical conditions (e.g., a contractual requirement that wind generators address this issue combined with the lack of available peaking capacity to compensate for the forecast error). It should be noted that this situation is probably the least common among the three scenarios presented. The case of fully compensating for forward period wind forecast error is illustrated in Exhibit 2 above. 9 Note that the biggest concern is when wind delivers less than forecast since the difference must be met by other resources. The need for gas-fired generation when wind output is lower than expected is compelling for system operations compared to the opposite case of wind output exceeding the forecast. This is because, without viable storage options, wind could, in the extreme, be curtailed. In this scenario, wind generators could require commitment of operating reserve units with up to 25.8% of the renewable capacity and cause changes in the operation of the gas generating units. The reserve units could be existing gas-fired generators or gas-fired plants yet-to-be-built depending on the local conditions. Summary of scenario impacts Table 4 summarizes the potential implications for natural gas of increased variable renewable generation in the three scenarios: 9 This is discussed in the INGAA Report. See Appendix 4. The choice of the four hour period Scenario III was partly data-driven. Typical forward periods are 24 hours and 1 hour ahead. However, as variable renewable supply increases, the typical forward period could change. 10 icfi.com

Scenario I Long-term utility planning II Utility RPS planning III Elimination of forward forecast error by renewables Table 4. Incremental gas generation capacity requirements in response to wind capacity additions Three scenarios Incremental wind capacity (MW) Scenario I Switching from gas to renewables for the required new capacity results in a small reduction (10 to 20%) in the amount of new conventional gas capacity required. It also results in reduced gas generation due to displacement of gas by the renewable generation. On the other hand, it results in a increased requirement for peaking and quick-start capacity and greater commitment and dispatch of these units. Overall there is a net reduction in gas generation and consumption relative to the non-renewables case. Scenario II Adding renewables to the system in the absence of demand growth increases the need for peaking and quick-start capacity and results in increased unit commitment and dispatch for these units. The requirement for quick-start capacity would be in the range of 7 to 15% of the renewable capacity unless it was already in place. Again, there is a net reduction in gas generation and consumption due to displacement by the renewable generation. Scenario III The need to directly compensate for forecast error results in a requirement for peaking capacity equal to up to 25.8% of the renewable capacity. Gas capacity needed +800 640 to 720 MW (-80 to -160 MW) of gas needed of which 60 to 130 MW must be quick start 1 gas; quick-start requirement is incremental unless sufficient quick-start exists +800 +56 to +120 MW of quick-start gas capacity unless quick-start exists +800 +206 MW 25.8% Ratio of incremental gas capacity to wind Negative though composition of new gas generation capacity may change +7 to +15% unless quick-start gas capacity exists already 1 Quick-start is defined as gas-fired LM 6000, LMS100, reciprocating engines or other plants (e.g., hydro with storage) that can ramp up to 100% output from 0% output within ten minutes; conventional gas-fired peakers take 30 minutes to fully ramp with no output at 10 minutes. Gas-fired combined cycles take even longer: 2 or more hours to start contributing output without special modifications, gas-fired steam units take even longer, e.g., many hours. IV. Gas infrastructure implications The changes in the make-up and operation of the electric system require changes in the operation and requirements for gas supply infrastructure. Examples of changes to address the requirements include enhanced line pack, applications of new no-notice and gas storage services specifically designed for power generation, increasing the number of nomination cycles, and reducing the length of nomination cycles. There is already significant variability in daily gas use due to weather and other factors, including: Residential and commercial gas loads fluctuate significantly with changes in weather. Electric load also fluctuates with weather and by time of day, which in turn drives fluctuations in gas demand for power generation. Variability in loads from these sources will change as the amount of load changes over time. Projected impacts of renewable variation make up a relatively small portion of total gas load variability, but the variability associated with firming variable generation will grow as renewable capacity increases. While it will still remain a small 11 icfi.com

