Phase III: Natural Gas-Fired Electric Power Generation Infrastructure Analysis An Analysis of Pipeline Capacity Availability

Appendix

Gregory L. Peters President, EnVision Energy Solutions [email protected] 804.378.0770

1

Disclaimer: This report was prepared by Gregory L. Peters, President and Principal Consultant of EnVision Energy Solutions, for the benefit of the Midcontinent Independent Transmission System Operator (MISO). This work involves detailed analyses of interstate pipeline daily flow and capacity data; data obtained and compiled by Bentek Energy; and available public information from independent third parties. The appropriate professional diligence has been applied in the preparation of this analysis, using what is believed to be reasonable assumptions. However, since the report also necessarily involves assumptions regarding the future and the accuracy of the data, no warranty is made, expressed or implied.

EnVision Energy Solutions is the prime contractor and Bentek Energy is the subcontractor for this analysis.

2 Table of Contents

A1 MBA Methodology Details………………………………………………………………………………….6 A1.1 Summary of Pipeline Capacity Availability for Additional Gas-fired Generation....14 A2 Specific Pipeline Overview and Analyses……………………………………………………………18 A2.1 Alliance Pipeline, LP (Segment 1)……..……………………………………………………….…..….18 A2.2 ANR Pipeline Co. (Segments 2, 3, 4) …………..……………………………………………………..21 A2.3 CenterPoint (Enable) MRT (Segment 5)………………………………………………..……………26 A2.4 Great Lakes Transmission (Segment 6)……………………………………………………………….29 A2.5 Guardian Pipeline (Segment 7)...... 31 A2.6 Midwestern Gas Transmission (Segment 8)………….………………………………………..…..33 A2.7 Natural Gas Pipeline Co. of America (Segments 9 and 10)……………………..……….…..37 A2.8 Northern Border Pipeline Company (Segment 11)…………………..…………………….……42 A2.9 Northern Natural Gas Co. (Segment 12)………………….………………………….……………….45 A2.10 Panhandle Eastern Pipe Line Co (Segment 13)……………………………………………….……48 A2.11 Rockies Express Pipeline (Segment 14)……………..…………………………………………….….50 A2.12 Texas Gas Transmission (Segment 15)……………………………………..…………………….……53 A2.13 Trunkline Gas Company (Segment 16)…………………………………………………………….…..57 A2.14 Viking Gas Transmission (Segment 17)……………………………………………………………..…60 A2.15 WBI Energy Transmission (Segment 18)………………………………………..………………..…..62 A2.16 Contributions and Comments by the Natural Gas Industry and EPSA to the Phase I and II Analyses………………………………………………………………………………..……….65

List of Figures

Figure A2-1: Alliance System Map Figure A2-2: ANR Outage Map Pipeline Segments Figure A2-3: Power Plants on ANR Figure A2-4: CenterPoint (Enable) MRT System Map Figure A2-5: CenterPoint (Enable) MRT Inflows and Outflows Figure A2-6: CEGT MRT Receipts within MISO Figure A2-7: Great Lakes Gas Transmission System Map Figure A2-8: Guardian Pipeline Map Figure A2-9: Midwestern Pipeline System Map Figure A2-10: Midwestern Multiple Interconnection Flow Options

3 Figure A2-11: Midwestern Northbound and Southbound Flow Customers Figure A2-12: NGPL System System Map Figure A2-13: NGPL System Assets Map Figure A2-14: Northern Border System Capacity Map Figure A2-15: Northern Natural Gas System Map Figure A2-16: Northern Natural Line Constraints Figure A2-17: PEPL System Map Figure A2-18: REX Gas System Map Figure A2-19: Texas Gas Transmission System Map Figure A2-20: Texas Gas Transmission Capacity Flow Patterns Figure A2-21: Trunkline Gas Company System Map Figure A2-22: Trunkline Capacity Flow Patterns Figure A2-23: Viking System Map Figure A2-24: WBI Energy System Map Figure A2-25: Dakota Pipeline System Map

List of Tables

Table A1.1-1: MWs for CCs and CTs allocated to pipelines and LDCs Table A1.1-2: LDCs with Embedded Units and Requirements Allocation Table A1.1-3: Base Demand Case CC and CT Requirements by Pipeline Table A1.1-4: High Demand Case CC and CT Requirements by Pipeline Table A2-1: Alliance: Base Demand Case Days of Unavailable IT Capacity Table A2-2: Alliance: High Demand Case Days of Unavailable IT Capacity Table A2-3: ANR SE-C: Base Demand Case Days of Unavailable IT Capacity Table A2-4: ANR SE-C: High Demand Case Days of Unavailable IT Capacity Table A2-5: ANR N IL–WI: Base Demand Case Days of Unavailable IT Capacity Table A2-6: ANR N IL–WI: High Demand Case Days of Unavailable IT Capacity Table A2-7: ANR N IL-MI: Base Demand Case Days of Unavailable IT Capacity Table A2-8: ANR N IL-MI: High Demand Case Days of Unavailable IT Capacity Table A2-9: MRT: Base Demand Case Days of Unavailable IT Capacity Table A2-10: MRT: High Demand Case Days of Unavailable IT Capacity Table A2-11: GLGT: Base Demand Case Days of Unavailable IT Capacity Table A2-12: GLGT: High Demand Case Days of Unavailable IT Capacity Table A2-13: Guardian: Base Demand Case Days of Unavailable IT Capacity Table A2-14: Guardian: High Demand Case Days of Unavailable IT Capacity Table A2-15: Midwestern: Base Demand Case Days of Unavailable IT Capacity Table A2-16: Midwestern: High Demand Case Days of Unavailable IT Capacity Table A2-17: NGPL SE: Base Demand Case Days of Unavailable IT Capacity Table A2-18: NGPL SE: High Demand Case Days of Unavailable IT Capacity Table A2-19: NGPL Amarillo: Base Demand Case Days of Unavailable IT Capacity Table A2-20: NGPL Amarillo: High Demand Case Days of Unavailable IT Capacity Table A2-21: Northern Border Base Demand Case Days of Unavailable IT Capacity Table A2-22: Northern Border: High Demand Case Days of Unavailable IT Capacity Table A2-23: Northern Natural Base Demand Case Days of Unavailable IT Capacity

4 Table A2-24: Northern Natural High Demand Case Days of Unavailable IT Capacity Table A2-25: PEPL Base Demand Case Days of Unavailable IT Capacity Table A2-26: PEPL High Demand Case Days of Unavailable IT Capacity Table A2-27: REX Base Demand Case Days of Unavailable IT Capacity Table A2-28: REX High Demand Case Days of Unavailable IT Capacity Table A2-29: TGT Base Demand Case Days of Unavailable IT Capacity Table A2-30: TGT High Demand Case Days of Unavailable IT Capacity Table A2-31: Trunkline Base Demand Case Days of Unavailable IT Capacity Table A2-32: Trunkline High Demand Case Days of Unavailable IT Capacity Table A2-33: Viking Base Demand Case Days of Unavailable IT Capacity Table A2-34: Viking High Demand Case Days of Unavailable IT Capacity Table A2-35: WBI Base Demand Case Days of Unavailable IT Capacity Table A2-36: WBI High Demand Case Days of Unavailable IT Capacity

5 A1 MBA Methodology Details

The details of MISO and Bentek methodologies are explained in the main body of the Report. Explained below are the details of how the Modified Backcast Analysis (MBA) allocated MWs for combined cycle units (CCs) and combustion turbine units (CTs) to pipelines and LDCs and how these MWs gas requirements were allocated to the pipelines in the Base and High Demand Case CC and CT gas Cases.

The Phase III MBA uses the same methodology as Phase I and II to simulate the impact on pipeline capacity of embedded generation and incremental generation requirements. MISO, through the use of its models, provided the inputs to determine individual unit fuel burns that were applied to historical pipeline flow data. This determines adequacy of natural gas infrastructure to serve projected demand on a pipeline-by-pipeline basis. The MBA is a screening analysis of the pipelines’ main line capacity into their market areas in the MISO region. This is a high-level “screening” analysis or “snapshot” of MISO-region pipelines’ main line capacity based on publically-available data at major interconnections into each pipeline’s market area and is intended to serve as an indicator of capacity availability into the pipelines’ MISO market areas. This Analysis tests the impact of increased natural gas demand on actual historic pipeline flowing volumes and capacity requirements due to a potential 12.6 GW (12K scenario) of coal-to-gas conversions operating at expected and maximum capacity factors. This Analysis is not intended to be a detailed market-area engineering analysis that uses sophisticated flow modeling and other types of transient flow analyses that analyzes each detailed market area pipeline segment’s operational inter- dependencies down to the detailed pipe sizes and pressures at the power plant delivery point levels as it would require access to the pipelines’ proprietary data and information. From a modeling perspective, the Analyses are based on what may be more accurately described as a “Modified-Backcast Scenario Technique” analytical approach based the pipelines’ forward-haul main line capacity using location-specific actual historical flow data into the MISO region.

6 The benefits of the MBA Approach also include:

 Reveals the number of days in which pipeline capacity would have been insufficient without year-round firm transportation arrangements for the gas pipeline capacity requirements.

 Identifies seasonal pipeline throughput trends to determine impacts of shifts in macroeconomic variables such as supply location, demands, etc.

 Establishes a baseline to provide insight to changes in pipeline flow patterns impacted by macroeconomic variables.

 Provides perspective on the relative strengths of one pipeline to another based on competition, new entrants and sourcing shifts.

 Reveals how similarly-situated pipelines’ throughput changes due to such factors as changing capacity from competing pipelines.

 Uses actual nomination flow data from each respective pipeline’s electronic bulletin board or “EBB” data and historical actual maximum flowing capacity data as compiled by Bentek Energy.

 Application of real-life data and experiences over an extended period 2005 -2013 to evaluate impacts and determine insights to pipelines supply and demand

dynamics.

This Analysis applied MISO’ s gas delivery requirements for the period 2013-2032 for existing units and the incremental, forecasted gas-fired requirements under 12,000 MW coal-to-gas retirement scenarios. The embedded requirements and the incremental 12,000 MW requirements were converted to Dekatherm gas requirements and applied to historic actual flows and compared to the respective pipeline’s daily maximum flow design capabilities.

This application was the method used to determine, on a daily basis, the number of days in which capacity would have been insufficient to deliver natural gas requirements for each pipeline for each day in the period March 1, 2005 through March 31, 2013. The daily data from each respective pipeline’s electronic bulletin board and historical actual maximum flowing

7 capacity data was compiled by Bentek Energy. If the embedded CTs’ and CCs’ maximum gas requirement quantities, in both the Base Demand Scenario and the High Demand Scenario, exceeded the respective pipelines’ daily maximum flow design capabilities, that day was deemed to be a day of “insufficient capacity”.

Capacity factors for both the Base Demand and the High Demand Scenario were determined through the MISO models as explained in the Report. The conversion factors to change from MWh to Dth are consistent with those used in the Phase I and II Infrastructure Analyses. These capacity factors were used to determine fuel requirements for existing and incremental CCs and CTs. Based on the assumptions set forth in the Phase II Study, the same MWh to Dth conversion factors were used to obtain the natural gas requirements for the embedded and incremental

CCs and CTs in the Phase III analysis.

The MWh requirements are identified below in Table A1.1-1 that shows the rated MW for existing CCs and CTs to which the Capacity Factors were applied and the respective pipeline or LDC that delivers natural gas.

Overall, pipeline capacity into the MISO Midwest is positive and continually improving due to shale gas developments and accommodating pipeline expansions, contract expirations and the benefits of increased pipeline reticulation underway in the Eastern Interconnect.

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Table A1.1-1: MWs for CCs and CTs allocated to pipelines and LDCs

9 The MISO embedded units include generation downstream of the pipelines’ citygates for three LDCs. For the LDCs, a detailed review of the respective pipelines’ Index of Customers (“IOC”) was performed to determine the delivering pipelines to Consumers Energy Co. (“Consumers”), Michigan Consolidated Gas Co. (“MichCon”) and Northern Indiana Public Service Co. (“NIPSCO”). Each LDC’s full requirements, firm transportation maximum daily transportation quantity (“MDTQ or MDQ”), was determined and the percentage of each was calculated. These percentages were applied to each LDC’s embedded units’ gas requirements and added to each respective upstream pipeline’s respective CT and/or CC requirements.

The firm transportation percentages that were applied to the MISO-provided CC and CT capacity requirements are shown below in Table A1.1-2.

Table A1.1-2: LDCs with Embedded Units and Requirements Allocation

The allocated LDC volumes were added to the converted MWH to DTH per day to determine the total daily gas delivery requirements for each pipeline to the embedded facilities.

10 Each pipeline’s CT capacity requirements and CC capacity requirements were analyzed separately as well as from a combined daily requirements perspective.

Tables A1.1-3 (Base Demand Case) and A1.1-4 (High Demand Case) are the starting points to calculate the daily natural gas requirements on each pipeline for the existing embedded and incremental facilities. The conversion factors are consistent with the “Phase I and II Infrastructure Analysis”. Based on the assumptions set forth in the “Infrastructure Analysis,” the same MW to DTH conversion factors were used to obtain the natural gas requirements for the embedded and incremental CCs and CTs in this Analysis.

Tables A1.1-3 and A1.1-4 show the natural gas requirement allocations, which include LDC allocations to their upstream pipelines for the respective pipelines for the Base Demand and High Demand Cases for the CTs and CCs.

Finally, the 12K incremental gas requirements for the forecasted period were added to the embedded requirements to obtain the total daily requirements for each pipeline. These requirements where backcasted against the actual historic nominated flow volumes at the measurement locations and compared to the maximum flowing pipeline capacity on each pipeline. If the total requirements exceeded the maximum flowing pipeline capacity on any given day, that day was deemed to have insufficient capacity.

Over the past two years, new shale gas supplies across the US have brought about significant infrastructure expansion that has positively impacted pipeline flow patterns and capacity availability throughout North America. It is becoming increasingly clear that the traditional ways of viewing capacity availability from a forward-haul perspective have been significantly altered by the revolutionary impact of the new shale supply paradigm shift.

The forward-haul based MBA has become less relevant as an indicator of the true “net” capacity availability on the interstate pipelines. Nonetheless, there is tremendous value and benefits in using the MBA as outlined in the Phase III Report and also above.

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Table A1.1-3: Base Demand Case CC and CT Requirements by Pipeline

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Table A1.1-4: High Demand Case: CC and CT Requirements by Pipeline

13 A1.1 Summary of Pipeline Capacity Availability for Additional Gas- fired Generation

The following summarizes the detailed analyses to determine how much electric generation can be built and supported based on defined locations provided by MISO and on the other pipelines in the MISO region that were not specifically selected by MISO. With the lateral upgrades, according to the MISO- surveyed pipelines sufficient capacity will be available to serve the MISO-identified facilities with the exception of Williston Basin Interstate Pipeline (WBIP) and Northern Border Pipeline. Northern Border would require substantial mainline improvements to assure firm transportation deliveries to WBIP for incremental units and also for incremental units on Northern Border. The MBA results indicate a trend toward enhanced mainline capacity on the majority of the MISO-region pipelines. There are 21 interstate pipeline companies in the MISO Midwest region. Of these 21 companies, 15 companies had MISO-identified combined cycle (CCs) or combustion turbines (CTs), existing or “embedded” and/or incremental that were analyzed with the MBA methodology. Of the 15 companies, ANR and NGPL were analyzed as 3 and 2 mainline segments, for a total of 18 pipeline “segments”. Of the 18 pipeline segments, Alliance, Northern Border and Northern Natural appear to have forward-haul capacity deficiencies at this time based on the locations of the projected units as explained herein. These companies, however, are undergoing positive changes in current capacity availability due to announced expansions, contract expirations and the benefits of increased reticulation underway in the MISO Midwest region. The MBA concludes that 15 of the 18 major interstate pipelines segments or 17 of the 211 interstate pipelines in the Midwest appear to have sufficient capacity to handle the needs of existing and forecasted CTs and CCs, if these units operate at expected capacity factors and are

1 KO Gas Transmission is not a major system. It is however under FERC jurisdiction because it crosses from Kentucky to Ohio and is fully subscribed. Alliance, Northern Border and the upper branches of NNG are the more important pipelines impacting MISO that have capacity sufficiency concerns. However, as explained in the individual company overviews, concerns for Alliance may be short-term contract oriented but also there are wet- gas conversion to dry gas quality concerns or, for Northern Border, the concern is whether or not changing MISO area pipeline flows that can provide displacement options to relieve capacity limitations. Lastly, NNG’s “upper branches” in north/east Iowa and southwest Minnesota, however will require infrastructure build out as identified in the areas in the NNG overview herein. 14 positively trending towards having additional capacity. The Phase III projects a continuation of increasing access to capacity on the majority of major interstate pipelines in the MISO Midwest footprint.

Also listed below are 5 other interstate companies and 2 intrastate companies that do not have MISO-identified units but which were analyzed to determine if they could support additional power generation requirements.

The bolded pipelines have “MISO-identified” power generation plants or “units”.

Interstate Pipelines

1. Alliance does not appear to have enough excess forward capacity to support the incremental unit requirements without costly facility upgrades to support firm transportation at this time. Alliance is a “wet” system transporting NGLs to the Aux Sable facility in Illinois. This is undesirable and costly because of the high NGL content that must be removed to comply with the operating specifications, requirements and warranty conditions of gas turbine manufacturers. The NGL to dry gas “frac” spread may be a reason for available capacity, on a dry basis. This issue needs further exploration with Alliance.

2. 2.1 ANR SE Central can support all the MISO identified units and has incremental capacity for possible 3 additional units even without firm capacity

2.2 ANR N IL – WI can support the units in its service locations because of how ANR operates its pipeline and storage in a reticulated manner.

2.3 ANR N L – MI can support the units in its service locations because of how ANR operates it pipeline and storage in a reticulated manner.

3. Centerpoint (Enable) MRT has sufficient capacity to support the MISO units identified, however (and positively) the impact of flow changes into MISO described in the Report need to be further explored with MRT due to westerly Appalachian Basin flows.

4. Great Lakes Gas Transmission has sufficient capacity to support the MISO units identified.

5. Guardian has sufficient capacity in the summer (over 500,000/d extra) and limited days of capacity in the winter for an 86,000 Dth/d CC facility or 2 CTs.

6. Midwestern on average has over 200,000 Dth/d of extra capacity in the summer and most days considerable more to be able to serve at least 3 summer CTs, if upstream supply is deliverable has.

15

7. 7.1 NGPL – Amarillo has had sufficient capacity since late 2009 when REX moved to full capacity.

7.2 NGPL Gulf Coast has sufficient capacity to support the MISO units and can operate its reticulated system in ways to support additional units through various combinations of storage, forward-haul and back-haul operations.

8. Northern Natural Gas has sufficient firm capacity for the CC unit near Des Moines, Iowa, just east of the measurement location at the Nebraska/Iowa border. Like NGPL Amarillo and PEPL, NNG mainline capacity has opened since REX began operation. However, on the branch systems where two units were identified to be located, it would require mainline upgrades to guarantee firm deliveries, according to NNG.

9. Northern Border does not have any excess capacity to support the MISO-identified units. It cannot deliver to WBIP without significant capacity additions. Even with the lateral upgrades, substantial mainline upgrades would be required to assure firm transportation deliveries. Additionally, Northern Border would require major mainline upgrades to be able to deliver to WBI Energy.

10. Panhandle (PEPL) has sufficient capacity. PEPL was impacted by REX “free” up large amounts of capacity.

11. Rockies Express (REX) has sufficient capacity to support additional power generation.

12. Texas Gas has sufficient capacity possibly 3 additional summer operating CTs with limited interruptions.

13. Trunkline has sufficient capacity to support additional power generation.

14. Viking has sufficient capacity to support additional power generation.

15. WBI Energy previously has stated that it does not have sufficient capacity for incremental generation without major upgrades. However, it is expected construct additional mainline capacity capabilities to be able to take delivery of future supply developments behind Bison and from Bakken shale gas developments.

Interstate Pipelines that were not included in the Phase 3 analysis but were analyzed:

16. Bison has an average of about 100,000 Dth/d of extra capacity for 2 CTs or 1 CC. Bison began operations in late 2010.