Plans must be made to account for the potential variability associated with gas generation used to firm variable renewable generation. This is less an issue of volumes and more an issue of operation, infrastructure, contracting, and cost recovery. part of total variability it can be locally significant for the facilities that serve a particular power generation facility or system. Plans must be made to account for the potential variability associated with gas generation used to firm variable renewable generation. This is less an issue of volumes and more an issue of operation, infrastructure, contracting, and cost recovery. An example of the impact of variable renewable integration on gas system requirements and operation is shown in Exhibit 5, a simplified example of a gas pipeline system which was analyzed using a dynamic flow model. The system includes a 16 inch gas mainline that serves a base load gas power plant and a gas-fired GE LMS100 ( quick start ) generator through two laterals. The power plants are connected to an electric system that is also served by an 800 MW wind facility. The graph in the lower right shows the gas demand of the base load power plant while the graph in the upper right hand side shows the operational profile of the LMS100 plant, both expressed in gas delivery units of million cubic fee per day (MMcfd). The profile of the peaking plant reflects the short-term supply perturbations from the wind generators. Two gas pipeline system configurations are modeled for the analysis, a Base System with a 10 inch lateral serving the peaking plant and an Enhanced Configuration with a 14 inch lateral serving the plant with greater gas pipeline line pack. 10 Hence, the Enhanced System has more rapid gas delivery capacity. Exhibit 6 shows the gas delivery profile for the two power plants and a base gas load of fixed demand. The black line is the average supply provided in the four standard gas nomination time periods. The blue area reflects the LMS100 operation. In hour 6, a decrease in wind output causes a spike in the use of the LMS100 plant, causing gas demand to reach up to nearly 180 MMcfd from average demand of slightly less than 100 MMcfd. Exhibit 7 shows the gas pressures in the system at the supply and at the LMS 100 along with the minimum gas pressure required for the plant to operate. In the Base System, the gas inlet pressure to the LMS 100 plant fluctuates significantly, Exhibit 5. Planning for load variability Dynamic flow modeling example for gas pipeline facilities The Base System Configuration assumes a 10 lateral to the firming power plant An Enhanced Configurataion assumes a 14 lateral Compressor initial discharge pressure 700 psia Mainline 83 miles, 16 pipeline MMcfd 60 40 20 0 Gas-fired power plant 2-block GE LMS100 200M Lateral 25 miles Wind capacity ~800MW Supply Fixed demand (total 83 MMcfd) Variable demand Other gas-fired power plant MMcfd 60 40 20 0 Source: Firming Renewable Electric Power Generators: Opportunities and Challenges for Natural Gas Pipelines, INGAA Foundation, 2011. 10 Line pack is the capacity to store additional gas in the pipeline by increasing the pressure. This increases the ability of the gas system to quickly deliver additional gas but requires advance notice in order to build up the line pack. 12 icfi.com

Exhibit 6. Gas supply and demand assumed in the dynamic flow modeling for the power plants applying standard 4 nominations windows MMcfd 180 160 140 120 100 80 60 40 20 0 0 2 4 6 8 10 12 14 16 18 20 22 Hour Fixed demand Firming power plant Conventional power plant Supply particularly when generation changes most. Critically, the pressure falls below the minimum acceptable operating pressure at the LMS1000 inlet when demand spikes. This can lead to a power plant trip or outage, especially if not expected. Line pack for this system ranges between 67 and 70 MMscf (Million standard cubic feet). Exhibit 8 shows the gas system pressures for the Enhanced System pipeline system configuration (i.e., with a 14 inch lateral). Line pack is about 3 MMscf greater throughout the projection and provides additional delivery capacity to maintain the required pressure at the peaking plant. Inlet pressure to the plant does not fluctuate nearly as much as in the Base Configuration. Critically, gas pressure does not fall below the minimum acceptable operating pressure at the firming plant inlet when firming demand spikes. Thus, not only does the increase in variable generation create new requirements on the power grid, e.g., more quick-start units. Gas supply infrastructure facilities must also be re-designed and sized appropriately to provide reliable gas transportation services to gas power plants used Exhibit 7. Dynamic flow modeling results for the base configuration (10 lateral) Psia 900 850 800 780 750 700 650 550 500 Pressure(psia) 0 2 4 6 8 10 12 14 16 18 20 22 Hour Minimum requirement at firming plant Supply Firming power plant MMscf 75 74 73 72 71 70 69 68 67 66 65 Line Pack (MMscf) 0 2 4 6 8 10 12 14 16 18 20 22 Hour 13 icfi.com