17. Crossroads has sufficient capacity is available from its upstream pipelines.

16 18. KO Gas Transmission is not a major system but a small line that crosses the Ohio River from Kentucky to Ohio. It is under FERC jurisdiction and is fully subscribed.

19. Southern Star has extra capacity and on most days, has considerable capacity available to serve additional units and to support deliveries into the MISO region.

20. TETCO was analyzed in the Phase I and II Studies and TETCO has experienced a positive and dramatic change in capacity availability due to Appalachian shale gas developments. TETCO is changing various operations to move gas bilaterally, and creative displacement and backhaul opportunities are developing to provide significant capacity into the MISO region.

21. Vector also has sufficient capacity for additional units and power generators can benefit from backhaul and displacement options.

Intrastate Pipelines that were not included in the Phase 3 analysis but were analyzed:

22. Horizon has sufficient capacity and it can benefit power generators with backhaul and other displacement options.

23. KM Illinois has over 150,000 Dth/d extra capacity, year-round if upstream pipelines have supply delivery capability; KM could handle 2 CCs or 3 CTs.

It is important to recognize that future available capacity on each pipeline is determined on a case-by-case basis. Changing shipper requirements and the flexibility to alternatively sourced, economically delivered gas supplies may frequently alter the future capacity profile. For example, one or the most interesting observations about Midwestern is and REX will be more so, functioning as longitudinal and latitudinal header systems, respectively albeit REX as so on a much larger scale. REX is and will further be functioning as the major latitudinal head in MISO Midwest. This demonstrates how, in combination, these types of reticulations open tremendous capacity options in the MISO footprint. The majority of the pipelines that were analyzed has sufficient capacity and is trending towards increased capacity. Below are the overviews of the specific pipelines analyzed. On the pipeline maps are the circled locations of where capacity and flow data were measured for the inputs to the MBA. Firm Transportation in the pipeline overviews below may use the acronym FT or FTS or similar. Interruptible Transportation is designated as IT or ITS or similar.

17 A2 Specific Pipeline Overview and Analyses

A2.1 Alliance Pipeline, LP (Segment 1)

The Alliance Pipeline system consists of 3,719-kilometre (2,311-mile) integrated Canadian and U.S. high-pressure natural gas transmission pipeline system, delivering rich natural gas from the Western Canadian Sedimentary Basin and the Williston Basin to the Chicago market hub. The United States portion of the system consists of approximately 900 miles of mainline and related infrastructure. The system has been in commercial service since December 2000 and delivers, on average, about 1.6 billion standard cubic feet (or 45.3 million standard cubic meters) of natural gas per day.

Alliance Pipeline System

Alliance Canada Canadian Border

Figure A2-1: Alliance System Map

Alliance is a high Btu “wet” system to Joliet, IL that requires processing and sharing of royalties with Canadian producers. It would require to installation of processing facilities from the pipeline gas stream into its component parts such as propane, ethane, butane, et al. before

18 pipeline & LDC gas quality standards are met to the power plant. The ability to blend a high Btu stream at the city-gate is not generally achievable without great cost, before burner tip deliveries. In addition, arrangements to ship and haul off the by-products renders distributed processing plants as uneconomic for power producers at this time. It appears at this time, that Alliance is at or near capacity based on current contract requirements at least until 2015 when contract renewal/expiration become an issue. As shown below (Tables A2-1 and A2-2) there is a trend towards reduced available non-firm capacity with the incremental power generation future requirements. However, capacity availability above the 1.932 Bcf/d historic maximum flow capacity used in the analysis may be possible based on the Tioga Lateral project which will provide incremental gas supply from the Bakken Shale region of the Williston Basin into Alliance thereby utilizing some of the latent capacity that Alliance has available on the US portion of its infrastructure. Additionally Alliance has an existing opportunity to increase its mainline transportation capacity through the addition of mainline compression. Originally Alliance was constructed with mainline compressor spacing of 120 miles. However Alliance had the foresight to install mainline block valves and secure land holdings to reduce their mainline compressor spacing to 60 miles. The throughput capacity of the Alliance system could be increased by approximately 0.5 Bcf/d through the installation of these compressor stations therefore increasing their ability to further attract incremental supply either from Canada’s Western Canadian Sedimentary Basin (WCSB) or more importantly forecast development of North Dakota’s Bakken associated natural gas resource.

As referenced above, Alliance is re-contracting its system by transitioning from a single-service, single-toll, pipeline system to one offering customers a suite of transportation services and contract tenures to the Chicago market. Alliance is offering capacity on its system for natural gas transportation services effective December 1, 2015. Customers can express interest in shipping on the Alliance system starting August 15, 2013 through a Precedent Agreement process.

The maximum flowing capacity used was 1.932 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not available.

19

Alliance has no embedded demand and 55,627 Dth/d one incremental CC unit Table A2-1: Alliance: Base Demand Case Days of Unavailable IT Capacity

Alliance has no embedded demand and 86,303 Dth/d from one incremental CC unit Table A2-2: Alliance: High Demand Case Days of Unavailable IT Capacity

20 A2.2 ANR Pipeline Co. (Segments 2, 3, 4)

ANR is a multi-segment system and is unique compared to the other long-line mainline systems serving the MISO region because its multiple segments must be evaluated, for capacity purposes from the (1) Southeast Central or Gulf Coast segment into western Ohio and southeast Michigan; (2) a Southwest Central segment, that joins the Northern Segment in Illinois to Wisconsin; and (3) the Northern Segment east of Chicago through Illinois into the Lower Peninsula of Michigan.

Traditional pipeline constraint points are changing or being eliminated based on currently nominated routes. Long haul transactions supplying gas from the Gulf of Mexico and West Texas are being replaced with shorter haul transactions from the Midwest. Excess supply in the Midwest is finding markets in ANR’s southern markets. Injection and withdrawal activity related to storage transactions has changed with new shale plays and seasonal pricing differences. Reticulated pipelines are more complicated when looking for capacity due to the many supply to market route potentials that can be nominated. The ANR system consists of two major mainline pipelines from the south with each connecting to market area facilities stretching from northern Michigan to Wisconsin. The northern Michigan facilities are connected to ANR’s significant storage position where it owns and operates approximately 250 Bcf of gas. Gas displacement, backhauls, longhauls, shorthauls and storage activity across these ANR facilities have all changed as a result of new gas supplies in the market area and how that supply is routed to get to market. Reticulated pipelines with significant facilities and capabilities like ANR’s are by their nature more complex to operate, but can provide electric generation with the capacity and flexibility required to be reliable into the future. A reticulated pipeline like ANR that has access to most every major supply basin and can physically flow gas in different directions has always had pockets of available capacity to sell its customers. These pockets of capacity may not have always been strategically located for supply to get to the market especially at the right price. However, the new shale gas supplies and resulting changes in historical flows have opened new routes of available capacity and at an attractive price.

21 ANR Outage Map

ANR North Illinois/Wisconsin Border Inter-MISO Flow

ANR East Illinois/Michigan Border Inter-MISO Flow

ANR SE Central Kentucky Border

Figure A2-2: ANR Outage Map Pipeline Segments

Power Plants on the ANR System

Legend: POWER PLANT LOCATION SUMMARY

ANR Great Lakes W. Marinette Plant Compressor Station Weston Plant

Power Plant Fox Energy & City of Kaukauna De Pere Plant & MI Pulliam Plant WI Manitowoc Plant

MO Weakley Menasha Plant Sheboygan Falls Greenwood Plant CountyTN Plant (Neenah) Hartford East Brownsville Fond du Lac Plant Central Plant Germantown AR Holland Plant Plant

Panola Plant Kegonsa Plant Rochester Plant GA (Concord) Zeeland Plant MS AL Edgerton Plant Covert Plant Troy Power LLC LA Kenosha

TX Plant (Paris) Tiffany/Tiffany East FL Napoleon Plant Acadia Plant & N. Beloit Plant IO Monee Plant Teche Plant Mone Plant (Convoy

Minooka Plant & PPL University Park Crete Plant IN OH Plant Lebanon/Tait Plant Burlington Plant Cadiz Plant

Keokuk Plant IL Lawrence Bedison Plant (Hoosier) MO Figure A2-3: Power Plants on ANR

22 ANR SE-C (Segment 2) The maximum flowing capacity used for the Southeast Central line was 1.419 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

ANR SE-C has 12,647 Dth/d CT embedded demand and 41,558 Dth/d from one incremental CT Table A2-3: ANR SE-C: Base Demand Case Days of Unavailable IT Capacity

ANR SE-C has 28,212 Dth/d CT embedded and 60,640 Dth/d from one incremental CT Table A2-4: ANR SE-C: High Demand Case Days of Unavailable IT Capacity

23 ANR N: Il-WI segment (Segment 2) The maximum flowing capacity used for the ANR N: Il-WI segment was .713 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

ANR N IL – WI has embedded demands of 284,186 dth/d CC and 32,115 dth/d CT and incremental demands of 124,674 Dth/d from 3CTs and 55,627 Dth/d 1 CC. Table A2-5: ANR N IL–WI: Base Demand Case Days of Unavailable IT Capacity

ANR N IL – WI has 381,169 dth/d CC and 40,500 dth/d CT and embedded and has 4 CTs with 242,560 Dth/d of incremental demand Table A2-6: ANR N IL–WI: High Demand Case Days of Unavailable IT Capacity

24 ANR N IL-MI (Segment 3) The maximum flowing capacity used for the ANR N IL-MI line was 1.338 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

ANR N – IL-MI has 256,077 Dth/d CC and 15,651 Dth/d CT embedded demands and 55,627 Dth/d from one incremental CC Table A2-7: ANR N IL-MI: Base Demand Case Days of Unavailable IT Capacity

ANR N – IL-MI has 445,705 Dth/d CC and 15,445 Dth/d CT embedded demands and 60,640 Dth/d from one incremental CT Table A2-8: ANR N IL-MI: Days of Unavailable IT Capacity

25 A2.3 CenterPoint (Enable) Mississippi River Transmission Corporation (MRT) (Segment 5)

Mississippi River transmission (MRT) is one of two indirect, wholly-owned interstate pipeline subsidiaries of CenterPoint Energy, Inc. MRT and CenterPoint Energy Gas Transmission (CEGT) operate more than 8,000 miles of interstate pipe located in Arkansas, Illinois, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas, as well as six storage facilities. In May 2013, CenterPoint Energy combined its midstream assets with the former Enogex to form Enable Midstream Partners, with operations in major natural gas and liquids-rich producing areas of Oklahoma, Texas, Arkansas and Louisiana. CenterPoint Energy owns a 58.3 percent limited partner interest in Enable Midstream, which it controls jointly with OGE Energy Corp. CenterPointCenterPoint– MRT –& MRTCEGT & SystemCEGT Map

MRT Illinois/Missouri Border

Figure A2-4: CenterPoint (Enable) MRT System Map

The maximum flowing capacity used for the Southeast Central line was .234 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

26

MRT has 14,632 Dth/d embedded and no incremental demands Table A2-9: MRT: Base Demand Case Days of Unavailable IT Capacity

MRT has 27,612 Dth/d embedded CT and 60,640 Dth/d demand from one incremental CT Table A2-10: MRT: High Demand Case Days of Unavailable IT Capacity

27

Figure A2-5: CenterPoint (Enable) MRT Inflows and Outflows

Figure A2-6: CEGT MRT Receipts within MISO South

28 A2.4 Great Lakes Transmission (Segment 6)

The increase in new supply in the Midwest from shale gas has had an impact on straight line pipelines like Great Lakes which historically has transported Canadian supply to markets in the Midwest and back to eastern Canada. Great Lakes and now finds itself having a bi-directional pipeline throughout the year, the impact of the new supply to a reticulated pipeline has been just as significant.

Great Lakes Gas Transmission System

Great Lakes Canadian Border

Figure A2-7: Great Lakes Gas Transmission System Map

The maximum flowing capacity used for the Southeast Central line was 2.237 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

29

Great Lakes has 6,463 Dth/d CT embedded demand and incremental demand from 2 CTs (83,116 Dth/d) and 2 CCs (111,254 Dth/d) Table A2-11: GLGT: Base Demand Case Days of Unavailable IT Capacity

Great Lakes has 11,639 Dth/d CT embedded demands and Incremental demand of 181,920 Dth/d from 3 CTs Table A2-12: GLGT: High Demand Case Days of Unavailable IT Capacity

30 A2.5 Guardian Pipeline (Guardian) (Segment 7)

Guardian receives supply from Northern Border, Midwestern, NGPL, ANR North: Illinois- Wisconsin segment, Alliance and Vector pipelines. Guardian Pipeline originates from the Chicago Hub, near Joliet, Illinois, and extends to Green Bay, Wisconsin. The pipeline has approximately 252 miles of 36, 30, & 20 inch mainline, 100,225 HP of compression and 18 meter stations. The current design capacity of Guardian Pipeline, L.L.C. is 1,287,000 Dth/day. Guardian accesses all major North American supply basins, multiple upstream firm transportation providers and multiple providers of storage and related services. Guardian has about 97,000 Dth/d (GI) and 40,000 Dth/d (GII) of available capacity and also about 30,000 Dth/d on the Northeast Extension.

Guardian Pipeline System Map

Guardian Illinois/Wisconsin State Border

Figure A2-8: Guardian Pipeline Map

For Guardian to be fully bi-directional (without CAPEX investments), they will need firm year- round gas & FTS (firm) sourcing from the north into Green Bay, WI before duplicating Midwestern which is sourced by Chicago and Portland, TN at the end points.

31 The maximum flowing capacity used was 1.287 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

Guardian has 4,670 Dth/d CC and 865 Dth/d CT embedded demand and no incremental units Table A2-13: Guardian: Base Demand Case Days of Unavailable IT Capacity

Guardian has 7,149 Dth/d CC and 1,275 Dth/d CT embedded demands and no incremental Table A2-14: Guardian: High Demand Case Days of Unavailable IT Capacity

32 A2.6 Midwestern Gas Transmission (MGT) (Segment 8)

Midwestern connects to other major interstate pipeline systems including Guardian Pipeline, Rockies Express Pipeline, Texas Eastern Transmission, ANR, Columbia Gulf Transmission, Natural Gas Pipeline, Panhandle Eastern Pipeline, East Tennessee, Alliance Pipeline, Northern Border Pipeline, Tennessee Gas Pipeline, Trunkline, and Texas Gas Transmission to provide bi- directional service to markets in Tennessee, Kentucky, Indiana, southern Illinois, as well as the growing Joliet/Chicago market hub.

Midwestern Gas Transmission System Map

Midwestern Kentucky Border

Figure A2-9: Midwestern Pipeline Map

33

Figure A2-10: Midwestern Multiple Interconnection Flow Options2

Midwestern’s multiple interconnections with other pipelines provide a tremendous amount of flow flexibility for shippers. This flexibility is partly what allows Midwestern to function as a bi- directional system. This bi-directionality is noted by the Northbound and Southbound customers identified below in Figure A2-11, According to MGT they have approximately 265,000 Dth/d of available Southbound capacity and approximately 89,000 Dth/d Northbound from the southern interconnect (Portland) northward to Scotland which is about ¾ of the way northward on their system. One or the most interesting observations about Midwestern is that is functioning as a longitudinal header system just as REX (albeit on a larger scale) is and will further be functioning as the major latitudinal header. In combination, this type of multiple-pipeline flow combinations and possibilities are opening tremendous capacity options in the MISO footprint.

2 Source: Midwestern website. 34

Figure A2-11: Midwestern Northbound and Southbound Flow Customers3

The maximum flowing capacity used was .996 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

Midwestern has 30,500 Dth/d CC embedded demand and no incremental demands Table A2-15: Midwestern: Base Demand Case Days of Unavailable IT Capacity

3 Source: Midwestern website. 35

Midwestern has 84,423 Dth/d CC embedded and no incremental demands Table A2-16: Midwestern: High Demand Case Days of Unavailable IT Capacity

36 A2.7 Natural Gas Pipeline Co. of America (NGLP) (Segments 9 and 10)

NGPL is a major interstate transporter of natural gas and provider of natural gas storage Naturalservices. With over Gas 10,000 miles Pipeline of pipelines and over of 280 billionAmerica cubic feet of working (NGPL) gas storage capacity, NGPL’s system transportsSystem gas from major Map United States and Canadian producing areas to Midwest markets as well as other pipelines serving the US.

NGPL Amarillo Iowa/Nebraska Border

NGPL SE Illinois/Missouri Border

Figure A2-12: NGPL System Map

NGPL is not just two long haul pipelines (Amarillo and Gulf Coast); NGPL’s pipeline system is capable of moving natural gas in multiple directions, in addition to its traditional long haul forward capacities reflected in the current report. The MBA forward-haul perspective does not completely reflect this reality, and does not account for ways in which NGPL would provide firm transportation, storage and line pack services. Besides NGPL’s mainline forward haul

37 capacities, NGPL’s significant market area storage deliverability should be noted. This enables NGPL to provide reliable, flexible, late and/or no-notice services traditionally required by CC and CT generation plants. Additionally, NGPL has access to significant market area supplies due to its numerous interconnects with other interstate pipelines which further enhances its capacity, reliability and deliverability. NGPL has the capability, through its extensive market area pipeline network, to physically move supply from the Amarillo system and backhaul that supply onto the Gulf Coast system. Likewise, supply from the Gulf Coast System can be physically backhauled onto the Amarillo system providing reliable and diverse supply sourcing. Additionally, NGPL may also provide backhauls via displacement, using no capacity. Also, it should be taken into account the full capability of NGPL’s capacity on the Amarillo mainline in Segment 14 of 1,677,000 Dth/d, and the full deliverability from NGPL’s storage fields of 1,700,000 Dth/d. NGPL deliverability in Chicago is the sum of the Amarillo mainline of 1.677 Bcf/day PLUS Gulf Coast mainline of 1.6 Bcf/d plus storage deliverability with dedicated pipe capacity of 1.7 bcf/day.

In total, NGPL has 5.0 Bcf/d of “traditional” capacity in NGPL’s market area to serve the Midwest market geographically centered around Chicago. To serve power generators, NGPL has the flexibility to source supply from traditional long haul supply basins and market area storage deliverability. In addition to providing over 5.0 Bcf of traditional capacity, Natural can source supply in the market area from Northern Border, Alliance, ANR, Midwestern, REX, Nicor and to further enhance deliverability through short distance forward hauls, physical backhauls and backhauls through displacement. These types of hauls typically use little or no additional capacity. The REX interconnect will provide access to Marcellus/Utica supplies that REX can provide through displacement or if they physically turn their system around to flow from east to west in the future. The significant amount of reticulated pipe, like ANR and NGPL in the MISO Market area allows both and others to utilize line pack to provide additional swing services to power generators by allowing them to pack and draft over short periods providing them the intraday flexibility needed to meet the immediate needs of peaking generation units.

38

Figure A2-13: NGPL System Assets Map4 Appalachian production growth is encouraging infrastructure build-out is recent action by Kinder Morgan Partners and MarkWest. The two have recently signed a letter of intent to form a midstream joint venture to pursue two important projects to support producers in the Utica and Marcellus shales in Ohio, Pennsylvania and West Virginia. The projects would include development of a 400 MMcf/d cryogenic processing complex in Ohio and an initial 200,000 barrels-per-day NGL pipeline that would transport product from Ohio to Gulf Coast fractionation facilities. Obviously, final commitment to build these projects is contingent on adequate customer commitments and regulatory approval. Based on operational unsubscribed capacity information provided by NGPL and the analyses, NGPL has more than enough available capacity to serve the delivery requirements of the 3 CTs and 1 CC identified by the MISO and the MBA results do not completely reflect the above operational information provided by NGPL and in the Bentek analysis. The MBA measurement points for the NGPL segments below are at the Amarillo Mainline Station 109 and NGPL Gulf Coast (SE) Mainline at the Illinois/Missouri Border.