Exhibit 8. Dynamic flow modeling results for an enhanced configuration (14 lateral) Psia 900 850 800 780 750 700 650 550 500 Pressure(psia) 0 2 4 6 8 10 12 14 16 18 20 22 Hour Minimum requirement at firming plant Supply Firming power plant MMscf 75 74 73 72 71 70 69 68 67 66 65 Line Pack (MMscf) 0 2 4 6 8 10 12 14 16 18 20 22 Hour Scenario 2 (14 lateral) Scenario 1 (10 lateral) to meet highly variable loads. Compression must be adequate to support the varying demands and system operation must be responsive to these requirements. In addition, the types and adequacy of services and contractual options must be considered. Scenarios investigated in ICF s work did not identify any specific insurmountable technical challenges in creating a reliable power or gas delivery system for supporting variable generation. But, both the system operators and regulators must carefully consider the adequacy of existing gas transportation facilities to support reliable deliveries of gas to systems with variable generators. Hence, there is a potential gas-power integration issue. Integrating renewable generation will create challenges not just for the power grid, but also for natural gas infrastructure. Careful consideration of gas transportation facilities and services must be considered to create reliable gas deliveries for these purposes. The natural gas pipeline system has considerable operational flexibility for supplying natural gas reliably to firming generators at their required pressures. Nevertheless, at some locations in some regions, new facilities may need to be constructed to guarantee reliable on-demand gas service to support changing generator needs resulting from increased renewable generation. Gas transportation services that address these operational challenges may include enhanced line pack, applications of new no-notice and gas storage services, increasing the number of nomination cycles, and reducing the length of nomination cycles. The costs of providing these services will affect the cost of gas transportation for these applications. V. Conclusions Integrating variable electricity generation requires changes in the electric system. Some of these can be potentially large changes in planned generating capacity. The system must also be able to respond when electricity supply is different than expected. Thus, the system must respond quickly to short-term fluctuations in the renewable energy supply. This is addressed in part by a change in ten minute reserve requirements typically quick-start gas peakers. Some of the services are required in the absence of renewable generation, but the addition of renewable generation adds more and different requirements that may be met by existing or new generating facilities. The amount and type of new generating facilities that are required can vary widely depending on the existing generating mix, role of renewables in the local market, electric demand growth, regional transmission capacity and other factors. The requirement can range from zero to 80 to 90 percent of the renewable resource depending on these variables thus, selecting a value for analysis can be challenging. 14 icfi.com

icfi.com 2011 ICF International, Inc. All Rights Reserved. You may access the content of this white paper solely for your noncommercial use. You may download, print, or copy the white paper in segments or in its entirety, provided any copy retains all applicable copyright notices. All other rights, title, and interest to the white paper are expressly reserved by ICF International. No other permission is granted to you to print, copy, reproduce, distribute, transmit, upload, download, store, display in public, alter, or modify this article s content. For example, you may not republish any part of this article on or within a website, magazine, newsletter, newspaper, or online forum without the prior consent from the article s author(s). These changes in the make-up and operation of the electric system require changes in the gas supply infrastructure and its operation. These include enhanced line pack, applications of new no-notice and gas storage services, increasing the number of nomination cycles, and reducing the length of nomination cycles. They also include changes in local gas delivery infrastructure to accommodate these needs. There is already significant variability in daily gas use due to weather and other factors: (1) residential and commercial gas loads fluctuate significantly with changes in weather, (2) electric load also fluctuates with weather and by time of day, which in turn drives fluctuations in gas demand for power generation, and (3) variability in loads from these sources will change as the amount of load changes over time. Projected impacts of renewable generation variability make up a relatively small portion of total gas load variability, but the variability associated with responding to variable renewable generation will grow as renewable capacity increases. Although it will still remain a small part of total gas load variability, it can have a significant effect on local infrastructure and operational requirements. Overall, the issue is not total gas volume changes, but rather changes in operations and infrastructure and requirements. Plans must be made to account for the potential variability associated with gas generation used to support variable renewable generation. Changes in power infrastructure construction and operating costs will need to be recovered by generators. Similarly, changes in gas infrastructure construction and operating costs will need to be recovered by the natural gas pipelines. About ICF International Since 1969, ICF International (NASDAQ:ICFI) has been serving government at all levels, major corporations, and multilateral institutions. With more than 3,700 employees worldwide, we bring deep domain expertise, problem-solving capabilities, and a results-driven approach to deliver strategic value across the lifecycle of client programs. At ICF, we partner with clients to conceive and implement solutions and services that protect and improve the quality of life, providing lasting answers to society s most challenging management, technology, and policy issues. As a company and individually, we live this mission, as evidenced by our commitment to sustainability and carbon neutrality, contribution to the global community, and dedication to employee growth. For additional information: Power Judah Rose, Managing Director jrose@icfi.com Steven Fine, Vice President sfine@icfi.com Kenneth Collison, Vice President kcollison@icfi.com Natural Gas Joel Bluestein, Sr. Vice President jbluestein@icfi.com Kevin Petak, Vice President kpetak@icfi.com Bruce Henning, Vice President bhenning@icfi.com EET.WPR.0611.0237