4 Source: NGPL. 39 NGPL Gulf Coast Line (S. East) (Segment 9) The trending lines below does not adequately reflect to operational capacity as explained above within the NGPL market area where the embedded and incremental units are located when measured from a forward-haul perspective. The maximum flowing capacity used was 1.8 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

NGPL SE has 41,684 Dth/d CC and 23,274 Dth/d CT embedded demands and 23,274 Dth/d incremental CT demand Table A2-17: NGPL SE: Base Demand Case Days of Unavailable IT Capacity

NGPL SE has 98,780 Dth/d CC and 30,914 Dth/d CT embedded demands and 60,640 Dth/d incremental CT demand Table A2-18: NGPL SE: High Demand Case Days of Unavailable IT Capacity

40 NGPL – Amarillo Line (Segment 10)

The maximum flowing capacity used for the Amarillo line was 1.677 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

NGPL Amarillo has 71,901 Dth/d embedded CC and 1,561 Dth/d CT and 55,627 Dth/d incremental CC demand Table A2-19: NGPL Amarillo Base Demand Case Days of Unavailable IT Capacity

NGPL Amarillo has 163,743 Dth/d embedded CC and 1,410 Dth/d CT and 60,640 Dth/d incremental CT demand Table A2-20: NGPL Amarillo: High Demand Case Days of Unavailable IT Capacity

41 A2.8 Northern Border Pipeline Company (NBP) (Segment 11)

Northern Border Pipeline is a major natural gas transportation system that links the Midwestern US with reserves in the Western Canadian Sedimentary Basin. In addition to transporting Canadian sourced supply, Northern Border Pipeline receives and transports natural gas produced in the Williston and Powder River Basins in the United States and synthetic natural gas produced at the Dakota Gasification plant in North Dakota.

Northern Border Capacity By Segment

Northern Border Pipeline Customer Meeting April 13 – 14, 2011, Carefree, AZ Figure A2-14: Northern Border System Capacity Map

While analysis of the Northern Border system indicates little to no available forward-haul capacity from supply sources (without firm transportation) located on the western end of its system, it should be noted, however, that Northern Border and its customers have been successfully selling capacity using supply from in and around Chicago to transport gas on a backhaul basis to power plants further upstream on its system. On the Northern Border system this backhaul is physically accomplished by displacing gas flows on the pipeline as there is no need to physically switch the flow direction of the gas. This type of displacement transaction is

42 a direct result of the new shale plays and their impacts to nominated flows on interstate pipelines. Displacement transactions like these generally require no facility expansions and can be provided on a daily basis. When Northern Border is operating at full capacity and moving gas from west to east, that physical operation actually increases the reliability for these types of backhaul nominations. Northern Border interconnects that are designed to physically flow gas in one direction can have nominations going in the opposite direction as long as the net of all nominations do not exceed the physical capabilities of the meter itself. These types of opportunities will need to be better understood and utilized by power generators. The maximum flowing capacity used was 2.394 Bcf/d (Port Morgan) from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

Northern Border has no embedded demand and 111,254 Dth/d incremental demand from 2 CCs Table A2-21: Northern Border: Base Demand Case Days of Unavailable IT Capacity

43

Northern Border has no embedded units and 86,305 Dth/d incremental CC demand Table A2-22: Northern Border High Demand Case Days of Unavailable IT Capacity

44 A2.6 Northern Natural Gas Co. (Segment 12)

Northern Natural Gas Company (Northern) is based in Omaha, Nebraska, and owns and operates an interstate natural gas pipeline extending from the Permian Basin in Texas to the Upper Midwest. The system includes over 14,900 miles of natural gas pipeline; 5.5 billion cubic feet per day (Bcf/d) of Market Area design capacity, 2.0 Bcf/d of Field Area capacity; and 5 natural gas storage facilities with a total firm and operational capacity of 73 Bcf, including 4 Bcf of liquefied natural gas.

Northern Natural Gas Company System Map

NNG Nebraska/Iowa Border

Figure A2-15: Northern Natural Gas System Map

Serving Northern’s Market Area, is 1.7 Bcf/day of capacity from Northern’s Field Area system. In addition, Northern has receipt capability from Rockies Express Pipeline (REX) in Nebraska, NGPL in Iowa, Great Lakes Gas Transmission and Viking Gas Transmission in Minnesota, ANR and Guardian Pipeline in Wisconsin as well as several significant Northern Border receipt points

45 in Minnesota and Iowa. Since 2004, Northern has increased receipt point capacity in its Market Area by 1.2 Bcf/day from Northern Border and Viking interconnects. Northern routinely holds pipeline expansion open seasons based on customer needs and growth requirements. Northern has held 32 expansion open seasons and 57 generally available capacity open seasons since 2007 in the Market Area. Currently, Northern has mainline capacity available into the areas identified by MISO for the facilities in Phase 3. The concern that is Analyses has is about Northern’s capability (in the market area (Zone EF)) to serve the large power MISO- forecasted power generator demands in locations north of Ventura, Iowa and for facilities through Farmington into the Scott County, MN area (Figure A2-15). It is obvious that additional mainline capacity most likely would be required to serve the entirety of the facility requirements for each plant and future plants identified by MISO in these areas.

Figure A2-16: Northern Natural Line Constraints

The maximum flowing capacity used was 1.73 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

46

NNG has 177,713 Dth/d embedded CC and 113,368 Dth/d CT demands and incremental demand of 41,558 Dth/d for one CT and 55,627 Dth/d one CC Table A2-23: Northern Natural Base Demand Case Days of Unavailable IT Capacity

NNG has 305,788 Dth/d embedded CC and 189,820 Dth/d CT demands and incremental demand of 121,281 Dth/d for 2 CTs Table A2-24: Northern Natural High Demand Case Days of Unavailable IT Capacity

Northern will implement an expansion project subject to certain conditions including, but not limited to, securing contractual commitments for incremental firm transportation with rates and terms sufficient to justify the Project economics and receipt of all necessary regulatory approvals. Customers requesting service are responsible for any capacity that may be required on upstream or downstream pipelines to assure their volumes are available for confirmation during the nomination and scheduling process.

47 A2.10 Panhandle Eastern Pipe Line Co (Segment 13)

Panhandle Eastern Pipe Line Company (PEPL) operates a 6,500-mile pipeline system with access to diverse supply sources and delivers natural gas to Midwest and East Coast markets. Tie-ins to Chicago, Dayton and Cincinnati have added to a Midwest customer base that includes some of the nation's largest utility and industrial natural gas users. It is a part of the Southern Union pipeline network, consisting of the affiliated PEPL, Trunkline and Sea Robin transmission systems. PEPL’s transmission system consists of four large diameter pipelines in parallel (looped) extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, OklahPanhandleoma and Kansas through Eastern Missouri, Illinois, Pipe Indiana, Line and Ohio Company and into Michigan. Map

Panhandle Missouri/IIlinois Border

Figure A2-17: PEPL System Map

The maximum flowing capacity used was 1.5 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

48

PEPL has 65,718Dth/d embedded demand for one CC and 39,268 Dth/d CT and has incremental demand of 41,558 Dth/d for one CT Table A2-25: PEPL Base Demand Case Days of Unavailable IT Capacity

PEPL has 108,468 Dth/d embedded demand for one CC and 50,489 Dth/d and incremental demand of 121,281Dth/d for two CTs Table A2-26: PEPL High Demand Case Days of Unavailable IT Capacity

49 A2.11 Rockies Express Pipeline (REX) (Segment 14)

The Rockies Express Pipeline was built in three (3) segments: The Cheyenne Hub, REX West and REX East. The 850 mile section from Meeker to the Cheyenne Hub was placed in service in February 2007. REX West, from the Cheyenne Hub to Audrain County, Missouri was completed in May 2008 and REX East, from Audrain County, Missouri, to the Lebanon Hub in Warren County, Ohio was completed in November 2009. REX has a capacity of 1.8 Bcf/d of gas. As REX was built eastward, the capacity patterns of several south-to-north pipelines had noticeable changes in capacity and throughput, most notable in this analysis include ANR, NGPL - Amarillo Line, NNG, Trunkline and Texas Gas.

Rockies Express Missouri/Illinois Border

Figure A2-18: REX Gas System Map

While there is acknowledgement of the efforts to flow Marcellus gas west on REX, the pipeline is still characterized as creating significant west-to-east flow. In fact, activity through REX is extremely low, as this $2 billion pipeline was built based on old assumptions that changed radically before it even went into service. But this is changing dramatically as this report is being written. REX will enhance its performance as a 1.8 Bcf/day “header” or “bottle” that traverses the heart of the Midwest region and will provide opportunities to end-users that were not envisioned when REX was on the drawing board. The degree of flexibility and optionality that REX will eventually add to the region has not yet been truly assessed and should greatly 50 enhance the very positive findings of this report. As a supply header REX offers on the enormous flexibility because it is so underutilized recently, but this is changing swiftly.

REX previously was used to ship natural gas from Colorado and Wyoming to Ohio. But the shale gas production growth in Ohio and Pennsylvania has reduced the demand for natural gas shipped east in the pipeline. REX is one of the largest natural gas pipelines built in the US and due to the shale gas production growth throughout the US, it will most likely be flowing bi- directionally to transport natural gas from Ohio to the Midwest and to the West. The new facilities are expected to add significant natural gas supply to the east end of REX for transport to points west or east via connecting pipelines.

An initial pipeline partner was Kinder Morgan Energy Partners, a major pipeline company. It was forced to divest itself of certain assets in the Rocky Mountains after it acquired El Paso Corp. In August 2012, Kinder Morgan sold a number of pipelines and facilities to privately held Tallgrass Energy Partners LP for $1.8 billion in cash and the assumption of Kinder Morgan’s proportionate amount of debt on REX. The total value of the deal was $3.3 billion. It is a joint venture of a subsidiary of Tallgrass Development LP (50 percent share); Sempra U.S. Gas & Power (25 percent share), a subsidiary of Sempra Energy; and a subsidiary of Phillips 66 (25 percent share). A wholly owned subsidiary of Tallgrass Development operates the pipeline.

Tallgrass, as the 50 percent owner and operator of REX, has stated that believes that it and its shippers have a common understanding of the future for transporting gas out of the Appalachian Basin. REX is a high-capacity, long-haul transmission pipeline that spans from Colorado-Wyoming to Ohio and can and will act as the nation’s northern-most east-to-west and west-to-east corridor for natural gas distribution.

Because of the changes that REX is undergoing and in the way it operates and its interconnectivity with other pipelines, the MBA results are inconclusive from a forward-haul perspective. Even before the idea that REX may flow bi-directionally, REX was becoming underutilized because of the shale developments. Capacity is available and opportunities are developing now to meet the needs of power generators. REX has been and will be a game- changer with regards to Midwest gas pipeline capacity and supply opportunities for power generators and other end-users.

51 The maximum flowing capacity used for was 1.8 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

REX has no embedded REX has CT 4 (41,558 Dth/d) incremental Table A2-27: REX Base Demand Case Days of Unavailable IT Capacity

REX has no embedded and one CT with 60,640 Dth/d incremental demand Table A2-28: REX High Demand Case Days of Unavailable IT Capacity

52 A2.12 Texas Gas Transmission Co. (Segment 15)

Texas Gas Transmission, LLC ("Texas Gas") is an interstate pipeline that moves natural gas from Gulf Coast, North Louisiana, East Texas and Arkansas supply areas to direct served markets in the South, Midwest and to indirect markets in the Northeast via interconnections with third- party pipelines. It originates in the Louisiana Gulf Coast area and in East Texas and runs north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and into Ohio, with smaller diameter lines extending into Illinois.

Texas Gas – Lateral Indiana/Kentucky Border

Figure A2-19: Texas Gas Transmission System Map

The Texas Gas system is composed of:

 Approximately 6,110 miles of pipeline, having a peak-day delivery capacity of approximately 4.4 billion cubic feet (Bcf) per day which includes deliveries to pipeline interconnects in South Louisiana;

 Nine natural gas storage fields located in Indiana and Kentucky, having aggregate storage capacity of approximately 180.0 Bcf of gas, of which approximately 84.0 Bcf is designated as working gas. 53 Texas Gas’s direct market area encompasses eight states in the southern and Midwestern United States and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Evansville and Indianapolis, Indiana metropolitan areas. Texas gas also has indirect market access to the Northeast through interconnections with unaffiliated pipelines. The principal sources of supply for Texas Gas are: (1) Regional supply hubs and market centers: offshore Louisiana; Perryville, Louisiana; Henry Hub; Agua Dulce; and Carthage, Texas; (2) Wellhead supplies: Fayetteville Shale in Arkansas, East Texas, northern and southern Louisiana and Mississippi; and (3) Canadian natural gas through a pipeline interconnect with Midwestern Gas Transmission Company at Whitesville, Kentucky.

Figure A2-20: Texas Gas Transmission Capacity Flow Patterns

Texas Gas has a variety of services that provide variable hourly flow rights on both a firm and interruptible basis which allows shippers to contract for the appropriate level of service needed to serve generation facilities. Texas Gas has developed firm services under its SNS and WNS rate schedules designed specifically for the power generation market, providing variable hourly flow rights on a firm basis as well as short notice start-up on a firm basis.

54 Texas Gas currently offers several services designed specifically for the power generation customer which provide variable hourly flow rights, no-notice start-up capabilities and a storage component to manage swings. Texas Gas also offers backhaul services on its mainline system which could be used to serve the MISO facility identified in Phase 3, subject to available capacity. In addition to the 4 standard NAESB cycles, Texas Gas offers 11 additional nomination cycles under Rate Schedule ENS. The ENS rate schedule is available at qualified receipt locations to shippers who have executed a firm transportation or firm no-notice transportation service agreement.

Based on the above flow patterns (Figure A2-18) and the impacts of (1) changes in downstream market area flow patterns (2) large amount of storage in the market area and (3) the aberrant nature of the 2010-2011 winter could possibly overstate of the number of days shown below. Reinforced by the Bentek analysis, Texas Gas has sufficient capacity for additional power generation growth, despite the proposed abandonment of a part of its system for possible re- purposing. The portion of Texas Gas that they are seeking to abandon is currently underutilized by its interstate natural gas customers and is projected to remain underutilized for the foreseeable future. The purpose of the proposed abandonment is to allow Texas Gas to deactivate, or remove from natural gas transportation service, pipeline facilities that are significantly underutilized by Texas Gas customers and therefore not needed to meet Texas Gas’ current commitments of anticipated future transportation needs of its current firm transportation customers.

The facilities to be removed from natural gas service and placed into natural gas liquids (NGL) transportation service consist primarily of one of three parallel pipelines that comprise a portion of Texas Gas’ mainline facilities between Hardinsburg, Kentucky, and Eunice, Louisiana. Only one 26-inch mainline facility is affected, and no service laterals or storage facilities are affected.

For the reasons above, the MBA results below do not fully capture the operational capacity capability of the Texas Gas Transmission system and understate capacity on Texas Gas.

55 The maximum flowing capacity used was .588 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

Texas Gas has 7,215 Dth/d embedded demand for one CT and has no incremental demands Table A2-29: TGT Base Demand Case Days of Unavailable IT Capacity

Texas Gas has 9,628 Dth/d embedded foe one CT and incremental demand of 60,640 Dth/d) for one CT Table A2-30: TGT High Demand Case Days of Unavailable IT Capacity

56 A2.13 Trunkline Gas Company (Segment 16)

Trunkline Gas Company operates a 3,059-mile pipeline system with access to Gulf Coast supply sources which can deliver 1.5 Bcf/d of natural gas to Midwest and East Coast markets.

Trunkline Gas Company System Map

Trunkline Illinois/Kentucky Border

Figure A2-21: Trunkline Gas Company System Map

In many ways, like Texas Gas Transmission, Trunkline has been impacted by the changes in Eastern Interconnect natural gas flow patterns (FigureA2-20) due to (1) changes in downstream market area flow patterns (2) large amount of storage in the market area and (3) the aberrant nature of the 2010-2011 winter. Together, these 3 developments could cause the forward-haul MBA perspective to possibly overstate of the number of days that Trunkline has insufficient capacity. Despite the proposed abandonment of a part of its system and possible re-purposing, the portion of Texas Gas for abandonment is currently underutilized by its interstate natural gas customers and is projected to remain underutilized for the foreseeable future.

57

Figure A2-22: Trunkline Capacity Flow Patterns

In July 2012, Trunkline filed an application with FERC to seeking authority to abandon certain looped segments of its Mainline and certain compression facilities. This segment of Mainline piping and associated compression facilities are currently underutilized. The abandoned pipeline segments would be transferred to an affiliate of Trunkline for conversion to oil transmission service. Specifically, Trunkline is requesting authorization to abandon approximately 770 miles of 24-inch and 30-inch Mainline pipeline located in Texas, Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Illinois. In addition, Trunkline would abandon approximately 15,850 HP of compression facilities. Throughout the path of the abandonment, Trunkline will maintain natural gas service on a larger diameter, parallel segment of Mainline pipeline. As a result, according to Trunkline, the proposed abandonment of Trunkline’s Mainline and compression facilities will have no adverse effect on its customers' firm service requirements and will not affect Trunkline’s continuing ability to meet all of its existing firm service obligations.5

5 Per Trunkline FERC filings, entire paragraph.. 58 Nonetheless, the remaining looped pipelines will likely have sufficient capacity in the MISO region to serve future generation and other demands through interconnections with REX and other Northeast expansion projects.

The maximum flowing capacity used was 1.4 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

Trunkline has 26,952 Dth/d embedded CT demand and 121,218 Dth/d incremental demand from 2 CTs. Table A2-31: Trunkline Base Demand Case Days of Unavailable IT Capacity

Trunkline has 47,112 Dth/d embedded CT demand and 121,281 Dth/d Incremental demand from 2 CTs Table A2-32: Trunkline High Demand Case Days of Unavailable IT Capacity 59 A2.14 Viking Gas Transmission (Segment 17)

Viking connects with major pipeline systems (TransCanada, Northern Natural, Great Lakes Transmission, and ANR), allowing it to serve strategic markets in North Dakota, Minnesota, and Wisconsin. The company was incorporated in 1988 and is based in Tulsa, Oklahoma. ONEOK Partners GP, L.L.C., serves as the operator of the Viking Gas Transmission system. Viking Gas Transmission Company receives Canadian natural gas at the same Manitoba/Minnesota border point as Great Lakes Transmission Company (Noyes, Minnesota), but its volumes are delivered and consumed entirely within the United States with deliveries to eastern North Dakota, Minnesota, and central Wisconsin.

Viking Gas Transmission Company System Map

Viking Canadian Border

Figure A2-23: Viking System Map

The maximum flowing capacity used was .533 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

60

Viking has 1,455 Dth/d embedded CT demand and no incremental demand Table A2-33: Viking Base Demand Case Days of Unavailable IT Capacity

Viking has 1,463 Dth/d embedded CT demand and no incremental demand Table A2-34: Viking High Demand Case Days of Unavailable IT Capacity

61 A2.15 WBI Energy Transmission (Segment 18)

WBI Energy Transmission (formerly known as Williston Basin Interstate Pipeline Company) owns and operates more than 3,700 miles of transmission, gathering and storage lines and owns or leases and operates 33 compressor stations in Montana, North Dakota, South Dakota and Wyoming. The total system is comprised of 3,439 Miles of transmission pipeline; 218 Miles of gathering lines and 143 miles of storage pipeline. Three underground storage fields in Montana and Wyoming with a total capacity of 353 Bcf of which working gas capacity is 193 Bcf serve to enhance system deliverability. WBI Energy Transmission provides transportation, gathering and storage services to local distribution companies, producers, natural gas marketers and others. WBI Energy Transmission's system is located near five natural gas producing basins, making natural gas supplies available to the company's transportation and storage customers. The system has 12 interconnecting points with other pipelines, allowing for the receipt and/or delivery of natural gas to and from other Williston Basin Interstate Pipeline regions of the country and from Canada.

Williston Basin Montana/North Dakota Border

Figure A2-24: WBI Energy System Map

The maximum flowing capacity used was .248 Bcf/d from which was subtracted the actual flowing volumes plus embedded and incremental volumes to determine the number of days in the season in which non-firm capacity would most likely be not have been available.

62

WBI has 3,076 Dth/d CT embedded demand and an incremental 55,627 Dth/d demand from one CC Table A2-35: WBI Base Demand Case Days of Unavailable IT Capacity

WBI Energy has 9,445 Dth CT embedded demand and an incremental 60,640 Dth/d demand from one CT Table A2-36: WBI High Demand Case Days of Unavailable IT Capacity

WBI Energy’s Proposed Dakota Pipeline WBI Energy has proposed the Dakota Pipeline that will add to its system approximately 400 miles of pipeline with approximately 400,000 Mcf per day of capacity expandable to over 500,000 Mcf per day and operating at pressures up to 1,450 psi. If this project is completed it will add a tremendous amount of capacity and flow diversity to the MISO region. It is proposed to interconnect with WBI Energy Transmissions, Northern Border, Alliance Pipeline and end

63 with an interconnection with Viking Gas Transmission. This proposed pipeline would be a tremendous benefit to enhancing pipeline capacity into the MISO region. It would enhance reliability and considerably expand supply, capacity and delivery options to power generators in the MISO region. It would enhance the reticulated pipeline flow benefits that are already occurring and increase supply opportunities and probably reduce overall delivery costs with increased access to storage and Bakken, Rockies and Canadian production, that, in turn, would lower costs overall into the MISO Midwest.

Figure A2-25: Dakota Pipeline System Map

64

A2.16 Contributions and Comments by the Natural Gas Industry and EPSA to the Phase I and II Analysis

In retrospect due to developments in today’s electric power and natural gas markets and the efforts by both industries to address interdependency issues, a revisit to the comments, some practical, some prophetic, will hopefully expand the dialogue between the two industries to address the electric power industry’s (hopefully waning) concerns about today’s new natural gas market environment. We believe these contributions must be considered in conjunction with the findings of this Phase III Analysis.

In Phase II, the Report clearly identified and qualified, on the pages referenced below, many of the issues that were later critically assessed by the pipeline community and the EPSA as follows:

P. 7) “The (Phase I and II) Analyses were not intended to be a detailed market-area engineering analysis that uses sophisticated flow modeling and other types of transient flow analyses that analyzes each detailed market area pipeline segment’s operational and storage inter- dependencies down to the detailed pipe sizes and pressures at the power plant delivery point levels as this would be beyond the scope of the Analysis and would require access to the pipelines’ proprietary data and information. A detailed forward looking market area analysis is beyond the scope of this Analysis as it would require access to the pipelines’ proprietary data and information.”

P. 8) “Pipeline capacity is affected by a number of operational capabilities and factors that were addressed extensively in the initial February 22, 2012 Analysis, “Gas and Electric Infrastructure Interdependency Analysis” (“Phase I Report”). These include shale gas developments impacting pipeline flow patterns, infrastructure build-out, backhaul opportunities, structural contractual issues, pipeline utilization and utilization rates, integration of market-area storage capacity, market-area capacity versus mainline capacity, secondary capacity markets, asset management arrangements and other contracting options and finally discretionary pipeline operations and flexibilities. “

P.9) “From a modeling perspective, the Analyses are based on what may be more accurately described as a “Modified-Backcast Scenario Technique” analytical approach based the pipelines’ forward-haul main line capacity using location-specific actual historical flow data into the MISO region. The Analyses also not intended to be detailed forward-looking market area analyses since that would also be beyond the scope of the Analyses as it would require access to the pipelines’ proprietary data and information. All pipeline capacity modeling has limitations of unknown impacts of potential future backhaul and short haul capacity to certain power plant locations, future available capacity due to contract “turn-backs” and the future impacts of shale gas supply development on the flow patterns into and on the pipelines.”

P.9): “This Analysis is not intended to be a detailed market-area engineering analysis that uses sophisticated flow modeling and other types of transient flow analyses that analyzes each

65 detailed market area pipeline segment’s operational inter-dependencies down to the detailed pipe sizes and pressures at the power plant delivery point levels as it would require access to the pipelines’ proprietary data and information.”

Ps. 20 – 21): However, as explained above, the measurement locations are into the market area and these indicators may not fully capture the unique operating capabilities of each specific pipeline within their market areas to creatively make use of storage and other operational capabilities. One case in point, for example, might be ANR. The analysis observed that at 2 of 3 pipeline segment’s measurement points into the ANR market area, there are indications of a large number insufficient capacity days to meet the requirements under the Embedded or Maximum Cases. However, behind these measurement points and within the market area, ANR has a “grid-like” system with considerable storage capabilities that were not analyzed at a micro-level at specific units’ locations. NGPL and NNG are also considered to be market area “grid” systems with their own unique market area operational considerations.

P. 22): It is recognized that these capacity insufficiency indications may not fully capture the unique operating capabilities of each specific pipeline within their market areas to creatively make use of storage, possible backhaul and other operational capabilities. A market area analysis of that nature is beyond the scope of this Analysis as it would require access to the pipelines’ proprietary data and information. (p22)

P. 60): The Analyses were not intended to be a detailed market-area engineering analysis that uses sophisticated flow modeling and other types of transient flow analyses that analyzes each detailed market area pipeline segment’s operational and storage inter-dependencies down to the detailed pipe sizes and pressures at the power plant delivery point levels as this would be beyond the scope of the Analysis and would require access to the pipelines’ proprietary data and information.

P. 67): In general terms, there is no consensus on a single classification or a guide to apply the most suitable future study approaches. Beyond any kind of classifications or definitions, the user’s worldview, perceptions and aims for the study are the most important thing when a future study is going to be developed. Scenario typologies and techniques are essential to answer user’s questions on future.”

66 The following are welcomed comments by energy industry organizations and pipelines to the Phase I and II Analysis. The Midcontinent Independent Transmission System Operator (“the MISO”) made available the May 30, 2012 draft report, “Embedded Natural Gas-Fired Electric Power Generation Infrastructure Analysis: An Analysis of Daily Pipeline Capacity Availability” (“Phase II Report”) to various organizations and companies for their review and comment. Ten organizations responded with comments on the draft report.6

The comments varied widely, from minor technical clarifications to extensive perspectives on factors that impact pipeline capacity. However, many of the comments pointed out that pipeline capacity is affected by a number of operational capabilities and factors that were addressed extensively in the initial February 22, 2012 “Gas and Electric Infrastructure Interdependency Analysis” (“Phase I Report”). These include shale gas developments impacting pipeline flow patterns, infrastructure build-out, backhaul opportunities, structural contractual issues, pipeline utilization and utilization rates, integration of market-area storage capacity, market-area capacity versus mainline capacity, secondary capacity markets, asset management arrangements and other contracting options and finally discretionary pipeline operations and flexibilities. In this regard, the final “Embedded Natural Gas-Fired Electric Power Generation Infrastructure Analysis: An Analysis of Daily Pipeline Capacity Availability” (“Phase II Report”), should more clearly emphasize that consideration was given to these factors. However, the quantification of these factors, as previously explained, are beyond the scope of both Analyses.

From a modeling perspective, the Analyses are based on what may be more accurately described as a “Modified-Backcast Scenario Technique” analytical approach based the pipelines’ forward-haul main line capacity using location-specific actual historical flow data into the MISO region. The Analyses were not intended to be a detailed market-area engineering analysis that uses sophisticated flow modeling and other types of transient flow analyses that analyzes each detailed market area pipeline segment’s operational and storage inter- dependencies down to the detailed pipe sizes and pressures at the power plant delivery point levels as this would be beyond the scope of the Analysis and would require access to the pipelines’ proprietary data and information.

Nor were the Analyses intended to be detailed forward-looking market area analyses since that would also be beyond the scope of the Analyses as it would require access to the pipelines’ proprietary data and information. Forward-looking pipeline capacity modeling has limitations of unknown impacts of potential future backhaul and short haul capacity to certain power plant locations, future available capacity due to contract “turn-backs” and the future impacts of shale gas supply development on the flow patterns into and on the pipelines.

The following is an attempt to summarize the key areas of commonality among the respondents’ comments, without regard to an order of importance.

6 In alphabetical order: American Gas Association (AGA), Electric Producers Supply Association (EPSA); Mississippi River Transmission (MRT) an affiliate of CenterPoint Energy; MidAmerican Holdings - parent company of Northern Natural Gas Company; Natural Gas Pipeline of America or “NGPL”, an affiliate of Kinder Morgan; ONEOK Partners, LP; Panhandle Eastern Pipe Line and affiliate Trunkline Gas Company; Spectra Energy Corp representing affiliate Texas Eastern Transmission, LP; Texas Gas Transmission; and TransCanada PipeLines Limited.

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Key comments groups

1. The analysis needs to be considered just the first step in a more detailed analysis that reflects the full capabilities of the pipelines that overlay MISO’s territory, before determining the ultimate potential need for additional pipeline infrastructure.

2. MISO and the pipeline industry need to address how best to ensure that power generators receive the service they need from pipelines, particularly in the area of non- uniform takes throughout the day. Fluctuating loads, or “swings” and hourly “swings” complicate capacity issues and require the use of compression, line pack and/or storage to manage effectively.

3. Backhaul and short haul capacity of pipelines continue to evolve to serve power plant locations. Each pipeline will have different capacities than those long haul capacities reflected in the current study.

4. The impact of future changes in supply development on the flow patterns of pipelines may well allow pipelines to serve incremental power generation load with no or minimal investment in infrastructure.

5. The amount of natural gas pipeline infrastructure available to meet electric reliability needs is and will be directly tied to the electric industry’s levels of firm contractual commitment. Once the electric industry determines the amount of natural gas capacity it needs to support the desired level of electric reliability, the electric industry must determine which electric market participants should contract and pay for the pipeline transportation capacity necessary to achieve that desired level of electric reliability. And the electric market pricing mechanisms must allow for the recovery of costs for subscribing for pipeline capacity and natural gas supplies on a firm basis.

6. Issues regarding pipeline operations, such as backhaul operations, the impacts of changing pipeline flows, the role of gas storage, as well as new arrangements developed to serve new generation need to be discussed and understood by power generators.

7. There is a robust secondary market for firm capacity (FT) at variable prices reflecting shifting value during peak times, this product is timely, available and meets the needs of many generators.

8. In MISO, contracting behavior will face new challenges related to recognizing the needs for firm service, participation in supporting pipeline expansions and consideration of natural gas infrastructure needs in reliability and resource adequacy planning.

9. While the data is generally proprietary, not making a distinction between firm and interruptible flowing gas on the pipes, and not quantifying the impact of market area gas storage beyond the “into MISO” measurement locations in a pipeline’s overall ability

68 to serve existing and future gas load, undeservedly labels the pipelines as inadequate to serve this load.

10. There is a need for MISO to institute a formal planning mechanism that strengthens the coordination efforts of the gas and electric power infrastructure. Electric and natural gas stakeholders must make a concerted effort to educate themselves and each other about how these industries work and interrelate.

11. There are planning and infrastructure cost benefits to both the natural gas and electric sectors through the cooperative use of forward-looking pipeline capacity and/or econometric supply/demand analyses or related gas supply and capacity modeling with MISO’s planning models to assess varying degrees of pipeline capacity availability.

The following is an attempt to summarize in alphabetical order the specific respondents’ comments.

American Gas Association (AGA)

The AGA’s main comment is that the draft report should recognize hourly swings as an independent cause of pipeline capacity constraints: the Phase II study should adequately recognize that generators.’ use of gas may vary over the course of the day, potentially exacerbating capacity issues on a pipeline. The AGA commented that the report does not characterize this issue adequately and an annotation/disclosure/footnote on this issue should be included. The AGA also attached their comments filed at FERC in response to questions noticed in Docket No. AD12-12-000, a summary talking points version of that document and a Policy Framework which we presented at meetings with FERC commissioners and staff earlier this year to kick start the conversation on their members’ behalf.

Electric Producers Supply Association (EPSA)

The EPSA points out that there is a robust secondary market for firm capacity (FT) at variable prices reflecting shifting value during peak times, this product is timely, available and meets the needs of many generators. Currently, the pipeline industry is able to meet those peak hour demands in a reliable manner with existing tariff-based service agreements. Often these peak hour needs are met with the flexibility provided to the pipelines by gas storage facilities. In this regard, the EPSA comments that the draft report should recognize these pipeline capabilities. The EPSA recognizes issues regarding pipeline operations, such as backhaul operations, the impacts of changing pipeline flows, the role of gas storage, as well as new arrangements developed to serve new generation clients that were acknowledged in the “Phase I Report”, the February 22, 2012 “Gas and Electric Infrastructure Interdependency Analysis”.

Finally, EPSA notes that the study’s findings highlight the need for MISO to institute a formal planning mechanism that strengthens the coordination efforts of the gas and electric power infrastructure.

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Mississippi River Transmission (MRT) an affiliate of CenterPoint Energy (Enable)

MRT correctly points out that the draft report appears to recognize only MRT’s East Line capacity, since this is the only part of the MRT system that flows into the MISO region based on actual historic capacity as measured at the Illinois-Missouri border. MRT also acknowledges that on peak days in winter, MRT’s capacity is committed to serve its firm Customers and would therefore be insufficient.

Lastly, MRT submits that another area that MISO and the pipeline industry need to address is how best to ensure that power generators receive the service they need from pipelines, particularly in the area of non-uniform takes throughout the day. Fluctuating loads or “swings” complicate capacity issues and require the use of compression, line pack and/or storage to manage effectively.

MidAmerican Holdings - parent company of Northern Natural Gas Company

MidAmerica’s comments were limited to their comments filed at FERC in response to questions noticed in Docket No. AD12-12-000 “Coordination between Natural Gas and Electricity Markets” and did not specifically comment on the Analysis.

Natural Gas Pipeline of America or “NGPL”, an affiliate of Kinder Morgan

According the NGPL, “The Gas – Electric Interdependency Analysis work that Greg Peters, (MISO consultant) prepared does provide a good starting point in understanding the Natural Gas industry. While we have not been able to validate the detailed workings of the model used, the second phase, “An Analysis of Daily Pipeline Capacity Availability” was a good attempt at an initial “screen” and high level analysis to gauge the level of available pipeline capacity given MISO projection on embedded and proposed natural gas generation projects.”

NGPL continued, “This analysis needs to be considered just the first step in a more detailed analysis that reflects the full capabilities of the pipelines that overlay MISO’s territory, before determining the ultimate potential need for additional pipeline infrastructure. Specifically, important factors to be considered before drawing any conclusions include:

 NGPL’s pipeline system is capable of moving natural gas in multiple directions, in addition to its traditional long haul forward capacities reflected in the current report. Besides NGPL’s mainline forward haul capacities, NGPL’s significant market area storage deliverability should be noted in the report.

 Backhaul and short haul capacity of pipelines to serve power plant locations. Each pipeline will have different capacities than those long haul capacities reflected in the

70 current study. These are very likely to reduce the amount of new infrastructure required.

 Future available capacity on each pipeline: while the “backcasting” technique used in the study gives one picture of capacity availability, it does not give proper consideration to the changing requirements of current pipeline customers that has increased the capacity availability from historical levels.

 The impact of future changes in supply development on the flow patterns of pipelines. This may well allow pipelines to serve incremental power generation load with no or minimal investment in infrastructure.”

“NGPL believes that if MISO wants to undertake a broad study of available pipeline capacity they should investigate utilizing a forward looking pipeline capacity model, such as the GPCM Natural Gas Market Forecasting System that RBAC developed or some other comparable tool. Additionally we would strongly encourage MISO to work with each pipeline individually to help further understand the dynamics of each pipeline and the capabilities of each system. The capabilities of each system are so varied, individual discussions are essential to ensuring MISO’s needs are met and that the pipelines can pursue services or infrastructure that is needed. We firmly believe that the results of a more detailed and focused analysis will lead to the conclusion by all parties that the gas pipeline industry is very capable of meeting the future needs of MISO, and likely at a cost substantially less than reflected in the current, high-level study”.

ONEOK Partners, LP

ONEOK had a few minor comments to the draft document that related to assets owned by ONEOK Partners. With respect to Guardian Pipeline, Northern Border should also be listed as a major supply source and with respect to Wabash Storage on the Midwestern Gas Transmission, the targeted in-service date should be listed as summer of 2014, versus “early 2013” as the project has had some delays.

Panhandle Eastern Pipe Line and affiliate Trunkline Gas Company

Panhandle commented that no distinction was made between how much of that gas is flowing under firm contracts, and how much is flowing as interruptible transportation. Panhandle recognized that this degree of detail is generally unavailable for public consumption. However, their point is that if pipelines had the choice to displace lower-priced interruptible transportation with “sufficiently-priced” firm transportation contracts (e.g., to serve gas-fired generation), then they almost certainly would do so.

Panhandle further commented that it can appreciate the fact that the intent of the study is to merely provide a general indication as to whether sufficient firm transportation capacity exists to serve the “embedded” generation fleet, and any additional gas-fired generation that might

71 replace retired coal units. “However, not making a distinction between firm and interruptible flowing gas on the pipes, and not accounting for the role that gas storage plays in a pipeline’s overall ability to serve existing and future gas load, undeservedly labels the pipelines as inadequate to serve this load. Subsequently, the conclusions reached in your study’s “Daily Insufficiency Analysis”, we believe, are generally overstated.”

Texas Eastern and its parent company, Spectra Energy Corp

Spectra began, “While time does not allow us to evaluate the specific technical conclusions in the MISO Infrastructure Study, Texas Eastern and Spectra Energy are not surprised with your conclusions that the current natural gas infrastructure will be insufficient for future gas-fired electric generation needs in the MISO region, because the electric generators historically have not contracted for the firm transportation service required to support infrastructure development.”

Spectra continued that, “The amount of natural gas pipeline infrastructure available to meet electric reliability needs is and will be directly tied to the electric industry’s levels of firm contractual commitment. Once the electric industry determines the amount of natural gas capacity it needs to support the desired level of electric reliability, the electric industry must determine which electric market participants should contract and pay for the pipeline transportation capacity necessary to achieve that desired level of electric reliability. And the electric market pricing mechanisms must allow for the recovery of costs for subscribing for pipeline capacity and natural gas supplies on a firm basis.”

“Additionally, capital investment by pipelines, and Federal Energy Regulatory Commission (“Commission”) approval to construct pipelines, must be supported by revenue certainty through firm service agreements. When the electric industry identifies its infrastructure needs and executes the firm transportation service commitments that will support the regulatory and financial obligations that must be met by the natural gas industry, we will build that natural gas pipeline infrastructure.

“Texas Eastern and Spectra Energy are encouraged by MISO’s recommendation that “[r]egulators should consider clarifying and encouraging cost-recovery incentives” regarding infrastructure development. Wholesale electric market design—which rewards generators with the lowest marginal costs—can disincentivize generators to sign up for firm transportation. As utilization of natural gas for electric generation continues to increase, markets and pricing mechanisms should be designed to encourage firm transportation contracting, rewarding reliability that will yield long-term benefits to energy consumers and the economy.”

Texas Eastern and Spectra Energy emphasize that the natural gas pipeline industry can serve the growing use of natural gas as a fuel for the region’s energy needs provided the electric industry determines the amount of reliability it desires and contracts accordingly.

72 Texas Gas Transmission (TGT)

According to TGT, the Daily Insufficiency Analysis (DIA) looks appropriate. Note, Texas Gas approved firm transportation requests to satisfy power generation load during the Winter 2010 – 2011 period ensuring reliable service for the balance of the winter.

Recognizing the report was not based on proprietary information from individual pipelines, TGT offered some general comments regarding the increased power load Texas Gas has recently served in the Midwest. The power load increase Texas Gas experienced during the last year of the historic period utilized in the MISO study (04/01/05 to 10/31/11) has continued. “Texas Gas has been actively working with power generators to increase their market share for both current and future needs. Texas Gas has been able to accomplish increased power plant deliveries without incremental mainline infrastructure due to many of the flow factors mentioned in the report related to the dynamics of shale supply and contractual changes. Texas Gas anticipates their volumetric contribution to meeting the needs of power generators will be greater when future historical information is compiled”.

TransCanada PipeLines Limited.

TransCanada fundamentally disagrees with the use of the “modified backcast scenario technique” methodology used in the Phase I and II Analyses and recommends an prospective- looking econometric supply/demand analysis that assesses pipeline capacity availability under varying degrees of growth in gas-fired power capacity at various implementation growth speeds (near-term and long-term).

In addition, TransCanada made the following comments about gas and electricity interdependency issues:

 There is ample natural gas pipeline and infrastructure in the MISO region to meet the needs of existing customers;

 New supplies and pipeline infrastructure have provided increased flexibility;

 Market forces continue to impact the changes in contracting levels;

 Electric and natural gas stakeholders must make a concerted effort to educate themselves and each other about how these industries work and interrelate;

 The natural gas pipeline industry has demonstrated its ability to meet build-out needs in a timely manner;

 In MISO contracting behavior will face new challenges related to recognizing the needs for firm service, participation in supporting pipeline expansions and consideration of natural gas infrastructure needs in reliability and resource adequacy planning.

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